UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended DECEMBER 31, 2005
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______ to ________.
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 of (I.R.S. Employer
incorporation or organization) Identification Number)
13710 FNB PARKWAY
OMAHA, NEBRASKA 68154-5200
(Address of principal executive offices) (Zip code)
(402) 492-7300
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
COMMON UNITS NEW YORK STOCK EXCHANGE
(Title of each class) (Name of each exchange
on which registered)
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]
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. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes [ ] No [X]
The 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 as of June 30, 2005, was $2,256,424,496.
The number of common units outstanding as of January 31, 2006, was 46,397,214.
DOCUMENTS INCORPORATED BY REFERENCE
None
NORTHERN BORDER PARTNERS, L.P.
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Page No.
--------
PART I
Item 1. Business
General Development of Business............................ 4
Financial Information About Segments....................... 7
Narrative Description of Business.......................... 7
Environmental and Safety Matters........................... 17
Major Customers............................................ 18
Employees.................................................. 18
Available Information...................................... 19
Item 1A. Risk Factors.................................................. 19
Item 1B. Unresolved Staff Comments..................................... 29
Item 2. Properties.................................................... 29
Item 3. Legal Proceedings............................................. 29
Item 4. Submission of Matters to a Vote of Security Holders........... 30
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities.......... 30
Item 6. Selected Financial Data....................................... 32
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Executive Summary.......................................... 34
Critical Accounting Estimates.............................. 37
Results of Operations...................................... 39
Liquidity and Capital Resources............................ 43
Recent Accounting Pronouncements........................... 49
Forward-Looking Statements................................. 49
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.... 50
Item 8. Financial Statements and Supplementary Data................... 52
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................... 52
Item 9A. Controls and Procedures....................................... 52
Item 9B. Other Information............................................. 54
PART III
Item 10. Directors and Executive Officers of the Registrant............ 54
Item 11. Executive Compensation........................................ 59
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................. 65
Item 13. Certain Relationships and Related Transactions................ 66
Item 14. Principal Accounting Fees and Services........................ 69
PART IV
Item 15. Exhibits and Financial Statement Schedules.................... 69
2
GLOSSARY
The abbreviations, acronyms, and industry terminology used in this annual report
are defined as follows:
Bcf/d......................... Billion cubic feet per day
Bear Paw Energy............... Bear Paw Energy, LLC
Bighorn Gas Gathering......... Bighorn Gas Gathering, L.L.C.
Black Mesa.................... Black Mesa Pipeline, Inc.
Border Midstream.............. Border Midstream Services, Ltd.
Btu/cf........................ British thermal units per cubic feet
Cantera....................... Cantera Natural Gas, LLC (formerly CMS Field
Services, Inc)
CCE Holdings.................. CCE Holdings, LLC, a Southern Union Company and
GE Commercial Finance Energy Financial joint
venture
Crestone Energy............... Crestone Energy Ventures, L.L.C.
Crestone Gathering............ Crestone Gathering Services, L.L.C., a
wholly-owned subsidiary of Crestone Energy
Design capacity............... Pipeline capacity available to transport
natural gas based on system facilities and
design conditions
Enron......................... Enron Corp.
Enron North America........... Enron North America Corp.
EPA........................... Environmental Protection Agency
Exchange Act.................. Securities Exchange Act of 1934
FASB.......................... Financial Accounting Standards Board
FERC.......................... Federal Energy Regulatory Commission
Fort Union Gas Gathering...... Fort Union Gas Gathering, L.L.C.
GAAP.......................... Generally accepted accounting principles
Guardian Pipeline............. Guardian Pipeline, L.L.C.
IRS........................... Internal Revenue Service
Lost Creek Gathering.......... Lost Creek Gathering, L.L.C.
MDth/d........................ Thousand dekatherms per day
Midwestern Gas Transmission... Midwestern Gas Transmission Company
MMBtu......................... Million British thermal units
MMcf/d........................ Million cubic feet per day
NBP Services.................. NBP Services, LLC, a ONEOK subsidiary
NOAA.......................... National Oceanic and Atmospheric Administration
Northern Border Pipeline...... Northern Border Pipeline Company
Northern Plains............... Northern Plains Natural Gas Company, LLC, a
ONEOK subsidiary
Northwest Border.............. Northwest Border Pipeline Company, a subsidiary
of TransCanada
NYSE.......................... New York Stock Exchange
ONEOK......................... ONEOK, Inc.
ONEOK Energy.................. ONEOK Energy Services Company, LP, a ONEOK
subsidiary
Pan Border.................... Pan Border Gas Company, LLC, a ONEOK subsidiary
Partnership................... Northern Border Partners, L.P., Northern Border
Intermediate Limited Partnership and its
subsidiaries
SEC........................... Securities and Exchange Commission
SFAS.......................... Statement of Financial Accounting Standards
TC PipeLines.................. TC PipeLines Intermediate Limited Partnership,
a subsidiary of TC PipeLines, LP
TransCanada................... TransCanada Corporation
Trunk gathering system........ Large diameter pipeline running through a
production area to which smaller individual
gathering systems are connected
U.S........................... United States
Viking Gas Transmission....... Viking Gas Transmission Company
3
The statements in this annual report that are not historical information,
including statements concerning plans and objectives of management for future
operations, economic performance or related assumptions, are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Forward-looking statements
may include words such as "anticipate," "estimate," "expect," "project,"
"intend," "plan," "believe," "should" and other words and terms of similar
meaning. Although we believe that our expectations regarding future events are
based on reasonable assumptions, we can give no assurance that our goals will be
achieved. Important factors that could cause actual results to differ materially
from those in the forward-looking statements are described under Item 1A, "Risk
Factors."
PART I
ITEM 1. BUSINESS
GENERAL DEVELOPMENT OF BUSINESS
In this report, references to "we," "us," "our" or the "Partnership"
collectively refer to Northern Border Partners, L.P., our subsidiary, Northern
Border Intermediate Limited Partnership, and its subsidiaries.
OVERVIEW
Northern Border Partners is a publicly-traded Delaware limited partnership
formed in 1993. Our common units are listed on the NYSE under the trading symbol
"NBP." Our purpose is to acquire, own and manage pipeline and other midstream
energy assets. We are a leading transporter of natural gas imported from Canada
into the U.S. Our operations are conducted through the following three business
segments:
- Interstate Natural Gas Pipeline, which provides natural gas
transportation services;
- Natural Gas Gathering and Processing, which gathers, processes and
compresses natural gas, and fractionates natural gas liquids; and
- Coal Slurry Pipeline, which transports crushed coal suspended in
water.
PARTNERSHIP STRUCTURE
We are managed under the direction of a partnership policy committee (similar to
a corporation's board of directors). The Partnership Policy Committee consists
of three members, one of whom is appointed by each of our general partners. Our
general partners and the general partners of our subsidiary limited partnership,
Northern Border Intermediate Limited Partnership, are Northern Plains, Pan
Border and Northwest Border. Our general partners hold an aggregate 2% general
partner interest. Northern Plains and Pan Border, both subsidiaries of ONEOK,
hold a combined 1.65% general partner interest. In addition, Northern Plains
owns 501,603 of our common units, which represents a 1.06% limited partner
interest. The combined general and limited partner interests held by ONEOK are
2.71%. Northwest Border, a subsidiary of TransCanada, holds a 0.35% general
partner interest.
At December 31, 2005, the voting interests of the Partnership Policy Committee
were as follows:
MEMBER DESIGNATED BY VOTING INTEREST
- -------------------- ---------------
Northern Plains 50%
Pan Border 32.5%
Northwest Border 17.5%
OUR HISTORY
1993 Northern Border Partners is formed by Enron, Panhandle Eastern
Corporation and The Williams Companies, Inc., whose general
partner interests are held by Northern Plains, Pan Border and
Northwest Border, respectively. We hold a 70% general partner
interest in Northern Border Pipeline.
1996 - 1997 We acquire Black Mesa.
4
1998 Enron acquires Pan Border.
1999 - 2000 We acquire joint venture interests in Bighorn Gas Gathering, Fort
Union Gas Gathering and Lost Creek Gathering.
2001 We acquire Midwestern Gas Transmission and Bear Paw Energy.
Our subsidiary, Border Midstream, acquires assets in Canada.
2002 TransCanada acquires Northwest Border.
2003 We acquire Viking Gas Transmission, including a 33-1/3% interest
in Guardian Pipeline.
2004 ONEOK acquires Northern Plains and Pan Border.
Border Midstream sells its remaining Canadian assets.
BUSINESS STRATEGY
Our primary business objectives are to generate stable cash flow sufficient to
pay quarterly cash distributions to our unitholders and to increase our
quarterly cash distribution over time. Our ability to maintain and grow our
distributions to unitholders depends on acquisitions and the growth of our
existing businesses. Our acquisition strategy and business strategy by major
segment are as follows:
Acquisitions - We seek opportunities to expand our existing businesses and
strategically acquire related businesses. We focus on U.S. and Canadian assets
related to energy transportation that will leverage our core competencies,
minimize commodity price risk and provide immediate cash flow. We target
interstate and intrastate natural gas pipelines, natural gas gathering and
processing assets, natural gas liquids pipelines and storage facilities. We
finance our acquisitions and capital expenditures conservatively with a mix of
debt and equity.
Interstate Natural Gas Pipeline - We focus on safe, efficient and reliable
operations and further development of our regulated pipelines. We intend to
continue to provide cost-effective transportation for Canadian natural gas to
the Midwestern U.S. We seek growth of our interstate natural gas pipelines
through incremental projects that access new market areas and are supported by
long-term transportation contracts. Our priorities for Northern Border Pipeline
in 2006 include: marketing its available transportation capacity, actively
processing its current rate case before the FERC and placing the Chicago III
Expansion Project into service. Midwestern Gas Transmission is focused on
receiving regulatory approval for its Eastern Extension project and pursuing the
expansion of existing and the development of new interconnections with other
interstate pipelines to access new markets.
Natural Gas Gathering and Processing - We seek to reduce costs, streamline
operations and increase facility utilization of our wholly-owned natural gas
gathering and processing operations. We pursue growth of our gathering network
through additional well connections, consolidation and acreage dedications, and
facility expansions in new production areas. We also seek to restructure
contracts when they come to term to mitigate commodity price exposure and offset
increased operating costs.
RECENT DEVELOPMENTS
The following is a summary of our significant developments during 2005.
Additional information regarding most of these items may be found elsewhere in
this annual report and in previous reports filed with the SEC.
Northern Border Pipeline Contracting - During 2005, short-term firm service
transportation contracts partially replaced expired contracts and continued to
expose Northern Border Pipeline to seasonal demand. As a result, Northern Border
Pipeline did not sell all of its available capacity and firm transportation
revenue decreased 5% compared with 2004 when the pipeline's transportation
capacity was sold out at maximum rates. To maximize overall revenue, Northern
Border Pipeline discounted transportation rates during certain periods of the
year.
Transition from CCE Holdings to ONEOK - In May 2005, the transition, from CCE
Holdings to ONEOK or us, of various services, including: information technology
services; accounting system usage rights and administrative support; and
payroll, employee benefits and administrative services, was completed.
5
Credit Agreements - In May 2005, we entered into a five-year, $500 million
revolving credit agreement. Northern Border Pipeline entered into a five-year,
$175 million revolving credit agreement. We terminated our previously existing
$275 million credit facility and Northern Border Pipeline terminated its
previously existing $175 million credit facility in conjunction with the
execution of the new agreements.
Bankruptcy Claims - In June 2005, Northern Border Pipeline, Crestone Gathering
and Bear Paw Energy executed term sheets with a third party for the sale of
their bankruptcy claims against Enron and Enron North America. Proceeds from the
sale of the claims were $14.6 million ($11.2 million, net to the Partnership).
Bighorn Gas Gathering Preferred A Settlement - In August 2005, as a result of
the settlement agreement with our partner in Bighorn Gas Gathering related to
cash flow incentives based on well connections to the gathering system, we
recognized $5.4 million of equity earnings that were due to us for 2004 and 2005
through our ownership of preferred A shares.
Interest in Fort Union Gas Gathering - In August 2005, Crestone Energy acquired,
for $5.1 million, an additional 3.7% interest in Fort Union Gas Gathering,
bringing our total interest to 37%.
Northern Border Pipeline Chicago III Expansion Project - In September 2005,
Northern Border Pipeline accepted the FERC's certificate of public convenience
and necessity for the Chicago III Expansion Project. This project will add 130
MMcf/d of transportation capacity on the eastern portion of the pipeline into
the Chicago area. It is estimated that the project will cost approximately $21
million and the target in-service date is April 2006.
Midwestern Gas Transmission Eastern Extension Project - In October 2005, the
FERC issued its Environmental Assessment concluding that the Eastern Extension
Project would not constitute a major federal action significantly affecting the
quality of the environment. The Eastern Extension Project will add 31 miles of
pipeline with 120 MDth/d (approximately 120 MMcf/d) of transportation capacity.
It is estimated that the project will cost approximately $28 million. As a
result of the pending FERC certificate of public convenience and necessity, the
Eastern Extension Project's proposed in-service date of November 2006 will
likely be delayed.
Guardian Pipeline Revenue and Cost Study - In October 2005, Guardian Pipeline
filed a revenue and cost study with the FERC. In conjunction with the filing,
Guardian requested approval of a settlement agreement to re-establish the rates
initially approved by the FERC and to reduce the depreciation rate. In February
2006, the FERC issued an order accepting Guardian's revenue and cost study,
including the settlement agreement reducing its depreciation rate from 3.33% to
2.0%, effective January 1, 2005.
Northern Border Pipeline Rate Case - On November 1, 2005, Northern Border
Pipeline filed a rate case with the FERC as required by the provisions of the
settlement of its last rate case. The rate case filing proposes, among other
things, a 7.8% increase to Northern Border Pipeline's revenue requirement; a
change to its rate design approach with a supply zone and market area utilizing
a fixed rate per dekatherm and a dekatherm-mile rate, respectively; an increase
in the depreciation rate for transmission plant; the implementation of a
short-term rate structure on a prospective basis; and the continued inclusion of
income taxes in the rate calculation. In December 2005, the FERC issued an order
that identified issues that were raised in the proceeding, accepted the proposed
rates but suspended their effectiveness until May 1, 2006, at which time the new
rates will be collected subject to refund until final resolution of the rate
case. The FERC also issued a procedural schedule which set a hearing
commencement date of October 4, 2006, with an initial decision scheduled for
February 2007, unless a settlement of the issues is reached with the FERC and a
majority of Northern Border Pipeline's customers.
Midwestern Gas Transmission Southbound Expansion Project - In November 2005,
Midwestern Gas Transmission completed the Southbound Expansion Project which
increased the pipeline's southbound capacity by 86 MDth/d (approximately 86
MMcf/d).
Shut Down of Black Mesa - On December 31, 2005, Black Mesa's transportation
contract with the coal supplier of the Mohave Generating Station expired and our
coal slurry pipeline operation was shut down as expected.
Proposed Transactions - On February 15, 2006, we announced a series of
transactions that are expected to increase unitholder value and facilitate
additional growth opportunities. In separate transactions, we will sell a 20%
partnership interest in Northern Border Pipeline to TC PipeLines for
approximately $300 million. The price of the
6
20% interest, along with the related share of Northern Border Pipeline's
outstanding debt, totals $420 million. Following completion of the sale, we will
own a 50% interest in Northern Border Pipeline and TC PipeLines will own the
remaining 50% interest. In 2006, Northern Border Pipeline's cash distributions
are expected to be split equally between us and TC PipeLines. In April 2007, an
affiliate of TransCanada will become the operator of Northern Border
Pipeline.
Northern Plains will purchase TransCanada's 0.35% general partner interest in
us, increasing ONEOK's general partner interest to 2.0%. We will acquire ONEOK's
entire gathering and processing, natural gas liquids, and pipelines and storage
segments in a transaction valued at approximately $3 billion. We will pay ONEOK
approximately $1.35 billion in cash and 36.5 million Class B units. Upon
completion of these transactions, ONEOK will own approximately 37.0 million of
our limited partner units, which, when combined with the general partner
interest acquired from TransCanada, will increase its total interest in us to
45.7%. The limited partner units and the related general partner interest
contribution are valued at approximately $1.65 billion.
Closings of the transactions are subject to regulatory approvals and other
conditions, including antitrust clearance from the Federal Trade Commission
under the Hart-Scott-Rodino Act. The transactions are expected to be completed
by April 1, 2006. Additional information about the proposed transactions is
included under Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations-Executive Summary."
FINANCIAL INFORMATION ABOUT SEGMENTS
Financial information about each of our business segments is included in Note 16
of the Consolidated Financial Statements.
NARRATIVE DESCRIPTION OF BUSINESS
INTERSTATE NATURAL GAS PIPELINE SEGMENT
OVERVIEW
The interstate natural gas pipeline segment transports natural gas along 2,320
miles of pipelines with a design capacity of approximately 4.7 Bcf/d. Our
transportation network provides pipeline access to the Midwestern U.S. primarily
from natural gas reserves in the Western Canada Sedimentary Basin, which is
located in the Canadian provinces of Alberta, British Columbia and Saskatchewan.
Our interstate natural gas pipeline segment included the following assets at
December 31, 2005:
2005
AVERAGE
CONTRACTED
SEGMENT SUBSIDIARY OWNERSHIP LENGTH DESIGN CAPACITY CAPACITY
- ------------------ --------- ----------- ----------------------- ----------
Northern Border Pipeline 70% 1,249 miles 2,374 MMcf/d 97%
Midwestern Gas Transmission 100% 350 miles Northbound - 650 MMcf/d 87%
Southbound - 475 MMcf/d(1) 100%
Viking Gas Transmission 100% 578 miles 496 MMcf/d 100%
Guardian Pipeline 33-1/3% 143 miles 750 MMcf/d 98%
(1) Capacity increased by 86 MMcf/d on November 1, 2005.
Operating revenue is derived from transportation contracts at rates that are
stated in our tariffs. Transportation rates are established in a FERC proceeding
known as a rate case. Tariffs specify the maximum rates we can charge our
customers and the general terms and conditions for natural gas transportation
service on our pipelines. During a rate case, a determination is reached by the
FERC, either through a hearing or a settlement, on maximum rates permissible for
interstate natural gas transportation service that include the recovery of our
prudent cost-based investment, operating expenses and a reasonable return for
our investors. Our pipelines' tariffs also allow for services to be provided
under negotiated and discounted rates. Once rates are set in a rate case,
interstate natural gas pipelines are not permitted to increase rates if costs
increase or contract demand decreases, nor are they required to reduce rates
based on cost savings until a new rate case is filed and completed. As a result,
the interstate natural gas pipeline segment's earnings and cash flow depend on
costs incurred, contracted capacity, the volume of gas transported and our
ability to recontract capacity at acceptable rates.
7
Our transportation contracts include specifications regarding the receipt and
delivery of natural gas at points along the pipeline systems. The type of
transportation contract, either firm or interruptible service, determines the
basis by which each customer is charged. Customers with firm service
transportation agreements pay a fee known as a demand charge to reserve pipeline
capacity, regardless of use, for the term of their contracts. Firm service
transportation customers also pay a fee known as a commodity charge that is
based on the volume of natural gas they transport. Customers with interruptible
service transportation agreements may utilize available capacity on our
pipelines after firm service transportation requests are satisfied.
Interruptible service customers are assessed commodity charges only. For the
year ended December 31, 2005, approximately 97% of the interstate natural gas
pipeline segment's revenue was derived from demand charges and the remaining 3%
was attributable to commodity charges.
Operating revenue from the interstate natural gas pipeline segment accounted for
56%, 65% and 68% of our consolidated operating revenue in 2005, 2004 and 2003,
respectively.
Our interest in Northern Border Pipeline represents the largest portion of our
interstate natural gas pipeline assets, earnings and cash flow. For the year
ended December 31, 2005, Northern Border Pipeline accounted for 85% of our
interstate natural gas pipeline segment revenue. Midwestern Gas Transmission and
Viking Gas Transmission accounted for 7% and 8% of the segment's revenue,
respectively. Earnings related to our interest in Guardian Pipeline are reported
in this segment as equity earnings of unconsolidated affiliates.
INTERSTATE PIPELINE SYSTEMS
Northern Border Pipeline - Northern Border Pipeline is a Texas general
partnership that was formed in 1978. We own a 70% general partner interest and
TC PipeLines owns the remaining 30%. Northern Border Pipeline is managed by a
management committee that consists of four members: one representative
designated by each of our three general partners and one representative
designated by TC PipeLines. TC PipeLines is a subsidiary of TC PipeLines, LP, a
publicly-traded partnership. The general partner of TC PipeLines, LP is TC
PipeLines GP, Inc., which is a subsidiary of TransCanada.
On February 15, 2006, we announced a series of transactions that will impact our
relationship with Northern Border Pipeline. Information about the proposed
transactions is included under Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations-Executive Summary."
At December 31, 2005, the voting interests of the Northern Border Management
Committee were as follows:
MEMBER DESIGNATED BY VOTING INTEREST
- -------------------- ---------------
Northern Plains 35%
Pan Border 22.75%
Northwest Border 12.25%
TC PipeLines 30%
Northern Border Pipeline transports natural gas from the Montana-Saskatchewan
border near Port of Morgan, Montana to a terminus near North Hayden, Indiana.
The system consists of 1,249 miles of pipeline with diameters ranging from 30
inches to 42 inches and a design capacity of 2,374 MMcf/d. Along the pipeline
are 16 compressor stations with a total of 499,000 horsepower, measurement
facilities to support the receipt and delivery of gas at various points, four
field offices and a microwave communication system with 50 tower sites.
Construction of Northern Border Pipeline was initially completed in 1982
followed by expansions or extensions in 1991, 1992, 1998 and 2001. Northern
Border Pipeline filed an application for a certificate of public convenience and
necessity with the FERC for the Chicago III Expansion Project in March 2005,
which the FERC issued in September 2005. The Chicago III Expansion Project will
add 130 MMcf/d of transportation capacity from Harper, Iowa to the Chicago
market area with the construction of a new 16,000-horsepower compressor station
in Iowa and minor modifications to two other compressor stations in Iowa and
Illinois. We estimate that the project will cost approximately $21 million and
the target in-service date is April 2006. This expansion is fully subscribed by
four shippers under long-term firm service transportation agreements with terms
ranging from five and one-half years to ten years.
8
Midwestern Gas Transmission - Midwestern Gas Transmission is a bi-directional
system that interconnects with Tennessee Gas Transmission near Portland,
Tennessee and several interstate pipelines near Joliet, Illinois. The system
consists of 350 miles of pipeline with diameters ranging from 24 inches to 30
inches, a northbound capacity of 650 MMcf/d and a southbound capacity of 475
MMcf/d. Along the pipeline are 7 compressor stations with a total of
approximately 68,000 horsepower. We acquired Midwestern Gas Transmission in May
2001.
In June 2005, Midwestern Gas Transmission filed an application requesting a
certificate of public convenience and necessity with the FERC for the Eastern
Extension Project, which is pending approval. The Eastern Extension Project will
add 31 miles of pipeline with 120 MDth/d of transportation capacity from
Portland, Tennessee to planned interconnections with Columbia Gulf Transmission
Company and East Tennessee Pipeline Company. In October 2005, the FERC issued
its Environmental Assessment concluding that the approval of the Eastern
Extension Project, with appropriate mitigating measures, would not constitute a
major federal action significantly affecting the quality of the environment. It
is estimated that the project will cost approximately $28 million. The
additional transportation capacity is fully subscribed by a local distribution
company under a 15-year firm service transportation agreement. As a result of
the pending FERC certificate of public convenience and necessity, the Eastern
Extension Project's proposed in-service date of November 2006 will likely be
delayed.
On November 1, 2005, Midwestern Gas Transmission completed its Southbound
Expansion Project and began service. The fully-subscribed project increased the
pipeline's southbound capacity by 86 MDth/d.
Viking Gas Transmission - Viking Gas Transmission transports natural gas from an
interconnection with TransCanada near Emerson, Manitoba to an interconnection
with ANR Pipeline Company near Marshfield, Wisconsin. The system consists of 578
miles of pipeline with diameters ranging from 3 inches to 24 inches. The
pipeline's design capacity is 496 MMcf/d. Along the pipeline are 8 compressor
stations with a total of approximately 69,000 horsepower. We acquired Viking Gas
Transmission in January 2003.
Guardian Pipeline - Viking Gas Transmission owns a 33-1/3% interest in Guardian
Pipeline. Subsidiaries of Wisconsin Public Service and Wisconsin Energy
Corporation hold the remaining interests. Guardian Pipeline transports natural
gas from Joliet, Illinois to a point west of Milwaukee, Wisconsin. The system
consists of 143 miles of pipeline with a design capacity of 750 MMcf/d. Northern
Plains is the operator of Guardian Pipeline.
On February 7, 2006, Guardian Pipeline announced that it signed precedent
agreements with two major Wisconsin utility companies to expand the existing
pipeline system in eastern Wisconsin. The proposed project will extend the
pipeline approximately 106 miles from its current terminus near Ixonia,
Wisconsin to the Green Bay area, adding 537 MDth/d (approximately 537 MMcf/d) of
capacity. Guardian Pipeline's capital costs for the project are estimated to
range between $200 million and $250 million. Pending all necessary approvals,
Guardian Pipeline anticipates that construction could begin in early 2008.
TITLE TO 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, they own sites for compressor stations,
meter stations, pipeline field offices and microwave towers, and derive
interests from leases, easements, rights-of-way, permits and licenses from
landowners or governmental authorities permitting land use for construction and
operation of our pipelines.
Approximately 90 miles of Northern Border Pipeline's system are located within
the boundaries of the Fort Peck Indian Reservation in Montana. In 1980, Northern
Border Pipeline entered into a pipeline right-of-way lease with the Fort Peck
Tribal Executive Board on behalf of the Assiniboine and Sioux Tribes of the Fort
Peck Indian Reservation. This pipeline right-of-way lease granted Northern
Border Pipeline the right and privilege to construct and operate its pipeline on
certain tribal lands. The pipeline right-of-way lease expires in 2011, although
Northern Border Pipeline has an option to renew the pipeline right-of-way lease
through 2061. In conjunction with obtaining right-of-way across tribal lands
located within the exterior boundaries of the Fort Peck Indian Reservation,
Northern Border Pipeline also obtained right-of-way across allotted lands
located within the reservation boundaries. Most of the allotted lands are
subject to a perpetual easement granted by the Bureau of Indian Affairs for and
on behalf of the individual Indian owners or obtained through condemnation.
Several tracts are subject to a right-of-way grant that expires in 2015.
9
SUPPLY
The primary source of natural gas for Northern Border Pipeline is the Western
Canada Sedimentary Basin. In 2005, approximately 85% of the natural gas
transported by Northern Border Pipeline was produced in Canada. In addition,
Viking Gas Transmission's natural gas receipts were primarily from Canada. For
these reasons, the continuous supply of Canadian natural gas is crucial to our
long-term financial condition.
Significant factors that can impact the supply of Canadian natural gas
transported by our pipelines include:
- Canadian natural gas available for export;
- transportation capacity and related market pricing options on other
pipelines;
- storage capacity for Canadian natural gas and demand for storage
injection;
- natural gas from other supply sources that can be transported to the
Midwestern U.S.;
- demand for Canadian natural gas in other U.S. consumer markets; and
- natural gas market price spread between Alberta, Canada and the
Midwestern U.S., which reflects the relative supply and demand for
Canadian natural gas in Canada and in the U.S.
The composition of natural gas can impact transportation capacity of our
pipelines. If the energy content of natural gas declines, more natural gas must
be transported to meet the energy equivalent specified in our transportation
contracts. This in turn reduces the available transportation capacity of our
pipelines and negatively impacts revenue. Since 2004, Canadian natural gas
transported by our pipelines has maintained an average of 1,005 Btu/cf.
Natural gas produced in the Williston Basin of Montana, North Dakota and the
Canadian province of Saskatchewan and the Powder River Basin of Wyoming
accounted for 9% of the natural gas transported by Northern Border Pipeline in
2005. The remaining 6% of the natural gas transported by Northern Border
Pipeline was synthetic gas produced at the Dakota Gasification plant in North
Dakota.
Midwestern Gas Transmission transports natural gas from various supply sources
through its multiple interconnections with other natural gas pipelines. In 2005,
50% and 7% of Midwestern Gas Transmission's direct receipts of natural gas
originated from Canada and the Gulf Coast, respectively. The remaining 43% of
receipts were supplied through interconnections with other pipelines, including
Northern Border Pipeline. In August and September 2005, Hurricanes Katrina and
Rita adversely impacted natural gas production and transportation in the Gulf
Coast region. As a result, some Chicago market supply was redirected to the East
Coast, utilizing Midwestern Gas Transmission, to replace supply from the Gulf
Coast region.
DEMAND
Demand for natural gas transportation service on our pipelines is directly
related to demand for natural gas in the markets that our customers serve.
Factors that may impact demand for natural gas include:
- weather conditions;
- economic conditions;
- government regulation;
- availability and price of alternative energy sources;
- fuel conservation measures; and
- technological advances in fuel economy and energy generation devices.
Furthermore, factors that may impact demand for natural gas transportation
service on our pipelines include:
- the ability and willingness of natural gas shippers to utilize our
pipelines over alternative pipelines;
- transportation rates; and
- volume of natural gas delivered to Midwestern U.S. markets from other
supply sources and storage facilities.
The interstate natural gas pipeline segment's primary exposure to market risk
occurs when existing transportation contracts expire and are subject to
renegotiation. Customers with competitive alternatives analyze the market price
spread or basis differential between receipt and delivery points along the
pipeline to determine their expected gross margin. The anticipated margin and
its variability are important determinants of the transportation rate customers
are willing to pay. In addition to general demand for natural gas, regional
economic conditions, climate, trends in
10
production, available pipeline capacity and natural gas storage inventories in
each market area can also impact the basis differential and affect demand for
transportation service on our pipelines.
SEASONALITY
Demand for natural gas is seasonal. In the natural gas industry, winter season
is considered to be during the months of November to March. Summer season is
considered to be the remaining months. Peak summer season for electric power
generation includes July, August and September.
Weather conditions throughout the U.S. can significantly impact regional natural
gas supply and demand. The Western U.S. market is sensitive to precipitation
levels which impact hydroelectric power generation. During the summer, high
temperatures combined with low hydroelectric power generation levels can
increase demand for Canadian natural gas in the Western U.S. markets and shift
supply away from our pipelines. In the Midwestern U.S., the current pipeline
infrastructure is designed to meet the region's winter heating demand loads.
Moderate winter temperatures can lead to the decline in the value of our
services due to reduced demand for our transportation services.
To the extent that our pipeline capacity is contracted under firm service
transportation agreements, a significant portion of our revenue, which is
generated from demand charges, is not impacted by seasonal throughput
variations. However, when transportation agreements expire, seasonal demand can
impact our ability to recontract firm service transportation capacity.
Accordingly, throughput on our interstate natural gas pipelines may experience
seasonal fluctuations and discounting of rates may be required to maximize
revenue.
Natural gas storage is necessary to balance the relatively steady natural gas
supply with the seasonal demand of residential, commercial and electric power
generation users. In 2004, residential, commercial and electric power generation
users consumed 65% of the total natural gas volume delivered that year
according to the Energy Information Administration. Industrial users, who
consumed the remaining 35% of the total natural gas volume delivered, demand a
steady load of natural gas to operate their facilities but will turn to
alternative energy sources when it is not economical to use natural gas.
CUSTOMERS
The interstate natural gas pipeline segment serves customers in North and South
Dakota, Minnesota, Iowa, Wisconsin, Illinois, Indiana and Kentucky. Our
customers include natural gas producers, marketers, industrial facilities, local
distribution companies and electric power generating plants.
The interstate natural gas pipeline segment's four largest customers contributed
approximately 16%, 10%, 10% and 9% of the segment's revenue in 2005.
COMPETITION
Competition among natural gas pipelines is based primarily on transportation
charges and proximity to natural gas supply areas and markets. Our interstate
natural gas pipelines compete primarily with other pipelines that transport
Western Canadian natural gas to markets in the West, Midwest and East in North
America, including TransCanada Pipeline and Alliance Pipeline. We also compete
with other pipelines that provide access to natural gas storage facilities,
alternate supply basins, such as the Rockies, Mid-Continent, the Permian Basin
and the Gulf Coast, and liquefied natural gas.
CONTRACTING
Northern Border Pipeline contracted 97% of its design capacity on a firm basis
in 2005, some of which was sold at a discount to maximize overall revenue on the
Port of Morgan, Montana to Ventura, Iowa portion of the pipeline. As of January
31, 2006, 73% of the pipeline's design capacity was contracted on a firm basis
through December 31, 2006. The weighted average life of these contracts is
approximately two years.
Midwestern Gas Transmission contracted 87% and 100% of its northbound and
southbound design capacity, respectively, on a firm basis in 2005. As of January
31, 2006, the pipeline had contracted 80% and approximately 100% of its
northbound and southbound design capacity, respectively, on a firm basis through
December 31, 2006.
11
Viking Gas Transmission contracted 100% of its design capacity on a firm basis
in 2005. As of January 31, 2006, 98% of the pipeline's design capacity was
contracted on a firm basis through December 31, 2006.
GOVERNMENT REGULATION
Our interstate natural gas pipelines are regulated under the Natural Gas Act and
Natural Gas Policy Act, which give the FERC jurisdiction to regulate virtually
all aspects of this business segment, including:
- transportation of natural gas;
- rates and charges;
- terms of service, including creditworthiness requirements;
- construction of new facilities;
- extension or abandonment of service and facilities;
- accounts and records;
- depreciation and amortization policies;
- acquisition and disposition of facilities; and
- initiation and discontinuation of services.
Northern Border Pipeline Rate Case - On November 1, 2005, Northern Border
Pipeline filed a rate case with the FERC as required by the provisions of the
settlement of Northern Border Pipeline's 1999 rate case. The rate case filing
proposes a 7.8% increase to Northern Border Pipeline's revenue requirement; a
change to its rate design approach with a supply zone and market area utilizing
a fixed rate per dekatherm and a dekatherm-mile rate, respectively; a compressor
usage surcharge primarily to recover costs related to powering electric
compressors; and the implementation of a short-term rate structure on a
prospective basis.
The filing also incorporates an overall cost of capital of 10.56% based on a
rate of return on equity of 14.20%, an increase in the depreciation rate for
transmission plant from 2.25% to 2.84%, the institution of a negative salvage
rate of 0.59% and a decrease in billing determinants. Also included in the
filing is the continued inclusion of income taxes in the rate calculation.
In December 2005, the FERC issued an order that identified issues that were
raised in the proceeding, accepted the proposed rates but suspended their
effectiveness until May 1, 2006, at which time the new rates will be collected
subject to refund until final resolution of the rate case. The FERC also issued
a procedural schedule which set a hearing commencement date of October 4, 2006,
with an initial decision scheduled for February 2007, unless a settlement of the
issues is reached with the FERC and a majority of Northern Border Pipeline's
customers.
Other Interstate Natural Gas Pipeline Rate Cases - Midwestern Gas Transmission
and Viking Gas Transmission have no timing requirements or restrictions
regarding future rate case filings.
Guardian Pipeline Revenue and Cost Study - In October 2005, as required under
the terms of its certificate of public convenience and necessity which allowed
for the construction of the interstate natural gas pipeline, Guardian Pipeline
filed a revenue and cost study with the FERC. In conjunction with the filing,
Guardian requested approval of a settlement agreement to re-establish the rates
initially approved by the FERC and reduce the depreciation rate from 3.3% to 2%
retroactive to January 1, 2005. In February 2006, the FERC issued an order
accepting Guardian's revenue and cost study, including the settlement agreement
to reduce its depreciation rate.
Income Tax Allowance - In Northern Border Pipeline's 1995 and 1999 rate cases,
the FERC addressed the federal income tax allowance included in Northern Border
Pipeline's proposed cost of service. In previous FERC rulings involving other
companies, interstate pipelines were not entitled to an income tax allowance for
income attributable to limited partnership interests held by individuals. The
settlements of Northern Border Pipeline's 1995 and 1999 rate cases provided that
Northern Border Pipeline could continue to calculate the allowance for income
taxes in the manner used historically until December 2005. In May 2005, the FERC
issued a policy statement permitting the inclusion of an income tax allowance in
the rates for partnership interests held by partners with an actual or potential
income tax liability. On December 16, 2005, the FERC issued an order (December
16 Order) in its first case-specific review of the income tax allowance issue,
reaffirming its new tax allowance policy and directing the pipeline to provide
certain evidence necessary to determine the income tax allowance. The FERC's new
policy and the December 16 Order have been appealed to the D.C. Circuit and
rehearing requests have been filed with respect to the December 16 Order. The
ultimate outcome of these proceedings could impact how the policy statement is
applied to us. Northern Border Pipeline's present rates and recent rate case
filing reflect an allowance for income taxes in accordance with the provisions
of its tariff.
12
Energy Affiliates - In November 2003, the FERC adopted revised standards of
conduct which govern the relationships between regulated interstate natural gas
pipelines and their energy affiliates. The new standards of conduct were
designed to prevent interstate natural gas pipelines from giving any undue
preference to their energy affiliates and ensure that transmission service is
provided on a nondiscriminatory basis. Bear Paw Energy, subsidiaries of ONEOK,
including ONEOK Energy, and subsidiaries of TransCanada are energy affiliates of
our interstate pipeline subsidiaries.
Selective Discounting - In May 2005, the FERC issued an order reaffirming
existing discount regulations that permit pipelines to discount transportation
rates to meet gas-on-gas competition. The FERC found that its current policy on
selective discounting is an integral and essential part of its policies to
further develop a competitive natural gas transportation market.
Creditworthiness Standards - In June 2005, the FERC adopted a new policy
detailing credit standards for interstate pipelines. The FERC's policy states
that pipelines must use objective criteria to determine a shipper's
creditworthiness utilizing a standard set of documents that shippers are
required to provide. For current shippers on existing facilities, the FERC
reiterated its traditional policy of permitting no more than the equivalent of
three months of reservation charges as security. For new mainline construction,
the FERC will continue its policy of permitting larger security requirements
that reasonably reflect the risk of the project. The issue of whether a pipeline
may justify security in an amount greater than three months of reservation
charges has recently been voluntarily remanded to the FERC for further
consideration.
Energy Policy Act of 2005 - In August 2005, the Energy Policy Act of 2005 was
signed into law addressing a wide range of energy issues, including many that
impact the oil and gas industries. The Energy Policy Act of 2005 directs federal
agencies to implement certain provisions. Significant provisions affecting the
interstate natural gas industry: (1) provides for the FERC to be the lead agency
and creates a common record for review of federal permitting decisions
associated with interstate natural gas pipeline projects authorized under the
Natural Gas Act, (2) makes it unlawful to engage in market manipulation under
the Natural Gas Act; (3) authorizes the FERC to issue market transparency rules
that will provide greater information about natural gas prices, and (4)
increases criminal penalties that may be assessed under the Natural Gas Act and
the Natural Gas Policy Act up to $1 million per violation, increases civil
penalties under the Natural Gas Policy Act up to $1 million per day per
violation, and creates new civil penalties under the Natural Gas Act up to $1
million per day for violations as long as they continue.
Market Manipulation - In January 2006, the FERC issued a final rule making it
unlawful for any entity subject to its jurisdiction that directly or indirectly
purchases or sells natural gas, transportation services or electric energy to
defraud, using any device, scheme or artifice; make untrue statements of a
material fact or omit a material fact; or engage in any act, practice or course
of business that operates as a fraud. The maximum civil penalty under these
statutes is $1 million per day, per violation.
Negotiated Rate Policy - In January 2006, the FERC issued an order revising its
negotiated rate policy to allow the use of basis differentials without a revenue
cap in determining negotiated rates. The use of basis differentials for
negotiated rates was previously banned because the FERC believed that such
mechanism could give pipelines an incentive to withhold capacity and manipulate
the natural gas markets by widening the basis between indexes. The FERC found
such policy to be overly restrictive, given the benefits that such a pricing
mechanism yields. Since negotiated rate transactions must be filed and approved
by the FERC and such filings give all parties an opportunity to comment, any
allegations of attempted manipulation would be investigated. Comments were filed
seeking clarification or conditions to the implementation of this policy.
NATURAL GAS GATHERING AND PROCESSING SEGMENT
OVERVIEW
The natural gas gathering and processing segment gathers natural gas from
producers' wells and central delivery points in three producing basins: the
Williston Basin, which spans portions of Montana, North Dakota and the Canadian
province of Saskatchewan, and the Powder River and Wind River Basins of Wyoming.
Our Williston Basin facilities gather raw natural gas, primarily associated with
oil production, at the wellhead. We compress and transport the natural gas
through pipelines to our processing facilities where water and other
contaminants are removed and valuable natural gas liquids are extracted. We
separate the natural gas liquids into marketable components, including propane,
isobutane, normal butane and natural gasoline, utilizing a distillation process
known as fractionation, and sell the components to refineries or local markets.
We compress the remaining residue gas, consisting primarily of methane, sell it
to various parties and deliver it to interstate natural gas pipelines.
13
Our Powder River Basin facilities gather coalbed methane gas generally from
producer-owned central delivery points. We compress and transport the coalbed
methane gas through various pipeline systems. We remove water, further compress
and deliver the natural gas primarily to the Bighorn Gas Gathering and Fort
Union Gas Gathering trunk gathering systems for transport and delivery to
interstate natural gas pipelines.
Our Wind River Basin facilities consist of a partnership interest in a trunk
gathering system that receives natural gas from pipeline interconnections with
producer-owned gathering systems and processing plants. The natural gas is
processed as necessary and delivered to interstate natural gas pipelines.
The natural gas gathering and processing segment included the following assets
at December 31, 2005:
2005 AVERAGE
SEGMENT SUBSIDIARY OWNERSHIP GATHERING LINES RECEIPT CAPACITY THROUGHPUT
- ------------------ --------- --------------- ---------------- ------------
Bear Paw Energy 100% 3,964 miles 370 MMcf/d 251 MMcf/d
Bighorn Gas Gathering 49% 210 miles 250 MMcf/d 163 MMcf/d
Fort Union Gas Gathering 37% 106 miles 634 MMcf/d 429 MMcf/d
Lost Creek Gathering 35% 120 miles 275 MMcf/d 200 MMcf/d
Our interests in Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek
Gathering are held through our wholly-owned subsidiary, Crestone Energy.
Operating revenue is derived primarily from percentage-of-proceeds and fee-based
contracts. A significant portion of this segment's revenue is derived from
percentage-of-proceeds contracts, under which we retain a percentage of the
commodities that we gather and process. We are exposed to commodity price risk
when we then sell the natural gas and natural gas liquids we retain in the open
market. We use derivative instruments to mitigate our sensitivity to
fluctuations in the price of natural gas and natural gas liquids. Our volumetric
fee-based contracts are impacted by the volume of gas gathered and the level of
gathering service provided for high- and low-pressure gas. Our gathering margins
are generally higher for low-pressure gas gathered due to the additional
services and compression we provide that are necessary for the gas to be
gathered through our gathering system and delivered to the interstate pipeline
grid. As a result of these different service levels, a change in our gathered
volumes will not impact revenue proportionately.
Operating revenue from the natural gas gathering and processing segment
accounted for 41%, 31% and 28% of our consolidated operating revenue in 2005,
2004 and 2003, respectively.
NATURAL GAS GATHERING AND PROCESSING SYSTEMS
Bear Paw Energy - Bear Paw Energy's natural gas gathering operations are located
in the Williston and Powder River Basins. Bear Paw Energy's natural gas
processing and fractionation operations are located in the Williston Basin. The
Powder River Basin system consists of approximately 420 miles of gathering lines
with diameters ranging from 4 inches to 16 inches and approximately 65
compressor stations with a total of approximately 140,000 horsepower. The
Williston Basin system consists of approximately 3,540 miles of gathering lines
with diameters ranging from 2 inches to 16 inches, 31 compressor stations with a
total of approximately 31,000 horsepower and the Grasslands, Lignite, Marmarth
and Baker/Little Beaver processing facilities, which can process 94 MMcf/d of
raw natural gas. In 2005, Bear Paw Energy's average daily throughput was 251
MMcf/d and its processing capacity and utilization in the Williston Basin by
facility were as follows:
2005
WILLISTON BASIN PROCESSING FACILITY PROCESSING CAPACITY UTILIZATION
- ----------------------------------- ------------------- -----------
Grasslands 60 MMcf/d 83%
Lignite 20 MMcf/d 24%
Marmarth 8 MMcf/d 63%
Baker/Little Beaver 6 MMcf/d 98%
Due to additional land dedication in the Bakken formation that extends across
the Williston Basin, a second phase of expansion was initiated and completed
during the second quarter of 2005. During the third quarter of 2005, we
completed an expansion of our gathering system in the Beaver Creek area, which
increased our processing volumes
14
at the Grasslands facility. In the fourth quarter of 2005, we completed
optimization projects at the Grasslands and Baker facilities, which improved our
natural gas liquids recoveries.
Bighorn Gas Gathering - Crestone Energy owns a 49% interest in Bighorn Gas
Gathering, which is a trunk gathering system with operations in the Powder River
Basin. The remaining interest is held by Cantera, which is the project manager
and operator. The Management Committee consists of representatives of the two
owners. The Bighorn Gas Gathering system consists of 210 miles of gathering
lines with diameters ranging from 8 inches to 24 inches and receipt capacity of
250 MMcf/d. Bighorn Gas Gathering's average daily throughput in 2005 was 163
MMcf/d.
Fort Union Gas Gathering - In August 2005, Crestone Energy acquired, for $5.1
million, an additional 3.7% interest in Fort Union Gas Gathering with operations
in the Powder River Basin, bringing our total interest to 37%. The remaining
interests are held by Cantera, Western Gas Resources and Bargath, Inc. Cantera
is the managing member, Western Gas Resources is the field operator and CIG
Resources Company, pursuant to contractual arrangement, is the administrative
manager. The Fort Union Gas Gathering system is a trunk gathering system which
consists of 106 miles of 24-inch diameter gathering lines with a receipt
capacity of 634 MMcf/d. Fort Union Gas Gathering's average daily throughput in
2005 was 429 MMcf/d.
Lost Creek Gathering - Crestone Energy owns a 35% interest in Lost Creek
Gathering with operations in the Wind River Basin. The remaining interest is
held by Burlington Resources Trading, Inc., which is the managing member. A
subsidiary of Crestone Energy is the commercial and administrative manager, and
an unaffiliated third party, Elkhorn Field Services Company, is the operator.
The Lost Creek Gathering system consists of 120 miles of 24-inch diameter
gathering lines with a receipt capacity of 275 MMcf/d. Lost Creek Gathering's
average daily throughput in 2005 was 200 MMcf/d.
TITLE TO PROPERTIES
Bear Paw Energy, Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek
Gathering hold the right, title and interest in their respective gathering and
processing assets which consist of low- and high-pressure gathering lines,
compression and measurement installations, and treating, processing and
fractionation facilities. With respect to real property, we either own the
properties on which our facilities are located or derive interests from leases,
easements, rights-of-way and permits.
SUPPLY
We do not explore for or produce crude oil or natural gas, nor do we own crude
oil or natural gas reserves. Supply for our natural gas gathering and processing
segment depends on the pace of natural gas drilling by producers. Significant
factors that can impact the supply of natural gas gathered and processed
include:
- producers' ability 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;
- environmental regulations governing water discharge associated with
coalbed methane gas production;
- oil and natural gas commodity prices; and
- natural gas and crude oil take-away capacity from the various basins
that we service.
We mitigate supply risk by requiring acreage dedication, long-term or minimum
volume commitments and/or demand charges from gas producers.
Williston Basin - Most of the wells connected to our Williston Basin facilities
produce casinghead gas, which is associated gas that occurs in crude oil
reservoirs. Casinghead gas is generally high in natural gas liquids and is
significantly higher in energy content than coalbed methane gas. Natural gas
liquids, which are separated from raw natural gas and fractionated into
components, and residue gas are sold in the open market.
Powder River Basin - Coalbed methane gas, which is natural gas extracted from
coal seams in the earth's crust, is produced in the Powder River Basin.
Approximately 396,000 and 832,000 acres are dedicated by producers to Bear Paw
Energy and Bighorn Gas Gathering, respectively, primarily under long-term
agreements. Bighorn Gas
15
Gathering and Fort Union Gas Gathering are generally stable in terms of
throughput volume because they are trunk gathering systems and the natural gas
is gathered from large areas.
Coalbed methane wells can produce large amounts of water, which can impact
producers' willingness and ability to drill. The time required for coalbed
methane wells to dewater prior to significant gas production can be difficult to
predict and environmentally acceptable disposal alternatives for the water can
be costly. In addition, production on federal lands, which accounts for 65% of
the Powder River Basin acreage, requires producers to obtain drilling and
production permits from the Bureau of Land Management.
Wind River Basin - The Lost Creek Gathering system gathers natural gas produced
from conventional gas wells in the Wind River Basin in central Wyoming.
DEMAND
Demand for natural gas gathering and processing services is directly related to
the proximity of our systems to natural gas supply areas. Other factors that may
impact demand for gathering and processing services provided by our systems
include:
- gathering and processing services offered;
- our rate structure and contractual terms for services;
- competition;
- system operating conditions, including pressure, volumes and capacity;
- speed of connectivity of new receipt points;
- quality of natural gas produced;
- natural gas reserve characteristics;
- location and capacity availability of receipt and delivery points
along the gathering lines;
- regulatory requirements; and
- commodity prices.
SEASONALITY
While certain components of demand for natural gas are seasonal, demand for
gathering and processing services are aligned with supply, which flows at a
relatively steady pace over the life of the reserves.
CUSTOMERS
The natural gas gathering and processing segment's customers are primarily
natural gas producers. Three of Bear Paw Energy's largest customers contributed
approximately 45%, 20% and 7% of its operating revenue in 2005.
COMPETITION
The natural gas gathering and processing segment competes with companies that
provide gathering and processing services in the Powder River, Wind River and
Williston Basin production areas. We compete with independent gathering
companies and gathering companies who are affiliated with producers for
gathering and processing contracts based on terms, integrated service offerings,
delivery options and coverage area. Once a relationship with a producer is
established, the term of the acreage dedication and cost of building duplicative
facilities mitigate competition in the vicinity.
Strong natural gas and natural gas liquids prices continue to attract natural
gas gathering and processing competition, particularly in the Western U.S. where
our gathering and processing facilities are located. Increased competition
continues to put pressure on our gathering and processing margins.
GOVERNMENT REGULATION
FERC Regulation of Gathering Affiliates - In September 2005, the FERC issued a
notice of inquiry to evaluate possible changes in the criteria used by the FERC
in evaluating whether and under what circumstances the FERC may invoke its "in
connection with" jurisdiction to guard against abusive practices by natural gas
companies and their gathering affiliates. The notice asks for comments on the
relevant factors in determining whether a gathering company is separate from its
pipeline affiliate and what kind of conduct should trigger the FERC's
reassertion of jurisdiction over the gathering affiliate. The notice also asks
whether states have incentives to ensure that gathering
16
service providers do not engage in anticompetitive behavior and for assessments
of the nature of any gap between state and FERC regulation of natural gas
companies.
COAL SLURRY PIPELINE SEGMENT
OVERVIEW
The coal slurry pipeline segment consists of Black Mesa. Black Mesa is designed
to transport crushed coal suspended in water along 273 miles of pipeline that
originates at a coal mine in Kayenta, Arizona and terminates at the Mohave
Generating Station in Laughlin, Nevada. The coal slurry pipeline is the sole
source of fuel for the Mohave Generating Station and was fully contracted to
Peabody Western Coal until December 31, 2005. The water used by the coal slurry
pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint
use area until December 31, 2005.
Under a consent decree, the Mohave Generating Station agreed to install
pollution control equipment by December 2005. However, due to the uncertainty
surrounding the ongoing source of water supply and coal supply negotiations,
Southern California Edison, a 56% owner of the Mohave Generating Station, filed
a petition before the California Public Utility Commission requesting that they
either recognize the end of Mohave Generating Station's coal-fired operations on
December 31, 2005, or authorize expenditures for pollution control activities
required for future operation. In December 2004, the California Public Utility
Commission authorized Southern California Edison to make the necessary
expenditures for critical path investments and directed interested parties to
continue working toward resolution of essential water and coal supply issues.
On December 31, 2005, we shut down our coal slurry pipeline operation. The
Mohave Generating Station co-owners, Navajo Nation, Hopi Tribe, Peabody Western
Coal Company and other interested parties continue to negotiate water source and
coal supply issues and Black Mesa is working to resolve coal slurry
transportation issues so that operations may resume in the future. If there are
successful resolutions of these issues and the project receives a favorable
Environmental Impact Statement, Black Mesa will reconstruct the coal slurry
pipeline in late 2008 and 2009. Portions of the pipeline must be modified or
reconstructed to repair normal wear related use before coal slurry
transportation service can resume. If the Mohave Generating Station permanently
closes, we will also permanently shut down our coal slurry operation.
TITLE TO PROPERTIES
Black Mesa holds the titles to its pipeline and pump stations. Black Mesa either
owns the properties on which its facilities are located or derives interests
from leases, easements, rights-of-way and permits, including the rights-of-way
grants from the Navajo Nation and Hopi Tribe.
ENVIRONMENTAL AND SAFETY MATTERS
Our operations are subject to extensive federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to the protection of the environment. Failure to comply with
these laws and regulations can result in substantial penalties, enforcement
actions and remedial liabilities. Although we believe our operations and
facilities are in compliance in all material respects with applicable
environmental laws and safety regulations, we cannot provide any assurances that
compliance with current and future laws and regulations will not have a material
adverse affect on our financial position or results of operations.
PIPELINE SAFETY
We are subject to U.S. Department of Transportation integrity management
regulations. The Pipeline Safety Improvement Act requires pipeline companies to
perform integrity assessments on pipeline segments that exist in densely
populated 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 perform subsequent
integrity assessments on a seven-year cycle. We are on schedule to meet the
required assessment of 50% of the highest priority high consequence areas by
2007.
AIR AND WATER EMISSIONS
The Clean Air Act and the Clean Water Act impose restrictions and controls
regarding the discharge of pollutants into the air and water in the U.S. Under
the Clean Air Act, a federal operating permit is required for sources of
17
significant air emissions. We may be required to incur certain capital
expenditures for air pollution control equipment in connection with obtaining or
maintaining permits and approvals for sources of air emissions. The Clean Water
Act imposes substantial potential liability for the removal and remediation of
pollutants discharged in U.S. water. Although we cannot provide any assurances,
we believe that we are in compliance with state and federal requirements related
to these regulations.
SUPERFUND
The Comprehensive Environmental Response, Compensation and Liability Act, also
known as Superfund, imposes liability, without regard to fault or the legality
of the original act, on certain classes of persons who contributed to the
release of a hazardous substance into the environment. These persons include the
owner or operator of a facility where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
facility. Under the Comprehensive Environmental Response, Compensation and
Liability Act, these persons may be liable for the costs of cleaning up the
hazardous substances released into the environment, damages to natural resources
and the costs of certain health studies.
In July 2005, the EPA notified Midwestern Gas Transmission and several other
non-affiliated parties, of possible liability pursuant to the Comprehensive
Environmental Response, Compensation and Liability Act and requested information
related to the Dunavan Oil Site located in Oakwood, Illinois. The EPA identified
Midwestern Gas Transmission as possibly transporting and disposing of used oil
at the contaminated site and classified Midwestern Gas Transmission as a de
minimis party. While it is difficult to determine the liability related to this
site because of the number of responsible parties involved, cost sharing
arrangements with other potentially responsible parties and the uncertainty
surrounding remediation costs, we believe the costs to resolve this matter will
not be material to our financial position or results of operations.
NITROGEN OXIDES STATE IMPLEMENTATION PLAN
In September 2005, the Illinois EPA distributed a draft of a rule to control
nitrogen oxide emissions from reciprocating engines and turbines state-wide by
January 1, 2009. Under this rule, the state would require the installation of
necessary controls to comply with EPA rules regarding the Nitrogen Oxides State
Implementation Plan Call, ozone non-attainment and fine particulate standards.
Midwestern Gas Transmission participated in several stakeholder meetings to
provide comments concerning the draft rule. Another draft of the rule is
expected to be distributed before it is submitted to the Illinois Pollution
Control Board. As currently drafted, the rule affects five Midwestern Gas
Transmission engines in Illinois and the preliminary cost estimates for the
required emission controls are less than $5 million.
MAJOR CUSTOMERS
For the year ended December 31, 2005, two customers each accounted for more than
10% of our consolidated revenue. Total transactions with Lodgepole Energy
Marketing and BP Canada Energy Marketing Corp. contributed 18% and 17% of
consolidated revenue, respectively. Lodgepole Energy Marketing is Bear Paw
Energy's largest customer. BP Canada Energy Marketing Corp. conducts business
with both the interstate natural gas pipeline segment and the natural gas
gathering and processing segment.
EMPLOYEES
We do not directly employ any of the persons responsible for managing or
operating the Partnership or for providing us with services related to our
day-to-day business affairs. Northern Plains provides administrative, operating
and
18
management services to us and our interstate natural gas pipeline segment under
operating agreements. NBP Services provides administrative, operating and
management services to us and our natural gas gathering and processing segment.
As of January 31, 2006, Northern Plains and NBP Services had 336 and 125
employees, respectively. Eighteen employees, 4 of whom were eligible to be
represented by the United Mine Workers of America or a collective bargaining
agreement, support Black Mesa's coal slurry pipeline operations.
AVAILABLE INFORMATION
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 are available, free of charge, on our
website at www.northernborderpartners.com as soon as reasonably practicable
after we electronically file the material with, or furnish it to, the SEC. Our
documents filed with or furnished to the SEC are also available on the SEC's
website at www.sec.gov. Our Governance Guidelines, Code of Conduct, Accounting
and Financial Reporting Code of Ethics, Partnership Agreement and written
charter of the Audit Committee are also available on our website. You may
receive a copy of these documents, excluding exhibits, free of charge by
contacting Investor Relations at 877-208-7318 or writing to Northern Border
Partners, L.P., P.O. Box 542500, Omaha, Nebraska 68154-8500.
ITEM 1A. RISK FACTORS
Limited partner interests are inherently different from the capital stock of a
corporation, although many of the business risks to which we are subject are
similar to those faced by corporations engaged in a similar business. The
following risk factors should be carefully considered together with all of the
other information included in this annual report when evaluating our business.
If any of the following risks were to actually occur, our business, results of
operations and financial condition could be materially adversely affected. In
that case, we may not be able to pay distributions to our common unitholders and
the trading price of our common units could decline.
RISKS INHERENT IN OUR BUSINESS
IF PRODUCTION FROM THE WESTERN CANADA SEDIMENTARY BASIN REMAINS FLAT OR DECLINES
AND DEMAND FOR NATURAL GAS FROM THE WESTERN CANADA SEDIMENTARY BASIN IS GREATER
IN MARKET AREAS OTHER THAN THE MIDWESTERN U.S., DEMAND FOR OUR TRANSPORTATION
SERVICES COULD SIGNIFICANTLY DECREASE.
We depend on natural gas supply from the Western Canada Sedimentary Basin
because our interstate natural gas pipeline segment transports primarily
Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern
U.S. market area. If demand for natural gas increases in Canada or other markets
not served by our pipelines and production remains flat or declines, demand for
transportation service on our interstate natural gas pipelines could decrease
significantly, which could adversely impact our results of operations.
THE VOLATILITY OF NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY
AFFECT OUR CASH FLOW.
A significant portion of our natural gas gathering and processing revenue is
derived from the sale of commodities we retain for our gathering and processing
services. As a result, we are sensitive to natural gas and natural gas liquids
price fluctuations. Natural gas and natural gas liquids prices have been and are
likely to continue to be volatile in the future. The recent record high natural
gas and natural gas liquids prices may not continue and could drop precipitously
in a short period of time. The prices of natural gas and natural gas liquids are
subject to wide fluctuations in response to a variety of factors beyond our
control, including the following:
- relatively minor changes in the supply of, and demand for, domestic
and foreign natural gas and natural gas liquids;
- market uncertainty;
- availability and cost of transportation capacity;
- the level of consumer product demand;
- political conditions in international natural gas-producing regions;
- weather conditions;
- domestic and foreign governmental regulations and taxes;
19
- the price and availability of alternative fuels;
- speculation in the commodity futures markets;
- overall domestic and global economic conditions;
- the price of natural gas and natural gas liquids imports; and
- the effect of worldwide energy conservation measures.
These external factors and the volatile nature of the energy markets make it
difficult to reliably estimate future prices of natural gas and natural gas
liquids. As natural gas and natural gas liquids prices decline, we are paid less
for our commodities, thereby reducing our cash flow. In addition, production and
related volumes could also decline.
OUR INTERSTATE NATURAL GAS PIPELINES' TRANSPORTATION RATES ARE SUBJECT TO REVIEW
AND POSSIBLE ADJUSTMENT BY FEDERAL REGULATORS.
Our interstate natural gas pipelines are subject to extensive regulation by the
FERC, which regulates most aspects of our pipeline business, including our
transportation rates. Under the Natural Gas Act, interstate transportation rates
must be just and reasonable and not unduly discriminatory. In November 2005,
Northern Border Pipeline filed a rate case with the FERC as required by the
provisions of the settlement of its last rate case. If the increased rates that
Northern Border Pipeline is seeking to collect are ultimately lowered by the
FERC, on its own initiative, or as a result of challenges raised by Northern
Border Pipeline's customers or third parties, the FERC could require refunds of
amounts collected under rates that it finds unlawful. In addition, an adverse
decision by the FERC in Northern Border Pipeline's rate case could result in
reductions to Northern Border Pipeline's regulated rates on a prospective basis,
which could adversely affect our cash flow.
IF WE ARE UNABLE TO COMPETE FOR CUSTOMERS, WE MAY HAVE SIGNIFICANT LEVELS OF
UNCONTRACTED OR DISCOUNTED TRANSPORTATION CAPACITY ON OUR INTERSTATE NATURAL GAS
PIPELINES.
Our interstate natural gas pipeline segment competes with other pipelines for
Canadian natural gas supplies delivered to U.S. markets. If we do not
successfully compete with the other natural gas pipelines, we may have
significant levels of uncontracted or discounted capacity on our pipelines,
which could adversely impact our results of operations.
OUR INTERSTATE NATURAL GAS PIPELINES HAVE RECORDED CERTAIN ASSETS THAT MAY NOT
BE RECOVERABLE FROM OUR CUSTOMERS.
Accounting policies for FERC-regulated companies permit certain assets to be
recorded that result from the regulated ratemaking process that would not be
recorded under GAAP for nonregulated entities. We consider factors such as
regulatory changes and the impact of competition to determine the probability of
future recovery of these assets. If we determine future recovery is no longer
probable, we would be required to write off the regulatory assets at that time.
IF THE LEVEL OF DRILLING AND PRODUCTION IN THE WILLISTON, POWDER RIVER AND WIND
RIVER BASINS SUBSTANTIALLY DECLINES, OUR GATHERING AND PROCESSING VOLUMES AND
REVENUE COULD DECLINE.
Our ability to maintain or expand our natural gas gathering and processing
business depends largely on the level of drilling and production in the
Williston, Powder River and Wind River Basins. Drilling and production in the
Williston and Wind River Basins are impacted by factors beyond our control,
including:
- demand for natural gas and refinery-grade crude oil;
- producers' desire and ability to obtain necessary permits in a timely
and economic manner;
- natural gas field characteristics and production performance;
- surface access and infrastructure issues; and
- capacity constraints on natural gas, crude oil and natural gas liquids
pipelines that transport gas from the producing areas and our
facilities.
In addition, drilling and production in the Powder River Basin are impacted by
environmental regulations governing water discharge associated with coalbed
methane production. If the level of drilling and production in these
20
areas substantially declines, our gathering and processing volumes and revenue
could be reduced.
THE COMPOSITION OF NATURAL GAS RECEIVED BY OUR PIPELINES OR GATHERED BY OUR
GATHERING AND PROCESSING OPERATIONS COULD REDUCE OUR AVAILABLE TRANSPORTATION
CAPACITY AND INCREASE OUR OPERATING EXPENSES.
If the energy content of the natural gas received by our pipelines is below the
energy equivalent specified under our transportation contracts, we must
transport additional natural gas to meet our contractual commitments. The
transportation of this additional natural gas reduces the available
transportation capacity on our pipelines and would negatively impact our
operating revenue. In addition, if the energy content of the natural gas
gathered by our natural gas gathering and processing operations is below
pipeline quality standards and we are unable to blend the gas, we would incur
higher operating expenses related to the additional processing required to avoid
curtailment.
OUR OPERATIONS ARE SUBJECT TO FEDERAL AND STATE LAWS AND REGULATIONS RELATING TO
THE PROTECTION OF THE ENVIRONMENT, WHICH MAY EXPOSE US TO SIGNIFICANT COSTS AND
LIABILITIES.
The risk of incurring substantial environmental costs and liabilities is
inherent in the performance of our operations. Our operations are subject to
extensive federal, state and local laws and regulations governing the discharge
of materials into the environment or otherwise relating to the protection of the
environment. These laws include, for example:
- the federal Clean Air Act and analogous state laws, which impose
obligations related to air emissions;
- the federal Water Pollution Control Act of 1972, as renamed and
amended as the Clean Water Act and analogous state laws, which
regulate discharge of wastewaters from our facilities to state and
federal waters;
- the federal Comprehensive Environmental Response, Compensation and
Liability Act and analogous state laws that regulate the cleanup of
hazardous substances that may have been released at properties
currently or previously owned or operated by us or locations to which
we have sent wastes for disposal; and
- the federal Resource Conservation and Recovery Act and analogous state
laws that impose requirements for the handling and discharge of solid
and hazardous waste from our facilities.
Various governmental authorities, including the U.S. EPA, have the power to
enforce compliance with these laws and regulations and the permits issued under
them. Violators are subject to administrative, civil and criminal penalties,
including civil fines, injunctions or both. Joint and several, strict liability
may be incurred without regard to fault under the Comprehensive Environmental
Response, Compensation and Liability Act, Resource Conservation and Recovery
Act and analogous state laws for the remediation of contaminated areas.
There is inherent risk of the incurrence of environmental costs and liabilities
in our business due to our handling of the products we gather, transport
and process, air emissions related to our operations, historical industry
operations and waste disposal practices, some of which may be material. Private
parties, including the owners of properties through which our pipeline systems
pass, may have the right to pursue legal actions to enforce compliance as well
as to seek damages for non-compliance with environmental laws and regulations
or for personal injury or property damage arising from our operations. Some
sites we operate are located near current or former third-party hydrocarbon
storage and processing operations and there is a risk that contamination has
migrated from those sites to ours. In addition, increasingly strict laws,
regulations and enforcement policies could significantly increase our compliance
costs and the cost of any remediation that may become necessary, some of
which may be material. Additional information is included under Item 1,
"Business-Environmental and Safety Matters."
Our insurance may not cover all environmental risks and costs or may not provide
sufficient coverage in the event an environmental claim is made against us. Our
business may be adversely affected by increased costs due to stricter pollution
control requirements or liabilities resulting from non-compliance with required
operating or other regulatory permits. New environmental regulations might also
adversely affect our products and activities and federal and state agencies
could impose additional safety requirements, all of which could materially
affect our profitability.
21
PIPELINE INTEGRITY PROGRAMS AND REPAIRS MAY IMPOSE SIGNIFICANT COSTS AND
LIABILITIES.
In December 2003, the U.S. Department of Transportation issued a final rule
requiring pipeline operators to develop integrity management programs for
pipelines located near "high consequence areas," where a leak or rupture could
do the most harm. The final rule requires operators to perform ongoing
assessments of pipeline integrity; identify and characterize applicable threats
to pipeline segments that could impact a high consequence area; improve data
collection, integration and analysis; repair and remediate the pipeline as
necessary; and implement preventive and mitigating actions. The final rule
incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and
became effective in January 2004. The results of these testing programs
could cause us to incur significant capital and operating expenditures in
response to repair, remediation, preventative or mitigating actions that are
determined to be necessary.
WE ARE EXPOSED TO THE CREDIT RISK OF OUR CUSTOMERS AND OUR CREDIT RISK
MANAGEMENT MAY NOT BE ADEQUATE TO PROTECT AGAINST SUCH RISK.
We are subject to the risk of loss resulting from nonpayment and/or
nonperformance by our customers. Our customers are predominantly natural gas
producers and marketers that may experience deterioration of their financial
condition as a result of changing market conditions or financial difficulties
that could impact their creditworthiness or ability to pay us for our services.
We have obtained the maximum security allowed under the FERC creditworthiness
policy. If we fail to adequately assess the creditworthiness of existing or
future customers, unanticipated deterioration in their creditworthiness and any
resulting nonpayment and/or nonperformance could adversely impact our results of
operations. In addition, if any of our customers filed for bankruptcy
protection, we may not be able to recover amounts owed or resell the capacity
held by such customer, which would negatively impact our results of operations.
PERMANENT SHUT DOWN OF OUR COAL SLURRY OPERATION COULD ADVERSELY IMPACT OUR
RESULTS OF OPERATIONS.
Our coal slurry pipeline is the sole source of fuel for the Mohave Generating
Station and was fully contracted to Peabody Western Coal until December 31,
2005. The water used by our coal slurry pipeline was supplied from an aquifer in
the Navajo Nation and Hopi Tribe joint use area until December 31, 2005. The
Mohave Generating Station co-owners, the Navajo Nation, Hopi Tribe, Peabody
Western Coal Company and other interested parties continue to negotiate water
source and coal supply issues and we are working to resolve coal slurry
transportation issues so that operations may resume in the future. If the Mohave
Generating Station is permanently closed, we expect to incur pipeline removal
and remediation costs and a non-cash impairment charge related to the remaining
undepreciated cost of the pipeline assets and goodwill. We may be required to
take an impairment charge in accordance with GAAP prior to final resolution of
the issues concerning the Mohave Generating Station even though the project may
ultimately proceed. Each quarter, we will take into consideration our
assumptions and estimates about economic conditions and the probability of Black
Mesa's future profitability. If an event or change in circumstance occurs that
potentially impacts our assumptions and estimates, we will be required to test
the assets for impairment. If our testing indicates that the carrying amount of
Black Mesa's assets exceeds their fair value, we would recognize an impairment
charge.
OUR USE OF FINANCIAL INSTRUMENTS TO HEDGE MARKET RISK MAY RESULT IN REDUCED
INCOME.
We utilize financial instruments to mitigate our exposure to interest rate and
commodity price fluctuations. Hedging instruments that are used to reduce our
exposure to interest rate fluctuations could expose us to risk of financial loss
where we have contracted for variable-rate swap instruments to hedge fixed-rate
instruments and the variable rate exceeds the fixed rate. In addition, these
hedging arrangements may limit the benefit we would otherwise receive if we have
contracted for fixed-rate swap agreements to hedge variable-rate instruments and
the variable rate falls below the fixed rate. Hedging arrangements that are used
to reduce our exposure to commodity price fluctuations may limit the benefit we
would otherwise receive if market prices for natural gas and natural gas liquids
exceed the stated price in the hedge instrument for these commodities.
A DOWNGRADE OF OUR CREDIT RATING MAY REQUIRE US TO OFFER TO REPURCHASE OUR
SENIOR NOTES OR IMPAIR OUR ABILITY TO ACCESS CAPITAL.
22
We could be required to offer to repurchase certain of our senior notes at par
value, plus any associated penalties and premiums, if Moody's Investor Services
or Standard & Poor's Rating Services rate our senior notes below investment
grade. We may not have sufficient cash on hand to repurchase the senior notes at
par value, which may cause us to borrow money under our credit facilities or
seek alternative financing sources to finance the repurchase. We could also face
difficulties accessing capital or our borrowing costs could increase, impacting
our ability to obtain financing for acquisitions or capital expenditures and to
refinance indebtedness.
OUR INABILITY TO EXECUTE GROWTH AND DEVELOPMENT PROJECTS AND ACQUIRE NEW ASSETS
COULD REDUCE CASH DISTRIBUTIONS TO UNITHOLDERS.
Our interstate natural gas pipelines are generally allowed to collect a return
on their assets' recorded book value, generally referred to as rate base, in
their transportation rates. Our interstate pipelines must maintain or increase
the book value of their assets through growth projects in order to maintain or
increase the return collected on our rate base. Accordingly, if we are unable to
implement business development opportunities and finance such activities on
economically acceptable terms, our future growth will be limited, which could
adversely impact our results of operations.
RISKS RELATED TO PROPOSED TRANSACTIONS
WE MAY NOT BE ABLE TO CONSUMMATE THE ACQUISITION OF THE ONEOK SUBSIDIARIES.
The agreements with ONEOK to acquire certain subsidiaries of ONEOK contain
customary and other closing conditions that, if not satisfied or waived, would
result in the acquisition not occurring. These conditions include, among others:
- expiration or early termination of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976;
- continued accuracy of the representations and warranties contained in
the agreements;
- performance by each party of its obligations under the agreements;
- consummation of ONEOK's purchase of Northwest Border;
- consummation of our sale of a 20% interest in Northern Border Pipeline
to TC PipeLines;
- amendments to certain debt agreements of ONEOK, us and Northern Border
Pipeline;
- lender approvals; and
- absence of any decree, order, injunction or law that prohibits,
restricts or substantially delays the transaction or makes the
transaction unlawful.
If we are unable to consummate the acquisition, we would be subject to a number
of risks, including the following:
- we would not realize the anticipated benefits of the proposed
acquisition;
- we will incur and will remain liable for significant transaction
costs, including legal, accounting, financial advisory and other costs
relating to the acquisition whether or not it is consummated; and
- our business and operations may be harmed to the extent that
customers, suppliers and others believe that we cannot effectively
compete in the marketplace without the acquisition or there is
customer or employee uncertainty surrounding the future direction of
our service offerings and strategy.
The occurrence of any of these events individually or in combination could have
an adverse effect on our results of operations.
WE MAY NOT BE ABLE TO SUCCESSFULLY INTEGRATE THE OPERATIONS OF ONEOK WITH OUR
CURRENT OPERATIONS.
If we consummate the acquisition of certain ONEOK subsidiaries, the integration
of their operations with our current operations will be a complex,
time-consuming and costly process. Failure to timely and successfully integrate
the operations of the ONEOK subsidiaries may have a material adverse effect on
our business, financial condition and results of operations. The difficulties of
integrating the ONEOK operations will present challenges to our management
including:
- operating a significantly larger combined company with operations in
geographic areas in which we have not previously operated;
23
- managing relationships with new customers for whom we have not
previously provided services;
- integrating personnel with diverse backgrounds and organizational
cultures;
- experiencing operational interruptions or the loss of key employees,
customers or suppliers;
- inefficiencies and complexities that may arise due to the
unfamiliarity with the new operations and the businesses associated
with them, including with their markets;
- assimilating the operations, technologies, services and products of
the acquired operations;
- assessing the internal controls and procedures for the combined entity
that we are required to maintain under the Sarbanes-Oxley Act of 2002;
and
- consolidating other corporate and administrative functions.
We will also be exposed to risks that are commonly associated with transactions
similar to this acquisition, such as unanticipated liabilities and costs, some
of which may be material, and diversion of management's attention. As a result,
the anticipated benefits of the acquisition may not be fully realized, if at
all.
THE ISSUANCE OF UNITS TO ONEOK IN CONNECTION WITH THE ACQUISITION WILL DILUTE
OUR CURRENT UNITHOLDERS' OWNERSHIP INTERESTS UPON THEIR CONVERSION TO COMMON
UNITS.
In connection with the acquisition of the ONEOK subsidiaries, we will issue
approximately 36.5 million Class B units representing limited partner interests
in us to ONEOK. The Class B units will convert to common units on a one-for-one
basis at the holder's option upon the requisite approval of such conversion by
our unitholders at a special meeting of unitholders or automatically, upon the
requisite approval of both the conversion and certain amendments to our
partnership agreement by our unitholders at a special meeting of unitholders.
The conversion of the Class B units will have the following effects:
- our unitholders' proportionate ownership interest in us will decrease;
- the amount of cash available to pay distributions on each common unit
may decrease;
- the relative voting strength of each previously outstanding common
unit may be diminished; and
- the market price of the common units may decline.
In addition, ONEOK may, from time to time, sell all or a portion of its common
units. Sales of substantial amounts of their common units, or the anticipation
of such sales, could lower the market price of our common units and may make it
more difficult for us to sell our equity securities in the future at a time and
at a price that we deem appropriate.
RISKS INHERENT IN AN INVESTMENT IN US
WE DO NOT OPERATE ALL OF OUR ASSETS NOR DO WE DIRECTLY EMPLOY ANY OF THE PERSONS
RESPONSIBLE FOR PROVIDING US WITH ADMINISTRATIVE, OPERATING AND MANAGEMENT
SERVICES. THIS RELIANCE ON OTHERS TO OPERATE OUR ASSETS AND TO PROVIDE OTHER
SERVICES COULD ADVERSELY AFFECT OUR BUSINESS AND OPERATING RESULTS.
We rely on Northern Plains and NBP Services to provide us with administrative,
operating and management services. We have a limited ability to control our
operations or the associated costs of such operations. The success of these
operations depends on a number of factors that are outside our control,
including the competence and financial resources of the operator. Northern
Plains and NBP Services may outsource some or all of these services to third
parties, and a failure to perform by these third-party providers could lead to
delays in or interruptions of these services. Should Northern Plains or NBP
Services not perform their respective contractual obligations, we may have to
contract elsewhere for these services, which may cost more than we are currently
paying. In addition, we may not be able to obtain the same level or kind of
service or retain or receive the services in a timely manner, which may impact
our ability to perform under our transportation contracts and negatively affect
our business and operating results. Our reliance on Northern Plains, NBP
Services and the third-party providers with which they contract, together with
our limited ability to control certain costs, could harm our business and
results of operations.
THE PARTNERSHIP POLICY COMMITTEE, OUR GENERAL PARTNERS AND THEIR AFFILIATES HAVE
CONFLICTS OF INTEREST AND LIMITED FIDUCIARY DUTIES, WHICH MAY PERMIT THEM TO
FAVOR THEIR OWN INTERESTS.
24
Our general partners collectively own a 2% general partner interest and a 1.06%
limited partner interest in us. Although our general partners, through the
Partnership Policy Committee, have a fiduciary duty to manage us in a manner
beneficial to us and our unitholders, the boards of directors of the general
partners have a fiduciary duty to manage our general partners in a manner
beneficial to their respective owners. Some members of our Partnership Policy
Committee are also members of their respective general partner's board of
directors. Conflicts of interest may arise between our general partners and
their affiliates and us and our unitholders. In resolving these conflicts, our
general partners may favor their own interests and the interests of their
respective affiliates over the interests of our unitholders. These conflicts
include, among others, the following situations:
- the Partnership Policy Committee and our general partners are allowed
to take into account the interests of parties other than us, such as
ONEOK and TransCanada, in resolving conflicts of interest, which has
the effect of limiting its fiduciary duty to our unitholders;
- the respective affiliates of our general partners may engage in
competition with us;
- the Partnership Policy Committee and our general partners have limited
their liability and reduced their fiduciary duties, and have also
restricted the remedies available to our unitholders for actions that,
without the limitations, might constitute breaches of fiduciary duty;
- the Partnership Policy Committee determines the amount and timing of
our cash reserves, asset purchases and sales, capital expenditures,
borrowings and issuances of additional partnership securities, each of
which can affect the amount of cash that is distributed to our
unitholders;
- the Partnership Policy Committee approves the amount and timing of any
capital expenditures. The nature of the capital expenditure, whether
it is a maintenance capital expenditure or a growth capital
expenditure, can affect the amount of cash that is distributed to our
unitholders;
- the Partnership Policy Committee may cause us to borrow funds in order
to permit the payment of cash distributions, even if the purpose or
effect of the borrowing is to make incentive distributions;
- the Partnership Policy Committee determines which costs incurred by
them, our general partners and their respective affiliates are
reimbursable by us;
- our partnership agreement does not restrict the Partnership Policy
Committee from causing us to pay them, our general partners or their
respective affiliates for any services rendered to us or entering into
additional contractual arrangements with any of these entities on our
behalf;
- our general partners may exercise their limited right to call and
purchase common units if they and their respective affiliates own more
than 80% of the units; and
- the Partnership Policy Committee decides whether to retain separate
counsel, accountants or others to perform services for us.
OUR PARTNERSHIP AGREEMENT LIMITS OUR GENERAL PARTNERS' FIDUCIARY DUTIES TO OUR
UNITHOLDERS AND RESTRICTS THE REMEDIES AVAILABLE TO UNITHOLDERS FOR ACTIONS
TAKEN BY OUR GENERAL PARTNERS THAT MIGHT OTHERWISE CONSTITUTE BREACHES OF
FIDUCIARY DUTY.
Our partnership agreement contains provisions that reduce the standards to which
our general partners would otherwise be held by state fiduciary duty law. For
example, our partnership agreement:
- permits our general partners to make a number of decisions in their
individual capacities, as opposed to in their capacity as our general
partners. This entitles our general partners to consider only the
interests and factors that they desire, and they have no duty or
obligation to give any consideration to any interest of, or factors
affecting, us, our affiliates or any limited partner. Examples include
the exercise of their limited call right, their voting rights with
respect to the units they own, their registration rights and their
determination (through the Partnership Policy Committee) whether or
not to consent to any merger or consolidation of the partnership;
- provides that our general partners will not have any liability to us
or our unitholders for decisions made in their capacity as a general
partner so long as they acted in good faith, meaning they believed the
decision was in the best interests of our partnership;
- provides that our general partners are entitled to make other
decisions in "good faith" if they reasonably believe that the decision
is in our best interests;
- provides generally that affiliated transactions and resolutions of
conflicts of interest not approved by the Audit Committee and not
involving a vote of unitholders must be on terms no less favorable to
us than those generally being provided to or available from unrelated
third parties or be "fair and reasonable" to us, as determined by our
general partners in good faith, and that, in determining whether a
transaction or
25
resolution is "fair and reasonable," our general partners may consider
the totality of the relationships between the parties involved,
including other transactions that may be particularly advantageous or
beneficial to us; and
- provides that our general partners, their respective affiliates and
their officers and directors will not be liable for monetary damages
to us or our limited partners for any acts or omissions so long as
such person acted in good faith and in a manner believed to be in, or
not opposed to, the best interest of the partnership and, with respect
to any criminal proceeding, had no reasonable cause to believe its
conduct was unlawful.
By purchasing a common unit, a common unitholder will be bound by the provisions
in the partnership agreement, including the provisions discussed above.
THE CONTROL OF OUR GENERAL PARTNERS MAY BE TRANSFERRED TO A THIRD PARTY WITHOUT
UNITHOLDER CONSENT.
Our general partners may transfer their respective general partner interests to
a third party without the consent of the unitholders. Furthermore, our
partnership agreement does not restrict the ability of the members of our
general partners from transferring their interests in our general partners to a
third party. The new members or stockholders, as the case may be, of our general
partners would then be in a position to replace the members of the Partnership
Policy Committee with their own choices and to control the decisions taken by
the Partnership Policy Committee.
INCREASES IN INTEREST RATES MAY CAUSE THE MARKET PRICE OF OUR COMMON UNITS TO
DECLINE.
An increase in interest rates may cause a corresponding decline in demand for
equity investments in general, and in particular for yield-based equity
investments such as our common units. Any such increase in interest rates or
reduction in demand for our common units resulting from other more attractive
investment opportunities may cause the trading price of our common units to
decline.
WE MAY ISSUE ADDITIONAL COMMON UNITS WITHOUT UNITHOLDER APPROVAL, WHICH WOULD
DILUTE UNITHOLDERS' OWNERSHIP INTERESTS.
Our general partners, without the approval of our unitholders, may cause us to
issue an unlimited number of additional units, subject to the limitations
imposed by the NYSE. The issuance by us of additional common units or other
equity securities of equal or senior rank will have the following effects:
- our unitholders' proportionate ownership interest in us will decrease;
- the amount of cash available to pay distributions on each unit may
decrease;
- the relative voting strength of each previously outstanding unit may
be diminished; and
- the market price of the common units may decline.
OUR GENERAL PARTNERS AND THEIR AFFILIATES MAY COMPETE DIRECTLY WITH US AND HAVE
NO OBLIGATION TO PRESENT BUSINESS OPPORTUNITIES TO US.
Our general partners and their affiliates are not prohibited from owning assets
or engaging in businesses that compete directly or indirectly with us. ONEOK may
acquire, construct or dispose of additional midstream or other assets in the
future without any obligation to offer us the opportunity to purchase or
construct any of those assets. In addition, under our partnership agreement, the
doctrine of corporate opportunity, or any analogous doctrine, will not apply to
ONEOK and its affiliates. As a result, neither ONEOK nor any of its affiliates
has any obligation to present business opportunities to us.
OUR GENERAL PARTNERS HAVE A LIMITED CALL RIGHT THAT MAY REQUIRE UNITHOLDERS TO
SELL THEIR COMMON UNITS AT AN UNDESIRABLE TIME OR PRICE.
If at any time our general partners and their respective affiliates own more
than 80% of the common units, our general partners will have the right, but not
the obligation, which they may assign to any of their respective affiliates or
to us, to acquire all, but not less than all, of the common units held by
unaffiliated persons at a price not less than their then-current market price.
As a result, unitholders may be required to sell their common units at an
undesirable time or price and may not receive any return on their investment.
Unitholders may also incur a tax liability upon the sale of their units. Our
general partners are not obligated to obtain a fairness opinion regarding the
value of the
26
common units to be repurchased by them upon exercise of the limited call right.
There is no restriction in our partnership agreement that prevents our general
partners from issuing additional common units and exercising their call right.
If our general partners exercised their limited call right, the effect would be
to take us private and, if the units were subsequently deregistered, we would
not longer be subject to the reporting requirements of the Exchange Act.
OUR PARTNERSHIP AGREEMENT RESTRICTS THE VOTING RIGHTS OF UNITHOLDERS OWNING 20%
OR MORE OF OUR COMMON UNITS.
Our partnership agreement restricts unitholders' voting rights by providing that
any units held by a person that owns 20% or more of any class of units then
outstanding, other than our general partners and their respective affiliates,
cannot vote on any matter. The partnership agreement also contains provisions
limiting the ability of unitholders to call meetings or to acquire information
about our operations, as well as other provisions limiting the unitholders
ability to influence the manner or direction of management.
COST REIMBURSEMENTS DUE TO OUR GENERAL PARTNERS AND THEIR RESPECTIVE AFFILIATES
WILL REDUCE CASH AVAILABLE TO PAY DISTRIBUTIONS TO UNITHOLDERS.
Prior to making any distribution on the common units, we will reimburse our
general partners and their respective affiliates for all expenses they incur on
our behalf, which will be determined by our general partners. These expenses
will include all costs incurred by the general partners and their respective
affiliates in managing and operating us, including costs for rendering corporate
staff and support services to us. The reimbursement of expenses and payment of
fees, if any, to our general partners and their respective affiliates, could
adversely affect our ability to pay cash distributions to our unitholders.
UNITHOLDERS MAY NOT HAVE LIMITED LIABILITY IF A COURT FINDS THAT UNITHOLDER
ACTION CONSTITUTES CONTROL OF OUR BUSINESS. UNITHOLDERS MAY ALSO HAVE LIABILITY
TO REPAY DISTRIBUTIONS.
As a limited partner in a partnership organized under Delaware law, unitholders
could be held liable for our obligations to the same extent as a general partner
if they participate in the "control" of our business. Our general partners
generally have unlimited liability for the obligations of the partnership, such
as its debts and environmental liabilities, except for those contractual
obligations of the partnership that are expressly made without recourse to our
general partners. In addition, the Delaware Revised Uniform Limited Partnership
Act provides that, under some circumstances, a unitholder may be liable to us
for the amount of a distribution for a period of three years from the date of
the distribution. The limitations on the liability of holders of limited partner
interests for the obligations of a limited partnership have not been clearly
established in some of the other states in which we do business.
TAX RISKS
OUR TAX TREATMENT DEPENDS ON OUR STATUS AS A PARTNERSHIP FOR FEDERAL INCOME TAX
PURPOSES, AS WELL AS OUR NOT BEING SUBJECT TO ENTITY-LEVEL TAXATION BY STATES.
IF THE IRS WERE TO TREAT US AS A CORPORATION OR IF WE WERE TO BECOME SUBJECT TO
ENTITY-LEVEL TAXATION FOR STATE TAX PURPOSES, THEN OUR CASH AVAILABLE TO PAY
DISTRIBUTIONS TO UNITHOLDERS WOULD BE SUBSTANTIALLY REDUCED.
The anticipated after-tax benefit of an investment in common units depends
largely on our being treated as a partnership for federal income tax purposes.
We have not requested a ruling from the IRS with respect our classification as a
partnership for federal income tax purposes. Under current law, we are treated
as a partnership for federal income tax purposes and do not pay any income tax
at the entity level. In order to qualify for this treatment, we must derive more
than 90% of our annual gross income from specified investments and activities.
While we believe that we currently do qualify and intend to meet this income
requirement, if we should fail, we would be treated as if we were a newly formed
corporation. If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our income at the corporate tax
rate, which is currently a maximum of 35%. In addition, the entire amount of
cash received by each unitholder would generally be taxed again as a corporate
distribution when received, and no income, gains, losses, deductions or credits
would flow through to our unitholders. Because a tax would be imposed upon us as
a corporation, the cash available for distribution to our unitholders would be
substantially reduced. Thus, treatment of us as a corporation would result in a
material
27
reduction in the anticipated cash flow and after-tax return to unitholders,
likely causing a substantial reduction in the value of the common units.
Current law may change, causing us to be treated as a corporation for federal
income tax purposes or otherwise subjecting us to entity-level taxation. For
example, because of widespread state budget deficits, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, use, franchise or other forms of taxation. If any
state were to impose a tax upon us as an entity, the cash available to pay
distributions would be reduced. Our partnership agreement provides that if a law
is enacted or existing law is modified or interpreted in a manner that subjects
us to taxation as a corporation or otherwise subjects us to entity-level
taxation for federal, state or local income tax purposes, then the minimum
quarterly distribution amount and the target distribution levels will be
decreased to reflect that impact on us.
A SUCCESSFUL IRS CONTEST OF THE FEDERAL INCOME TAX POSITIONS WE TAKE MAY
ADVERSELY IMPACT THE MARKET FOR OUR COMMON UNITS, AND THE COSTS OF ANY CONTEST
WILL BE BORNE BY OUR UNITHOLDERS AND GENERAL PARTNERS.
We have not requested any ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes. The IRS may adopt positions that
differ from the federal income tax positions we take. It may be necessary to
resort to administrative or court proceedings to sustain some or all of the
positions we take. A court may not agree with some or all of the positions we
take. Any contest with the IRS may materially and adversely impact the market
for our common units and the price at which they trade. In addition, the costs
of any contest with the IRS will result in a reduction in cash available to pay
distributions to our unitholders and our general partners and thus will be borne
indirectly by our unitholders and our general partners.
A UNITHOLDER MAY BE REQUIRED TO PAY TAXES ON A SHARE OF OUR INCOME EVEN IF THE
UNITHOLDER DOES NOT RECEIVE ANY CASH DISTRIBUTIONS FROM US.
A unitholder will be required to pay federal income taxes and, in some cases,
state and local income taxes on the unitholder's share of our taxable income,
whether or not the unitholder receives cash distributions from us. A unitholder
may not receive cash distributions from us equal to the unitholder's share of
our taxable income or even equal to the actual tax liability that results from
that share of our taxable income.
THE TAXABLE GAIN OR LOSS ON THE DISPOSITION OF OUR COMMON UNITS COULD BE
DIFFERENT THAN EXPECTED.
A unitholder will recognize gain or loss on the sale of common units equal to
the difference between the amount realized and the unitholder's tax basis in
those common units. A unitholder's amount realized will be measured by the sum
of the cash or the fair market value of other property received plus the
unitholder's share of our nonrecourse liabilities. Because the amount realized
includes a unitholder's share of our nonrecourse liabilities, the gain
recognized on the sale of common units could result in a tax liability in excess
of any cash received from the sale. Prior distributions to a unitholder in
excess of the total net taxable income allocated to a unitholder for a common
unit, which decreased the tax basis in that common unit, will, in effect, become
taxable income to a unitholder if the common unit is sold at a price greater
than the tax basis in that common unit, even if the price received is less than
the original cost. A substantial portion of the amount realized, whether or not
representing gain, may be ordinary income to a unitholder.
TAX-EXEMPT ENTITIES AND FOREIGN PERSONS FACE UNIQUE TAX ISSUES FROM OWNING
COMMON UNITS THAT MAY RESULT IN ADVERSE TAX CONSEQUENCES TO THEM.
Investment in common units by tax-exempt entities, such as individual retirement
accounts, regulated investment companies known as mutual funds, and non-U.S.
persons raises issues unique to them. For example, virtually all of our income
allocated to organizations exempt from federal income tax, including individual
retirement accounts and other retirement plans, will be unrelated business
taxable income and will be taxable to them. Distributions to non-U.S. persons
will be reduced by withholding taxes at the highest applicable effective tax
rate, and non-U.S. persons will be required to file U.S. federal income tax
returns and pay tax on their share of our taxable income.
WE WILL TREAT EACH PURCHASER OF UNITS AS HAVING THE SAME TAX BENEFITS WITHOUT
REGARD TO THE UNITS PURCHASED. THE IRS MAY CHALLENGE THIS TREATMENT, WHICH COULD
ADVERSELY AFFECT THE VALUE OF THE COMMON UNITS.
28
Because we cannot match transferors and transferees of common units, we have
adopted depreciation and amortization positions that may not conform to all
aspects of existing Treasury regulations. A successful IRS challenge to those
positions could adversely affect the amount of tax benefits available to
unitholders. It also could affect the timing of these tax benefits or the amount
of gain from a unitholder's sale of common units and could have a negative
impact on the value of our common units or result in audit adjustments to a
unitholder's tax returns.
UNITHOLDERS WILL BE SUBJECT TO STATE AND LOCAL TAXES AND RETURN FILING
REQUIREMENTS AS A RESULT OF INVESTING IN OUR COMMON UNITS.
In addition to federal income taxes, unitholders will be subject to other taxes,
such as state and local income taxes, unincorporated business taxes and estate,
inheritance, or intangible taxes that are imposed by the various jurisdictions
in which we do business or own property. Unitholders will be required to file
state and local income tax returns and pay state and local income taxes in some
or all of these various jurisdictions and may be subject to penalties for
failure to comply with those requirements. We may own property or conduct
business in other states or foreign countries in the future. It is each
unitholder's responsibility to file all federal, state and local tax returns.
Some of the states in which we do business or own property may require us, or we
may elect to withhold a percentage of income from amounts to be distributed to a
unitholder who is not a resident of the state. Withholding, the amount of which
may be greater or less than a particular unitholder's income tax liability to
the state, generally does not relieve the non-resident unitholder from the
obligation to file an income tax return. Amounts withheld may be treated as if
distributed to unitholders for purposes of determining the amounts distributed
by us. Our counsel has not rendered an opinion on the state and local tax
consequences of an investment in our units.
THE SALE OR EXCHANGE OF 50% OR MORE OF OUR CAPITAL AND PROFITS INTERESTS WILL
RESULT IN THE TERMINATION OF OUR PARTNERSHIP FOR FEDERAL INCOME TAX PURPOSES.
We will be considered to have terminated for federal income tax purposes if
there is a sale or exchange of 50% or more of the total interests in our capital
and profits within a 12-month period. Our termination would, among other things,
result in the closing of our taxable year for all unitholders and could result
in a deferral of depreciation deductions allowable in computing our taxable
income.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
See Item 1, "Business-Narrative Description of Business," for a description of
our properties, their utilization, and how each property is held.
ITEM 3. LEGAL PROCEEDINGS
NORTHERN BORDER PIPELINE RATE CASE
On November 1, 2005, as required by the provisions of the settlement of Northern
Border Pipeline's 1999 rate case, Northern Border Pipeline filed a rate case
with the FERC. The rate case filing proposes a 7.8% increase to Northern Border
Pipeline's revenue requirement; a change to its rate design approach
with a supply zone and market area utilizing a fixed rate per dekatherm and a
dekatherm-mile rate, respectively; a compressor usage surcharge primarily to
recover costs related to powering electric compressors; and the implementation
of a short-term rate structure on a prospective basis. The filing also
incorporates an overall cost of capital of 10.56% based on a rate of return on
equity of 14.20%, an increase in the depreciation rate for transmission plant
from 2.25% to 2.84%, the institution of a negative salvage rate of 0.59% and a
decrease in billing determinants. Also included in the filing is the continued
inclusion of income taxes in the rate calculation. In December 2005, the FERC
issued an order that identified issues raised in the proceeding, accepted the
proposed rates but suspended their effectiveness until May 1, 2006, at which
time the new rates will be collected subject to refund until final resolution of
the rate case. The FERC also issued a procedural schedule which set a hearing
29
commencement date of October 4, 2006, with an initial decision scheduled for
February 2007, unless a settlement of the issues is reached with the FERC and a
majority of Northern Border Pipeline's customers.
F. RICHARD MANSON V. NORTHERN PLAINS NATURAL GAS COMPANY, LLC, ET AL.,
CIVIL ACTION NO. 1973-N, IN THE NEW CASTLE COUNTY CHANCERY COURT, DELAWARE.
On February 15, 2006, Northern Border Partners, L.P. and ONEOK, Inc. issued a
joint press release announcing certain transactions relating to (1) the sale of
certain assets by ONEOK to Northern Border Partners, (2) the increase of ONEOK's
general partnership interest in Northern Border Partners to 100% and (3) the
sale by Northern Border Partners of 20% of its interest in Northern Border
Pipeline Company to TC PipeLines, LP. (collectively, the "Transactions").
On March 2, 2006, a holder of limited partnership units of Northern Border
Partners, L.P. filed a class action and derivative complaint, Civil Action No.
1973-N, in the New Castle County Chancery Court in the State of Delaware, on
behalf of a putative class of all holders of limited partnership units against
Northern Border Partners, ONEOK, Northern Plains Natural Gas Company, LLC, and
related entities involved in the Transactions. The plaintiff claims the
Transactions will constitute a breach of our partnership agreement and a breach
of defendants' fiduciary duties. The plaintiff seeks to enjoin the Transactions
or to rescind the Transactions if the Transactions are completed prior to entry
of a final judgment in the case. The Plaintiff also seeks to recover on behalf
of the class damages for the profits and any special benefits obtained by the
defendants, as well as interest, costs, and attorney and expert fees. We have
not yet been served with the complaint.
Various other legal actions that have arisen in the ordinary course of business
are pending. We believe that the resolution of these issues will not have a
material adverse impact on our results of operations or financial position.
ITEM 4. SUBMISSIONS OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our equity consists of a 2% general partner interest and a 98% limited partner
interest. Our limited partner interests are represented by our common units,
which are listed on the NYSE under the trading symbol "NBP." At January 31,
2006, there were approximately 67,400 beneficial owners (held in street name)
and 1,100 holders of record of our 46,397,214 outstanding common units.
The high and low trading prices and cash distributions per common unit declared
for each quarter of fiscal 2005 and 2004 were as follows:
PRICE RANGE
------------------- CASH
HIGH LOW DISTRIBUTION
------ ------ ------------
2004
First quarter $42.60 $38.01 $0.80
Second quarter $42.60 $35.70 $0.80
Third quarter $45.81 $38.61 $0.80
Fourth quarter $49.54 $44.60 $0.80
2005
First quarter $52.99 $45.60 $0.80
Second quarter $51.13 $45.21 $0.80
Third quarter $52.35 $45.75 $0.80
Fourth quarter $48.00 $40.60 $0.80
CASH DISTRIBUTION POLICY
We are required to distribute 100% of our available cash as defined in our
partnership agreement to our general and limited partners within 45 days
following the end of each quarter. Available cash generally consists of all cash
receipts less adjustments for cash disbursements and net changes to reserves.
Our income is allocated to the general partners and limited partners according
to their respective partnership percentages of 2% and 98%, respectively, after
the effect of any incremental income allocations for incentive distributions to
the general partners. The general partners receive incentive distributions if
the quarterly cash distribution exceeds $0.605 per common unit as follows:
QUARTERLY INCENTIVE QUALIFIER INCENTIVE DISTRIBUTION
- ----------------------------- ----------------------
Cash distribution in excess of $0.605 per common unit 15% of the amount in excess of $0.605
Cash distribution in excess of $0.715 per common unit 25% of the amount in excess of $0.715
Cash distribution in excess of $0.935 per common unit 50% of the amount in excess of $0.935
30
In 2005 and 2004, we paid cash distributions of $159.6 million to our general
and limited partners, which included an incentive distribution of $8.0 million
to our general partners, each year. Additional information about our cash
distributions is included under Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations-Liquidity and Capital Resources,"
and Item 13, "Certain Relationships and Related Transactions."
On February 15, 2006, the Partnership Policy Committee announced that after we
close a series of proposed transactions, including the sale of a 20% partnership
interest in Northern Border Pipeline, Northern Plain's acquisition of
TransCanada's 0.35% general partner interest and our purchase of ONEOK's entire
gathering and processing, natural gas liquids, and pipelines and storage
segments, they intend to consider an increase in the quarterly distributions to
unitholders, which could also exceed the maximum general partner incentive
distribution target. Depending on the timing of the closing, an increase could
be included in the first quarter distribution payable in May 2006.
Additional information about the proposed transactions is included under Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations-Executive Summary."
31
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for each of the
periods indicated.
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
2005 2004 2003 (1) 2002 2001 (2)
---------- ---------- ---------- ---------- ----------
(In thousands, except per unit, other financial
and operating data)
Income data:
Operating revenue, net $ 678,560 $ 590,383 $ 550,948 $ 487,204 $ 455,997
Product purchases 167,257 103,213 80,774 50,648 39,699
Operations and maintenance 129,950 111,142 127,623 106,521 92,891
Depreciation and amortization (3) 86,010 86,431 299,791 74,672 75,424
Taxes other than income 38,575 36,212 35,443 32,194 27,863
---------- ---------- ---------- ---------- ----------
Operating income 256,768 253,385 7,317 223,169 220,120
Interest expense, net 86,903 76,943 78,980 82,898 89,908
Other income, net 28,108 19,648 23,679 15,170 258
Minority interests in net income 45,674 50,033 44,460 42,816 42,138
Income taxes 5,792 5,136 4,705 1,643 499
---------- ---------- ---------- ---------- ----------
Income (loss) from continuing
operations 146,507 140,921 (97,149) 110,982 87,833
Discontinued operations, net of tax (4) 506 3,799 9,338 2,694 (47)
Cumulative effect of change in
accounting principle, net of tax -- -- (643) -- --
---------- ---------- ---------- ---------- ----------
Net income (loss) to partners $ 147,013 $ 144,720 $ (88,454) $ 113,676 $ 87,786
========== ========== ========== ========== ==========
Per unit income (loss) from
continuing operations $ 2.92 $ 2.81 $ (2.27) $ 2.38 $ 2.12
========== ========== ========== ========== ==========
Per unit net income (loss) $ 2.93 $ 2.89 $ (2.08) $ 2.44 $ 2.12
========== ========== ========== ========== ==========
Number of units used in computation 46,397 46,397 45,370 42,709 38,538
========== ========== ========== ========== ==========
Cash flow data:
Net cash provided by operating
activities $ 267,372 $ 244,658 $ 224,660 $ 244,006 $ 233,948
Capital expenditures 59,882 43,477 30,282 50,738 126,414
Acquisition of businesses -- -- 123,194 1,561 345,074
Distribution per unit 3.20 3.20 3.20 3.20 2.99
Balance sheet data:
Property, plant and equipment, net $1,918,510 $1,941,558 $1,992,104 $2,015,280 $2,040,099
Total assets 2,527,766 2,514,690 2,570,583 2,715,936 2,687,355
Long-term debt, including current
maturities 1,354,971 1,330,358 1,415,986 1,403,743 1,423,227
Minority interests in partners' equity 274,510 290,142 240,731 242,931 250,078
Partners' equity 765,589 789,334 800,573 944,035 914,958
Other financial data:
Ratio of earnings to fixed charges (5) 3.1 3.4 0.4 2.8 2.5
32
Operating data by segment:
Interstate natural gas pipeline:
MMcf delivered 1,141,902 1,130,634 1,110,969 935,654 891,935
MMcf/d average throughput 3,204 3,166 3,147 2,636 2,605
Natural gas gathering and processing:
MMcf/d gathered 1,044 1,022 1,037 1,052 754
MMcf/d processed 64 55 52 55 54
Coal slurry pipeline:
Thousands of tons shipped 4,561 4,652 4,451 4,639 4,932
(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 (April 2001) since dates
of acquisition.
(3) Includes goodwill and asset impairment charge of $219,080 in 2003 related
to our natural gas gathering and processing business segment.
(4) In June 2003, Border Midstream sold its Gladys and Mazeppa processing
plants and related gas gathering facilities. In December 2004, Border
Midstream sold its undivided minority interest in the Gregg Lake/Obed
Pipeline.
(5) Earnings are 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 are the sum of interest expensed and
capitalized; amortized premiums, discounts and capitalized expenses related
to indebtedness; and 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 have been 3.1
for 2003.
33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with our
consolidated financial statements and accompanying notes included under Item 15.
EXECUTIVE SUMMARY
OVERVIEW
Northern Border Partners is a publicly-traded Delaware limited partnership
formed in 1993. Our common units are listed on the NYSE under the trading symbol
"NBP." Our purpose is to acquire, own and manage pipeline and other midstream
energy assets. Our equity consists of a 2% general partner interest and a 98%
limited partner interest. ONEOK is our majority general partner and holds a
combined general and limited partner interest in us of 2.71%.
We provide natural gas transportation services and are a leading transporter of
natural gas imported from Canada to the U.S. In addition, we gather, process and
compress natural gas, fractionate natural gas liquids, and transport coal
slurry. Our operations are conducted through the following three business
segments:
- Interstate Natural Gas Pipeline;
- Natural Gas Gathering and Processing; and
- Coal Slurry Pipeline.
In 2005, the interstate natural gas pipeline segment accounted for 81% of our
consolidated operating income. Operating revenue of this segment is derived
from transportation contracts under FERC-regulated tariffs. Customers with firm
service transportation agreements pay a fee known as a demand charge to reserve
pipeline capacity, regardless of use, for the term of their contracts. Firm
service transportation customers also pay a fee known as a commodity charge that
is based on the volume of natural gas they transport. Customers with
interruptible service transportation agreements may utilize available capacity
on our pipelines after firm service transportation requests are satisfied.
Interruptible service customers are assessed commodity charges only. In 2005,
97% of the interstate natural gas pipeline segment's revenue was derived from
demand charges.
The natural gas gathering and processing segment accounted for 17% of our
consolidated operating income in 2005. Operating revenue of this segment is
derived primarily from percentage-of-proceeds and fee-based contracts. Under
percentage-of-proceeds contracts, we retain a percentage of the commodities that
we gather and process in exchange for our services. We are exposed to commodity
price risk when we sell the natural gas and natural gas liquids we retain in the
open market. We use derivative instruments to mitigate our sensitivity to
fluctuations in the price of natural gas and natural gas liquids.
Information about our business, properties and strategy can be found under Item
1, "Business," and a description of our risk factors can be found under Item 1A,
"Risk Factors."
OUR BUSINESS ENVIRONMENT
A healthy long-term natural gas supply outlook is critical for our operations.
Western Canada supply trends are particularly important to us because the
majority of the natural gas we transport is produced in the Western Canada
Sedimentary Basin. We estimate that Northern Border Pipeline transported
approximately 20% of Canada's natural gas export volume in 2005. In 2005,
Canadian natural gas supplies available for export were relatively flat compared
with prior years.
Canadian natural gas supplies available for export could be impacted by the
development of oil sand reserves due to increased natural gas consumption
associated with production. Increased production of crude oil from oil sand
reserves in Canada could reduce natural gas available for export to the U.S. if
production and the related demand for natural gas are significantly greater than
supply growth. Despite this possibility, we anticipate that Canadian natural gas
supplies available for export in 2006 will be similar to 2005. Once new pipeline
projects associated with the Mackenzie Delta in Northern Canada and Alaska are
constructed, we could have access to new supply sources.
34
We gather and process unconventional natural gas produced in the Powder River
Basin and conventional natural gas in the Williston and Wind River Basins.
Unconventional natural gas differs from conventional natural gas only by its
reservoirs, which have characteristics that make production more difficult
compared with conventional natural gas reservoirs. We expect coalbed methane gas
production in the Powder River Basin to remain flat or increase moderately in
2006. We expect casinghead gas production in the Williston Basin to increase at
least through 2006 but at a slower rate of growth compared with 2005 because of
curtailment of crude oil production due to refinery outages and constraints in
crude oil pipeline shipments. This situation in the Williston Basin, which began
in late 2005, is expected to continue moderately affecting natural gas
production at least through 2006.
We serve natural gas markets in the Midwestern U.S. and provide our customers
with access to the Chicago market area, which is the third largest market area
hub in North America. Although domestic demand for natural gas is expected to
remain near 2005 levels in 2006, relatively high prices may significantly impact
natural gas supply and demand. Strong natural gas prices may lead to increased
production, supply source and market competition, and demand destruction and
volatility.
Supply competition from other sources of natural gas can adversely impact demand
for transportation on our pipelines. New supply from the Rocky Mountain region
transported by a competitor impacted demand for service on Northern Border
Pipeline at certain times during 2005 and will continue to put pressure on us
when market demand is light. In August 2005, Kinder Morgan Energy Partners, L.P.
(Kinder Morgan) and Sempra Pipelines & Storage proposed to construct a natural
gas pipeline that would transport natural gas from the Rocky Mountain region to
the upper Midwestern and Eastern U.S. In February 2006, Kinder Morgan announced
that the 1.8 Bcf/d, 1,323-mile Rockies Express Pipeline was fully subscribed.
The proposed project's interim service to the Mid-Continent region, anticipated
to begin in late 2008, may adversely impact the value of transportation service
on our pipelines which currently serve the Midwestern U.S. markets. Production
in the Wind River Basin, where we own an equity interest in a gathering system,
however, may increase as a result of the greater pipeline access the project is
expected to provide.
Temperatures in the U.S. were above normal averages from December 2004 through
November 2005, according to the NOAA National Climate Data Center. During the
first half of 2005, the market responded by increasing natural gas storage
injection activity, which resulted in natural gas in storage at levels greater
than the five-year average. With ample natural gas already in storage and the
U.S. experiencing higher than normal summer temperatures during the third
quarter of 2005, demand for Canadian natural gas increased to meet demand for
electricity. In addition, demand for natural gas from the Chicago market area
increased as a result of decreased production in the Gulf Coast region due to
infrastructure disruptions following Hurricanes Katrina and Rita. December 2005
began with unusually cold conditions across the U.S. that retreated in the last
two weeks of the year and above normal temperatures resumed in January 2006.
Natural gas storage is essential to balance natural gas supply with
temperature-driven seasonal demand. As the market gains the ability to better
align its demand with supply by utilizing natural gas storage, we anticipate
demand for transportation services will become increasingly volatile. With new
Canadian storage projects expected to go in service during 2006, we anticipate
that increased storage may reduce demand for Northern Border Pipeline's
transportation capacity during the spring and early summer months and increase
demand during the winter months.
YEAR IN REVIEW
In 2005, income from continuing operations of $146.5 million exceeded 2004
income from continuing operations by 4% due to improved results from the
gathering and processing segment and the benefit of non-recurring items which
offset decreased demand for transportation capacity on Northern Border Pipeline.
During the second quarter of 2005, increased storage injection activity of
Canadian natural gas negatively impacted demand for Northern Border Pipeline's
firm service transportation when several contracts expired. In order to maximize
revenue, Northern Border Pipeline discounted transportation rates primarily on a
short-term basis. As Western Canadian working gas in storage rose to high levels
and summer temperatures were higher than normal, demand for Northern Border
Pipeline's transportation capacity also increased. While we anticipate that
demand for Northern Border Pipeline's transportation capacity in 2006 will be
similar to 2005 demand based on our expectations of Canadian natural gas supply
and demand for natural gas in the Midwestern U.S., the level of discounting in
the future may vary from 2005 depending upon transient market conditions, which
are difficult to predict.
35
In 2005, Northern Border Pipeline accounted for 47% of our consolidated
operating revenue. The outcome of Northern Border Pipeline's rate case filed in
November 2005 could have a significant impact on our financial results because
the resulting tariff will specify the maximum rates the pipeline can charge its
customers for natural gas transportation service. In December 2005, the FERC
identified the issues raised in the proceeding and accepted the proposed rates
but suspended their effectiveness until May 1, 2006. At that time, Northern
Border Pipeline will collect the new rates, which will be subject to refund
until final resolution of the rate case following hearings conducted by the
FERC or by settlement. A change in Northern Border Pipeline's rates will not
affect earnings until final resolution with the FERC staff and a majority of our
customers is reached and subsequently approved by the FERC, which may not occur
until 2007.
We continue to seek internal growth opportunities to expand our business. We
commenced construction on several interstate natural gas pipeline projects in
2005. In September, the FERC issued a certificate of public convenience and
necessity for Northern Border Pipeline's Chicago III Expansion Project, which
will increase the pipeline's transportation capacity from Harper, Iowa to the
Chicago market area by 130 MMcf/d to 974 MMcf/d. The additional capacity is
fully subscribed for five and one-half years to ten years. The Chicago III
Expansion Project is expected to be in service in April 2006. In October,
Midwestern Gas Transmission received a positive Environmental Assessment from
the FERC for its Eastern Extension Project. The Eastern Extension Project will
extend Midwestern Gas Transmission's transportation service 31 miles into
Tennessee. The Eastern Extension Project's proposed in-service date of November
2006 will likely be delayed since the FERC's certificate of public convenience
and necessity for the project is still pending. In November, Midwestern Gas
Transmission completed its Southbound Expansion Project, which increased the
pipeline's southbound capacity by 86 MDth/d.
Our overall business strategy encompasses a focus on growth opportunities that
will balance our supply source and market risk exposures. Since 2000, our
business mix has evolved from primarily interstate pipeline transportation
service operations to our present mix, which includes 23% natural gas gathering
and processing operations based on EBITDA. Strong natural gas and natural gas
liquids prices in 2005 resulted in improved consolidated results due to our
natural gas gathering and processing segment. In August 2005, we acquired an
additional 3.7% interest in Fort Union Gas Gathering to bring our total interest
to 37%.
During 2005, several events marked the end of our relationship with Enron. In
May, our transition from CCE Holdings, through which Enron provided certain
services to ONEOK was completed. In June, Northern Border Pipeline, Crestone
Gathering and Bear Paw Energy sold their unsecured claims against Enron and
Enron North America to a third party, which sale is reflected in our operating
results. In addition, Enron was the grantor of the Enron Gas Pipeline Employee
Benefit Trust (Trust), which when taken together with the Enron Corp. Medical
Plan for Inactive Participants (Medical Plan) constituted a "voluntary
employees' beneficiary association" or VEBA under the Internal Revenue Code. The
Trust was established as a result of a regulatory requirement for the inclusion
of certain costs for post-employment medical benefits in the rates established
for the affected pipelines, including Northern Border Pipeline. In 2002, Enron
began the necessary steps to partition the assets of the Trust and the related
liabilities of the Medical Plan among all of the participating employers of the
Trust, including Northern Plains, and requested the enrolled actuary to prepare
an analysis and recommendation for the allocation of the Trust's assets and
associated liabilities. In June 2005, Enron filed an amended motion in
bankruptcy court seeking approval to terminate the Trust and to distribute its
assets among certain identified companies. If Enron's relief is granted as
requested, Northern Plains would assume retiree benefit liabilities, estimated
as of
36
November 17, 2004, of approximately $2.3 million and Trust assets of
approximately $1.7 million. Northern Natural Gas Company, a participating
employer of the Trust through June 30, 2002, along with other parties filed a
motion alleging that the allocation of assets and liabilities of the Trust
should be decided in a pending lawsuit filed in the U.S. District Court for the
District of Nebraska and not in bankruptcy court. The lawsuit filed in Nebraska
was dismissed.
On February 15, 2006, we announced a series of proposed transactions expected to
increase unitholder value and facilitate additional growth opportunities,
including the sale of a 20% partnership interest in Northern Border Pipeline to
TC PipeLines, Northern Plain's acquisition of TransCanada's 0.35% general
partner interest and our purchase of ONEOK's entire gathering and processing,
natural gas liquids, and pipelines and storage segments. Upon completion of
these transactions, ONEOK will own approximately 37.0 million of our limited
partner units, which, when combined with the general partnership interest
acquired from TransCanada, will increase their total interest in us to 45.7%. We
expect the acquisition of ONEOK's assets and the sale of a portion of our
interest in Northern Border Pipeline will be immediately accretive to our
distributable cash flow. In addition, we anticipate increasing our cash
distribution to unitholders by the end 2006 as a result of greater cash flow
associated with the additional assets. The acquisition will result in a more
diversified master limited partnership and an improved ability to fund future
growth. Additional information about the proposed transactions is included under
"Liquidity and Capital Resources," of this section, Item 1, "Business-General
Development of Business," Item 1A, "Risk Factors," Item 3, "Legal Proceedings,"
Item 5, "Market for Registrant's Common Equity Related Stockholder Matters
and Issuer Purchases of Equity Securities," and Item 13, "Certain Relationships
and Related Transactions."
We believe we are well-positioned for growth in 2006. The natural gas industry
continues to be a critical component of the energy infrastructure in the U.S. We
expect strong natural gas prices and continually improving technology will
encourage producers to replace depleted reserves with new supply sources
providing the natural gas transportation and gathering and processing sectors
with growth opportunities. Our commitment to fee-based businesses and
disciplined hedging policies will continue to be the foundation upon which we
will strive to grow our businesses and provide consistent distributions to
unitholders.
BLACK MESA
On December 31, 2005, Black Mesa's transportation contract with the coal
supplier of the Mohave Generating Station expired and our coal slurry pipeline
operations were shut down as expected. We expect the impact associated with the
shutdown will be a reduction of net income of approximately $7 million in 2006,
which includes approximately $4 million to $6 million of operations and
maintenance expense we expect to incur related to stand by costs.
Under a consent decree, the Mohave Generating Station must complete significant
pollution control investments to operate in the future. In addition, issues
surrounding the use of an alternative water source for the coal slurry pipeline
must be resolved. The original water source was an aquifer in the Navajo Nation
and Hopi Tribe joint use area. Black Mesa is working to resolve coal slurry
transportation issues and interested parties continue to negotiate water and
coal supply issues so that operations may resume in the future. If these issued
are resolved and the project receives a favorable Environmental Impact
Statement, portions of the pipeline would be modified or reconstructed to repair
normal wear related to use. If the pipeline is reconstructed, we anticipate
Black Mesa's capital expenditures for the project will be approximately $175
million to $200 million beginning in late 2008 and 2009, supported by revenue
from a new transportation contract, for an anticipated in-service date during
2010. If the Mohave Generating Station is permanently closed, we expect to incur
pipeline removal and remediation costs of approximately $1 million to $2
million, net of salvage, and a non-cash impairment charge of approximately $10
million related to the remaining undepreciated cost of the pipeline assets and
goodwill.
We may be required to take an impairment charge in accordance with GAAP prior to
final resolution of the issues concerning Mohave Generating Station even though
the project may ultimately proceed. Each quarter, we will take into
consideration our assumptions and estimates about economic conditions and the
probability of Black Mesa's future profitability. If an event or change in
circumstance occurs that potentially impacts our assumptions and estimates, we
will be required to test the assets for impairment. If our testing indicates
that the carrying amount of Black Mesa's assets exceed their fair value, we
would recognize an impairment charge. Additional information about our critical
accounting policies and estimates related to asset impairment is included under
the following sections, "Critical Accounting Estimates," and in Note 2 of the
Consolidated Financial Statements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with U.S. GAAP requires us
to make estimates and assumptions, with respect to values or conditions which
cannot be known with certainty, that affect the reported amount of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the financial
37
statements. Such estimates and assumptions also affect the reported amounts of
revenue and expenses during the reporting period. Although we believe these
estimates are reasonable, actual results could differ from our estimates. The
following summarizes our critical accounting estimates, which should be read in
conjunction with Note 2 of the Consolidated Financial Statements.
IMPAIRMENT OF GOODWILL
Goodwill represents the excess of the purchase price over the fair value of
identifiable net assets acquired. We review goodwill for possible impairment
annually and when events or changes in circumstances indicate the carrying value
of the goodwill might exceed its current fair value. An assessment is made for
each of our business segments by comparing the fair value of the business, as
determined in accordance with SFAS No. 142, "Goodwill and Other Intangible
Assets," to the book value, including goodwill, of each reporting unit. In
addition, we obtained a business valuation from an independent valuation firm of
our coal slurry pipeline segment in 2005.
If the fair value of the business is less than the book value including the
goodwill, goodwill is deemed to be impaired and we are required to perform a
second test to measure the amount of the impairment. In the second test, we
calculate the fair value of the goodwill by deducting the fair value of all
tangible and intangible net assets of the operations from the fair value
determined in step one of the assessment. If the carrying value of the goodwill
exceeds this calculated fair value of the goodwill, we will record a goodwill
impairment charge.
We determine fair value using the discounted cash flow method for each of our
business segments. This type of analysis requires us to make assumptions and
estimates regarding industry economic factors and the profitability of future
business strategies. Our assumptions and estimates are based on our current
business strategy taking into consideration present industry and economic
conditions, as well as our analysis of future expectations. Our evaluation of
our coal slurry pipeline segment incorporated an assessment of the probabilities
of permanent closure of the Mohave Generating Station. See "Executive Summary"
of this section for further discussion of Black Mesa's shutdown.
In the fourth quarter of 2005, we completed our annual impairment testing of
goodwill for each of our business segments using the methodology described
above. We determined there is no goodwill impairment. The business valuation of
the coal slurry pipeline segment we received from the independent valuation firm
concluded there was no impairment to goodwill.
If actual results differ from our assumptions and estimates, we may be exposed
to a goodwill impairment charge. At December 31, 2005, we had $339 million of
goodwill recorded on our consolidated balance sheet. At December 31, 2005,
goodwill per business segment was $71 million, $260 million and $8 million for
our interstate natural gas pipeline, natural gas gathering and processing and
coal slurry pipeline segments, respectively.
IMPAIRMENT OF LONG-LIVED ASSETS
Long-lived assets, such as property and equipment, are reviewed for impairment
when events or changes in circumstances indicate that their carrying amount may
exceed their fair value. We assess our long-lived assets for impairment based on
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
Fair values are based on the sum of the undiscounted future cash flow expected
to result from the use and eventual disposition of the assets. If the
undiscounted future cash flow is less than the carrying value of the asset, we
calculate an impairment loss. The impairment loss calculation compares the
carrying value of the asset to the asset's estimated fair value, which is based
on future discounted cash flow. If we recognize an impairment loss, the adjusted
carrying amount of the asset will be its new cost basis. For a depreciable
long-lived asset, the new cost basis will be depreciated over the remaining
useful life of that asset. Restoration of a previously recognized impairment
loss is prohibited.
We will prepare a fair value analysis when events or changes in circumstances
indicate that the carrying amount of our long-lived assets may exceed the fair
value. Management reviews our assets at the end of each reporting period to
determine if any events that would trigger asset impairment have occurred. This
type of analysis requires us to make assumptions and estimates regarding
industry economic factors and the profitability of future business strategies.
Our assumptions and estimates are based on our current business strategy, taking
into consideration
38
present industry and economic conditions as well as our analysis of future
expectations. Using the impairment review methodology described herein, we
determined there was no asset impairment in 2005.
If actual results differ from our assumptions and judgments used in estimating
future cash flow and asset fair values, we may be exposed to impairment losses
that could be material to our results of operations.
REGULATORY ASSETS
The interstate natural gas pipeline segment's accounting policies conform to
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." We
consider several factors to evaluate our continued application of the provisions
of SFAS No. 71 such as potential deregulation of our pipelines; anticipated
changes from cost-based ratemaking to another form of regulation; increasing
competition that limits our ability to recover costs; and regulatory actions
that limit rate relief to a level insufficient to recover costs. Certain assets
that result from the ratemaking process are reflected on the balance sheet as
regulatory assets. If we determine future recovery of these assets is no longer
probable as a result of discontinuing application of SFAS No. 71 or other
regulatory actions, we would be required to write off the regulatory asset at
that time. As of December 31, 2005, the interstate natural gas pipeline segment
reflected regulatory assets of $14.2 million that we expect to recover from our
customers over varying time periods up to 44 years.
CONTINGENCIES
Our accounting for contingencies covers a variety of business activities,
including contingencies for legal and environmental liabilities. We accrue these
contingencies when our assessments indicate that it is probable that a liability
has been incurred or an asset will not be recovered and an amount can be
reasonably estimated in accordance with SFAS No. 5, "Accounting for
Contingencies." We base our estimates on currently available facts and our
estimates of the ultimate outcome or resolution. Actual results may differ from
our estimates resulting in an impact, positive or negative, on earnings.
RESULTS OF OPERATIONS
SELECTED FINANCIAL RESULTS BY SEGMENT
The following table summarizes financial results by segment for the years ended
December 31, 2005, 2004 and 2003:
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------
% % %
2005 SEGMENT 2004 SEGMENT 2003 SEGMENT
-------- ------- -------- ------- --------- -------
(In thousands)
Operating revenue:
Interstate natural gas pipeline $378,701 55.8% $383,625 65.0% $ 375,256 68.1%
Natural gas gathering and processing 275,287 40.6 184,738 31.3 154,284 28.0
Coal slurry pipeline 24,572 3.6 22,020 3.7 21,408 3.9
-------- ----- -------- ----- --------- -----
Total operating revenue 678,560 100.0 590,383 100.0 550,948 100.0
-------- ----- -------- ----- --------- -----
Operating income (loss):
Interstate natural gas pipeline 214,168 81.1 231,027 87.9 212,841 91.0
Natural gas gathering and processing 44,714 16.9 28,278 10.8 (203,067) 6.8
Coal slurry pipeline 5,186 2.0 3,446 1.3 5,144 2.2
Other (7,300) -- (9,366) -- (7,601) --
-------- ----- -------- ----- --------- -----
Total operating income (loss) 256,768 100.0 253,385 100.0 7,317 100.0
-------- ----- -------- ----- --------- -----
Income (loss) from continuing operations:
Interstate natural gas pipeline 123,604 63.4 134,726 73.9 119,620 74.9
Natural gas gathering and processing 67,552 34.6 44,488 24.4 (183,016) 22.6
Coal slurry pipeline 3,902 2.0 3,088 1.7 4,092 2.6
Other (48,551) -- (41,381) -- (37,845) --
-------- ----- -------- ----- --------- -----
Total income (loss) from
continuing operations 146,507 100.0% 140,921 100.0% (97,149) 100.0%
-------- ----- -------- ----- --------- -----
Discontinued operations, net of tax 506 3,799 9,338
Cumulative effect of change in
accounting principle, net of tax -- -- (643)
-------- -------- ---------
Net income (loss) $147,013 $144,720 $ (88,454)
======== ======== =========
39
COMPARISON OF THE YEAR ENDED DECEMBER 31, 2005, WITH YEAR ENDED DECEMBER 31,
2004
CONSOLIDATED RESULTS
Operating revenue increased $88.2 million, or 15%, in 2005 compared with 2004
due to strong natural gas gathering and processing segment results which more
than offset the interstate natural gas pipeline segment's modest revenue
decline.
Operating income was relatively flat as a result of the significantly greater
contribution by the natural gas gathering and processing segment offset by
decreased operating income from the interstate natural gas pipeline segment.
Both the interstate natural gas pipeline and the natural gas gathering and
processing segments benefited from the sale of their bankruptcy claims related
to Enron and Enron North America in 2005.
Income from continuing operations increased $5.6 million, or 4%, despite higher
interest expense of $10.0 million as a result of interest rates.
Equity earnings of unconsolidated affiliates increased $6.7 million, or 37%, due
to the settlement of our preferred A shares with Bighorn Gas Gathering and
improved results from our gathering and processing joint ventures interests.
Discontinued operations included an after-tax gain of $3.6 million related to
the sale of Border Midstream's undivided interest in the Gregg Lake/Obed
Pipeline in 2004.
INTERSTATE NATURAL GAS PIPELINE SEGMENT
Income from continuing operations decreased $11.1 million, or 8%, in 2005
compared with 2004 primarily as a result of the following:
- unsold transportation capacity on Northern Border Pipeline;
- discounted transportation rates on Northern Border Pipeline; and
- increased operations and maintenance expense; partially offset by
- the sale of Northern Border Pipeline's bankruptcy claims against Enron
and Enron North America.
Operating revenue decreased $4.9 million in 2005 compared with 2004 due to
Northern Border Pipeline's decreased demand for transportation capacity. During
the second quarter of 2005, contracts for 800 MMcf/d of capacity on the Port of
Morgan, Montana to Ventura, Iowa portion of the pipeline expired. Some of this
firm transportation capacity was not sold. To maximize revenue, Northern Border
Pipeline discounted transportation rates primarily on a short-term basis and
sold most of its remaining capacity in 2005. Revenue from firm service
transportation decreased $16.2 million as a result of uncontracted and
discounted capacity. Partially offsetting this decrease, Northern Border
Pipeline recognized revenue of $9.4 million from the sale of its bankruptcy
claims for transportation contracts and associated guarantees against Enron and
Enron North America. In 2004, Northern Border Pipeline recognized revenue of
$0.9 million due to an additional day of transportation service because of the
leap year.
Operations and maintenance expense increased $9.3 million, or 18%, in 2005
compared with 2004 primarily due to the settlement or anticipated settlement of
several outstanding issues related to Enron which reduced expenses in 2004. The
resolution of our potential obligation for costs related to the termination of
Enron's cash balance plan, the settlement for certain administrative expenses
for 2002 and 2003, and an adjustment to our allowance for doubtful accounts
related to bankruptcy claims held by Northern Border Pipeline reduced expenses
by $7.2 million in 2004. In 2005, operational gas volume imbalances on Viking
Gas Transmission resulted in a $2.2 million net increase of operations and
maintenance expense.
Interest expense increased $1.1 million in 2005 compared with 2004 due to higher
average interest rates partially offset by decreased average debt outstanding.
Equity earnings of unconsolidated affiliates represent earnings from our
one-third interest in Guardian Pipeline.
Minority interests in net income represent the 30% minority interest in Northern
Border Pipeline.
NATURAL GAS GATHERING AND PROCESSING SEGMENT
Income from continuing operations increased $23.1 million, or 52%, in 2005
compared with 2004 primarily as a
40
result of the following:
- increased gathering and processing volumes in the Williston Basin;
- higher commodity prices realized on equity natural gas and natural gas
liquids derived from percentage-of-proceeds contracts;
- the sale of Bear Paw Energy and Crestone Gathering's bankruptcy claims
against Enron and Enron North America;
- the settlement of preferred A shares in Bighorn Gas Gathering; and
- increased equity earnings from our joint venture interests.
Operating revenue increased $90.6 million, or nearly 50%, in 2005 compared with
2004 due to our Williston Basin results. Williston Basin operating revenue is
derived primarily from the sale of natural gas and natural gas liquids gathered
and processed under percentage-of-proceeds contracts.
Williston Basin gathering and processing volumes increased 9 MMcf/d, or 16%, as
a result of accelerated production and drilling activity across the entire basin
driven by strong natural gas and natural gas liquids prices. The Charlie Creek
Expansion Project and Beaver Creek Expansion Project also helped to increase
volume and improve utilization at our Grasslands facility. Optimization projects
at the Grasslands and Baker facilities increased natural gas liquids recoveries.
The increased Williston Basin volumes more than offset the 9% decreased Powder
River Basin volumes related to production declines and the diversion of a
producer's volume to its own gathering lines during the year. Better prices were
also realized on our sales of natural gas and natural gas liquids retained
through percentage-of-proceeds contracts, which also contributed to the
segment's increased operating revenue. The weighted average price of natural gas
realized, net of the effects of hedging, was $6.87 per MMBtu in 2005 compared
with $4.76 per MMBtu in 2004. The weighted average price of natural gas liquids
realized, net of the effects of hedging, was $0.92 per gallon in 2005 compared
with $0.53 per gallon in 2004. Commodity sales more than offset the impact of
modestly lower gathering rates in the Powder River Basin.
Product purchases increased $64.1 million in 2005 compared with 2004. Product
purchases as a percent of operating revenue increased to 61% of operating
revenue in 2005 compared with 56% of operating revenue in 2004 due to declining
percentage-of-proceeds contract margins. Product purchases reflect the amounts
we paid to producers for raw natural gas.
Operations and maintenance expense increased $9.0 million, or 25%, in 2005
compared with 2004. Operations and maintenance expense included additional
expenses related to expansions, pipeline repairs and employee costs of $3.5
million offset by the recovery of Bear Paw Energy and Crestone Gathering's
allowance for doubtful accounts related to Enron and Enron North America of $1.2
million in 2005. In 2004, resolution of our potential obligation for costs
related to the termination of Enron's cash balance plan and an adjustment to our
allowance for doubtful accounts related to bankruptcy claims reduced expenses by
$3.7 million. We also sold two non-strategic gathering systems and compressor
equipment in the Powder River Basin and recognized a $3.4 million gain in
operations and maintenance expense in 2004.
Equity earnings of unconsolidated affiliates increased $6.1 million, or 37%, in
2005 compared with 2004. Increased volumes and transportation rates are
reflected in our equity earnings from our investments in Bighorn Gas Gathering,
Fort Union Gas Gathering and Lost Creek Gathering. Crestone Energy's acquisition
of an additional 3.7% interest in Fort Union Gas Gathering also contributed to
our equity earnings growth. We also recognized $5.4 million of equity earnings
related to our preferred A shares held in Bighorn Gas Gathering that were due to
us for 2004 and 2005 resulting from a settlement agreement with our partner in
Bighorn Gas Gathering. Provisions of the joint venture agreement provided for
cash flow incentives based on well connections to the gathering system. The
settlement agreement cancelled and effectively redeemed Bighorn Gas Gathering's
outstanding preferred A shares held by us and preferred B shares held by our
partner in Bighorn Gas Gathering and eliminated future incentives. In 2004, we
recorded $2.7 million of equity earnings related to our preferred A shares that
were due to us for 2003.
COAL SLURRY PIPELINE SEGMENT
On December 31, 2005, our coal slurry pipeline operations were shut down. We
incurred one-time termination costs of $0.7 million in the fourth quarter which
were reflected in the segment's operations and maintenance expense.
41
COMPARISON OF THE YEAR ENDED DECEMBER 31, 2004, WITH YEAR ENDED DECEMBER 31,
2003
CONSOLIDATED RESULTS
Operating revenue increased $39.4 million, or 7%, in 2004 compared with 2003 as
a result of higher interstate natural gas pipeline segment revenue due to
expired regulatory conditions and improved natural gas gathering and processing
segment results. In 2003, we recorded an impairment charge of $219.1 million
related to our natural gas gathering and processing segment's tangible assets
and goodwill. Excluding the impairment charge, operating income increased $27.0
million, or 12%, in 2004 compared with 2003 due to several Enron-related
settlements and the sale of non-strategic gathering and processing assets which
reduced expenses in 2004.
Income from continuing operations, excluding the 2003 impairment charge,
increased $19.0 million, or 16%, which included lower interest expense of $2.0
million as a result of decreased average debt outstanding.
Discontinued operations included an after-tax gain of $4.9 million related to
the sale of the Gladys and Mazeppa processing plants located in Alberta, Canada
in 2003.
INTERSTATE NATURAL GAS PIPELINE SEGMENT
Income from continuing operations increased $15.1 million, or 13%, in 2004
compared with 2003 primarily as a result of the following:
- increased revenue;
- decreased Northern Border Pipeline operations and maintenance expense;
and
- decreased Northern Border Pipeline interest expense.
Operating revenue increased $8.4 million in 2004 compared with 2003 due to
improved results from all three interstate natural gas pipelines. Northern
Border Pipeline's operating revenue increased $4.9 million primarily as a result
of expired regulatory conditions under its previous rate case settlement, which
enabled the pipeline to generate and retain $2.0 million from the sale of
short-term firm capacity and $2.0 million from new service revenue. Northern
Border Pipeline also recognized revenue of $0.9 million due to an additional day
of transportation service because of the leap year.
In 2004, Viking Gas Transmission's operating revenue was $2.1 million higher
primarily because 2003 results did not include the pipeline's revenue prior to
the pipeline's January 17, 2003 acquisition date. Midwestern Gas Transmission's
revenue included operational gas sales which increased its revenue $1.4 million
in 2004.
Operations and maintenance expense decreased $10.9 million in 2004 compared with
2003 primarily due to the settlement or anticipated settlement of several
outstanding issues related to Enron which reduced expenses in 2004, including
the resolution of costs related to the termination of Enron's cash balance plan
of $4.2 million, the settlement for certain administrative expenses for 2002 and
2003 of $1.9 million and an adjustment to our allowance for doubtful accounts
related to bankruptcy claims held by Northern Border Pipeline of $1.1 million.
Interest expense decreased $3.7 million in 2004 compared with 2003 due to
Northern Border Pipeline's lower average debt outstanding as a result of equity
contributions from its general partners that were used to repay outstanding
indebtedness.
NATURAL GAS GATHERING AND PROCESSING SEGMENT
Income from continuing operations increased $8.4 million, or 23%, in 2004
compared with 2003 excluding the effect of impairment charges that were recorded
in 2003, primarily as a result of the following:
- the sale of non-strategic assets in the Powder River Basin; and
- estimated recoveries of bankruptcy claims against Enron and Enron
North America.
In 2003, we accelerated our annual impairment testing due to lower throughput
volumes for the segment. We determined that impairment existed related to our
tangible assets and goodwill. We recorded an impairment charge of $219.1 million
as a result, which consisted of $76.0 million related to tangible assets in the
Powder River Basin and $143.1 million for goodwill related to the segment.
Operating revenue increased $30.5 million, nearly 20%, in 2004 compared with
2003 due to our Williston Basin
42
results. Gathering and processing volumes for our Williston Basin operations
increased 4 MMcf/d, or 7%, as a result of increased drilling activity due to
strong commodity prices, which partially offset lower gathering volumes in the
Powder River Basin. We also benefited from higher prices on our natural gas and
natural gas liquids. The weighted average price of natural gas realized, net of
the effects of hedging, was $4.76 per MMBtu in 2004 compared with $3.64 per
MMBtu in 2003. The weighted average price of natural gas liquids realized, net
of the effects of hedging, was $0.53 per gallon in 2004 compared with $0.43 per
gallon in 2003.
Product purchases increased $22.4 million, or 28%, in 2004 compared with 2003.
Product purchases as a percent of operating revenue increased to 56% of
operating revenue in 2004 compared with 52% of operating revenue in 2003.
Product purchases reflect the amounts we paid to producers for raw natural gas.
Operations and maintenance expense decreased $6.9 million, or 16%, in 2004
compared with 2003. In 2004, the average daily volume gathered in the Powder
River Basin was down 3% compared with 2003 due to well production declining more
than anticipated despite modest growth in drilling activity. We sold two
non-strategic gathering systems and compressor equipment in the Powder River
Basin, resulting in a $3.3 million gain which reduced operations and maintenance
expense in 2004. In addition, we renegotiated certain gathering contracts to
mitigate volumetric risk and reduce operations and maintenance expense.
Operations and maintenance expense was also reduced due to the settlement or
anticipated settlement of several outstanding issues related to Enron, including
a reduction to our allowance for doubtful accounts of $2.3 million and the
resolution of costs related to the termination of Enron's cash balance plan of
$1.5 million.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW
Our principal sources of liquidity include cash generated from operating
activities and bank credit facilities. We fund our operating expenses, debt
service and cash distributions to limited and general partners primarily with
operating cash flow.
Capital resources for acquisitions and maintenance and growth expenditures are
funded by a variety of sources, including cash generated from operating
activities, borrowings under bank credit facilities, issuance of senior
unsecured notes or sale of additional limited partner interests. Our ability to
access capital markets for debt and equity financing under reasonable terms
depends on our financial condition, credit ratings and market conditions.
We believe that our ability to obtain financing at reasonable rates and our
history of consistent cash flow from operating activities provide a solid
foundation to meet our future liquidity and capital resource requirements.
SHORT-TERM LIQUIDITY
We use cash from operating activities and bank credit facilities as our primary
sources of short-term liquidity.
In May 2005, we entered into a $500 million five-year revolving credit agreement
with certain financial institutions. Under this agreement, we borrowed $186
million to pay the outstanding balance of our existing $275 million revolving
credit agreement and terminated that agreement. At our option, the interest rate
on the outstanding borrowings may be the lender's base rate or the London
Interbank Offered Rate (LIBOR) plus a spread that is based on our long-term
unsecured debt ratings. We are required to comply with certain financial,
operational and legal covenants, including the maintenance of an EBITDA (net
income plus minority interests in net income, interest expense, income taxes and
depreciation and amortization) to interest expense ratio of greater than 3 to 1
and a debt to adjusted EBITDA (EBITDA adjusted for pro forma operating results
of acquisitions made during the year) ratio of no more than 4.75 to 1. If we
consummate one or more acquisitions that exceed $25 million in total purchase
price, the allowable ratio of debt to adjusted EBITDA is increased to 5.25 to 1
for two calendar quarters following the acquisition. If we breach any of these
covenants, amounts outstanding may become due and payable immediately.
Also in May 2005, Northern Border Pipeline entered into a $175 million five-year
revolving credit agreement with certain financial institutions. Under this
agreement, Northern Border Pipeline borrowed $29 million to pay the outstanding
balance on its existing $175 million revolving credit agreement and terminated
that agreement. Similar to our revolving credit agreement, Northern Border
Pipeline may select the lender's base rate or the LIBOR plus a
43
spread that is based on Northern Border Pipeline's long-term unsecured debt
ratings as the interest rate on the loan. Northern Border Pipeline is required
to comply with certain financial, operational and legal covenants, including the
maintenance of an EBITDA to interest expense ratio of greater than 3 to 1 and a
debt to adjusted EBITDA ratio of no more than 4.5 to 1. If Northern Border
Pipeline consummates one or more acquisitions that exceed $25 million in total
purchase price, the allowable ratio of debt to adjusted EBITDA is increased to 5
to 1 for two calendar quarters following the acquisition. If Northern Border
Pipeline breaches any of these covenants, amounts outstanding may become due and
payable immediately.
The fair value of our variable rate debt is approximately the carrying value
since the interest rates are periodically adjusted to reflect current market
conditions. At December 31, 2005, our outstanding borrowings under our credit
agreement were $204 million and we were in compliance with the covenants of our
agreement. The average interest rate on our debt at December 31, 2005, was
5.18%. At December 31, 2005, Northern Border Pipeline's outstanding borrowings
under its credit agreement were $27 million and they were in compliance with the
covenants of their agreement. The average interest rate on Northern Border
Pipeline's debt at December 31, 2005, was 5.11%.
LONG-TERM FINANCING
On February 15, 2006, we announced a series of transactions that will involve
long-term financing. Information about the proposed transactions is included
under "Executive Summary" of this section.
DEBT SECURITIES
We periodically issue long-term debt securities to meet our capital resource
requirements. All of our outstanding debt securities are senior unsecured notes
with similar terms except for interest rates, maturity dates and prepayment
premiums. As of December 31, 2005, the total liability on our outstanding senior
notes was $1,104 million.
Our senior note issuances of $250 million due in 2010 and $225 million due in
2011 are borrowed at fixed interest rates of 8.875% and 7.10%, respectively. The
indentures of the notes do not limit the amount of unsecured debt we may incur,
but they do contain material financial covenants, including restrictions on
incurrence, assumption or guarantee of secured indebtedness. The indentures also
contain provisions that require us to offer to repurchase the notes at par value
if either Standard & Poor's Rating Services or Moody's Investor Services
rate the notes below investment grade and the investment grade rating is not
reinstated for a period of 40 days. At December 31, 2005, the aggregate fair
value of the notes was approximately $499 million. In 2005, the interest expense
related to our outstanding senior notes was $38.2 million.
Northern Border Pipeline's senior notes issuances of $150 million due in 2007,
$200 million due in 2009 and $250 million due in 2021 are borrowed at fixed
interest rates of 6.25%, 7.75% and 7.50%, respectively. The indentures of the
notes do not limit the amount of unsecured debt we may incur but contain
material financial covenants, including the restriction of secured indebtedness.
At December 31, 2005, the aggregate fair value of the notes was approximately
$637 million. In 2005, interest expense related to Northern Border Pipeline's
senior notes was $43.6 million. In 2004, Northern Border Pipeline redeemed $75
million of the $225 million principal amount outstanding of its senior notes due
in 2007.
Viking Gas Transmission has four series of senior note issuances outstanding.
Interest payments for the senior notes due between 2011 and 2014 are paid
quarterly and the principal payment is due at maturity. We pay interest and
principal payments monthly for the senior notes due in 2008. Under the
indentures of the notes, we are the guarantor as security for payment. At
December 31, 2005, the aggregate fair value of the notes was approximately $32
million. In 2005, the interest expense related to Viking Gas Transmission's
senior notes was $2.2 million.
EQUITY ISSUANCES
In May and June 2003, we sold 2,587,500 common units. According to our
partnership agreement, the general partners are required to make capital
contributions in conjunction with the issuance of additional common units to
maintain a 2% general partner interest. The net proceeds from the sale of common
units and the general partners' capital contributions of $102.2 million were
used primarily to repay outstanding debt.
44
CASH FLOW FROM OPERATING, INVESTING AND FINANCING ACTIVITIES
OPERATING ACTIVITIES
Cash provided by operating activities increased $22.7 million, or 9%, in 2005
compared with 2004 primarily as a result of the following:
- increased earnings from the natural gas gathering and processing
segment;
- the sale of bankruptcy claims against Enron and Enron North America;
- receipt of cash flow incentives due to us for 2005 through our
ownership of preferred A shares in Bighorn Gas Gathering; and
- decreased payment in 2005 compared with 2004 related to Northern
Border Pipeline's settlement with respect to right-of-way lease and
taxation issues with the Fort Peck Tribes. Northern Border Pipeline
paid the Fort Peck Tribes $7.4 million as part of the settlement in
2004 and an option payment of approximately $1.5 million in 2005.
The increased inflow of cash in 2005 was partially offset by the following:
- decreased earnings from the interstate natural gas pipeline segment as
a result of unsold and discounted capacity on Northern Border
Pipeline; and
- increased interest expense.
Cash provided by operating activities increased $20.0 million, or 9%, in 2004
compared with 2003 due to higher operating revenue and lower interest expense.
Northern Border Pipeline's initial payment related to the settlement with
respect to right-of-way lease and taxation issues with the Fort Peck Tribes was
partially offset by the release of restricted funds previously required on
deposit for Viking Gas Transmission's debt service.
INVESTING ACTIVITIES
Cash used for investing activities was $68.4 million in 2005 compared with $20.9
million in 2004 primarily due to increased interstate natural gas pipeline
segment capital expenditures in 2005 and the sale of gathering and processing
assets in 2004. We fund our investing activities primarily with operating cash
and borrowings under our credit facilities. In 2005 and 2004, maintenance and
growth capital expenditures, and investments in unconsolidated affiliates for
the interstate natural gas pipeline and natural gas gathering and processing
segments were as follows:
INTERSTATE NATURAL GAS PIPELINE SEGMENT ($ MILLIONS) 2005 2004
- ---------------------------------------------------- ----- -----
Maintenance Capital Expenditures $23.4 $15.9
Growth Capital Expenditures 16.3 0.3
----- -----
Total $39.7 $16.2
===== =====
NATURAL GAS GATHERING AND PROCESSING SEGMENT ($ MILLIONS) 2005 2004
- --------------------------------------------------------- ----- -----
Maintenance Capital Expenditures $ 2.3 $ 3.4
Growth Capital Expenditures 22.8 22.1
----- -----
Total $25.1 $25.5
===== =====
Consolidated maintenance capital expenditures increased $8.4 million in 2005
compared with 2004 primarily due to pipeline replacements and compressor station
overhauls by Northern Border Pipeline. Growth capital expenditures increased
$16.7 million in 2005 compared with 2004 primarily due to the following
interstate natural gas pipeline segment projects:
2005
INTERSTATE NATURAL EXPENDITURES
GAS PIPELINE SYSTEM EXPANSION PROJECT ($ MILLIONS)
- ------------------- --------------------- ------------
Northern Border Pipeline Chicago III Expansion $10.4
Midwestern Gas Transmission Southbound Expansion $ 2.4
Midwestern Gas Transmission Eastern Extension $ 2.9
Growth capital expenditures for the natural gas gathering and processing segment
included investments in unconsolidated affiliates of $8.5 million in 2005.
Crestone Energy increased its investment in Fort Union Gas
45
Gathering and acquired an additional 3.7% interest for $5.1 million.
Contributions to Bighorn Gas Gathering were $3.4 million.
In 2004, we sold our undivided minority interest in the Gregg Lake/Obed Pipeline
for $14.0 million and two gathering systems in the Powder River Basin for $8.7
million. In 2003, we acquired Viking Gas Transmission for $123.2 million and
sold the Gladys and Mazeppa processing plants for $40.3 million. Capital
contributions of $3.5 million in 2003 primarily represented amounts made to
Guardian Pipeline to fund additional expenditures related to the construction of
the pipeline that was completed in December 2002.
FINANCING ACTIVITIES
Cash provided by financing activities was $189.8 million in 2005 compared with
$225.7 million in 2004. In 2005, borrowings under our and Northern Border
Pipeline's revolving credit agreements were primarily used to repay amounts
borrowed under our and Northern Border Pipeline's previously existing credit
agreements. Total borrowings in 2005 were $165.0 million and debt repayments
were $130.2 million. We also paid $2.8 million to terminate forward-starting
interest rate swaps and distributions of $159.6 million to our general partners
and unitholders in 2005.
In 2004, we borrowed $152.0 million under our credit agreement. Northern Border
Pipeline borrowed $107.0 million under its credit agreement and received an
equity contribution of $61.5 million from its minority interest holder. Northern
Border Pipeline also terminated interest rate swap agreements with a total
notional amount of $225 million and received $7.6 million. We and Northern
Border Pipeline used the cash to repay $327.5 million of debt, which included
the $75 million redemption of Northern Border Pipeline's senior notes due in
2007, and the related $4.8 million premium. In 2004, the Northern Border
Management Committee approved a change to its cash distribution policy to equal
100% of its distributable cash flow based on earnings before interest, taxes,
depreciation and amortization less interest expense and maintenance capital
expenditures which increased distributions to its minority interest holder by
$15.5 million compared with 2003.
In 2003, we borrowed $200.0 million under our credit agreement and Northern
Border Pipeline borrowed $142.0 million under its credit agreement. We issued
2.6 million additional common units which raised $102.2 million. We also
terminated interest rate swap agreements with a total notional amount of $75
million and received $12.3 million. We used the cash to fund the $123.2 million
Viking Gas Transmission acquisition and repay $361.1 million of debt.
CAPITAL EXPENDITURES
We will continue to make capital expenditures for acquisitions, new development
projects, and maintenance and growth activities. We intend to finance our
capital expenditures, either separately or in combination, with cash generated
from operating activities, borrowings under our bank credit facilities, issuance
of senior notes or the sale of additional limited partner interests.
In 2006, we expect to invest in our currently existing businesses approximately
$94 million for capital expenditures and investments in unconsolidated
affiliates by segment as follows:
2006 PROJECTED
SEGMENT ($ MILLIONS) MAINTENANCE GROWTH EXPENDITURES
- -------------------- ----------- ------ -------------
Interstate Natural Gas Pipeline $21 $38 $59
Natural Gas Gathering and Processing 4 28 32
Other 3 -- 3
We expect to invest approximately $50 million in 2006 for the following
significant growth projects:
2006 ESTIMATED
EXPENDITURES
SUBSIDIARY EXPANSION PROJECT ($ MILLIONS)
- ---------- ----------------- -------------
Midwestern Gas Transmission Eastern Extension $25
Bear Paw Energy Williston Basin Expansions 15
Northern Border Pipeline Chicago III Expansion 10
46
PROPOSED TRANSACTIONS
On February 15, 2006, we announced a series of proposed transactions, including
the sale of a 20% partnership interest in Northern Border Pipeline to TC
PipeLines, Northern Plain's acquisition of TransCanada's 0.35% general partner
interest and our purchase of ONEOK's entire gathering and processing, natural
gas liquids, and pipelines and storage segments. We expect to initially fund the
$1.35 billion cash portion of the ONEOK asset acquisition with proceeds from the
sale of a 20% interest in Northern Border Pipeline of $300 million and bridge
financing. The bridge financing is expected to consist of borrowings under a
364-day bank credit facility, which is under negotiation with certain banks. We
expect to repay these borrowings with proceeds from the issuance of long-term
debt securities in 2006. The remainder of the ONEOK asset acquisition will be
funded with the issuance of 36.5 million Class B units. The newly created units
will carry the same distribution rights as our outstanding common units but will
be subordinated related to cash distributions to the common units and will have
limited voting rights. The Class B units' cash distribution will be prorated
from the date of issuance.
We will hold a special election for holders of common units as soon as
practical, but within 12 months of issuing the Class B units, to approve the
conversion of the Class B units into common units and certain amendments to our
partnership agreement. If the common unitholders do not approve the conversion
and amendments, the Class B unit distribution rights will increase to 115% of
the distributions paid on the common units. Additional information about the
proposed transactions is included under "Executive Summary" of this section.
COMMITMENTS
CONTRACTUAL OBLIGATIONS
Our contractual obligations related to debt, capital and operating leases and
other long-term obligations as of December 31, 2005, included the following:
PAYMENTS DUE BY PERIOD
--------------------------------------------------------------
LESS THAN 1 MORE THAN 5
TOTAL YEAR 1-3 YEARS 4-5 YEARS YEARS
---------- ----------- --------- --------- -----------
(In thousands)
Northern Border Pipeline:
6.25% senior notes due 2007 $ 150,000 $ -- $150,000 $ -- $ --
7.75% senior notes due 2009 200,000 -- -- 200,000 --
7.50% senior notes due 2021 250,000 -- -- -- 250,000
$175 million credit agreement due
2010, average 5.11% 27,000 -- -- 27,000 --
Viking Gas Transmission:
Series A, B, C and D senior notes
due 2008 to 2014, average 7.48% 28,987 2,133 3,912 -- 22,942
Northern Border Partners:
8.875% senior notes due 2010 250,000 -- -- 250,000 --
7.10% senior notes due 2011 225,000 -- -- -- 225,000
$500 million credit agreement due
2010, average 5.18% 204,000 -- -- 204,000 --
Interest payments on debt 563,768 84,647 153,247 116,713 209,161
Capital leases 61 61 -- -- --
Operating leases 80,176 3,788 6,842 4,697 64,849
Other long-term obligations 49,776 11,659 23,351 14,766 --
---------- -------- -------- -------- --------
Total contractual obligations $2,028,768 $102,288 $337,352 $817,176 $771,952
========== ======== ======== ======== ========
Operating Leases - We are required to make future minimum payments for office
space, pipeline equipment, rights-of-way and vehicles under non-cancelable
operating leases.
47
Other Long-Term Obligations - Crestone Energy's firm transportation agreements
with Fort Union Gas Gathering and Lost Creek Gathering require minimum monthly
payments.
We guarantee the performance of certain of our unconsolidated affiliates in
connection with credit agreements that expire in March 2009 and September 2009.
The collective amount of the guarantees was $4.4 million at December 31, 2005.
CASH DISTRIBUTIONS
We distribute 100% of our available cash, which generally consists of all cash
receipts less adjustments for cash disbursements and net change to reserves, to
our general and limited partners. Our income is allocated to the general
partners and limited partners according to their respective partnership
percentages of 2% and 98%, respectively, after the effect of any incremental
income allocations for incentive distributions to the general partners.
In each of 2005 and 2004, we paid $148.5 million to our common unitholders and
$11.2 million to our general partners for their general partner and incentive
distribution interests. In 2003, we paid $144.3 million to our common
unitholders and $10.8 million to our general partners for their general partner
and incentive distribution interests.
On February 14, 2006, we paid quarterly cash distributions of $0.80 per unit on
all outstanding units. We paid $37.1 million to our common unitholders and
approximately $2.8 million to our general partners for their general partner and
incentive distribution interests.
Additional information about our cash distributions is included under Item 5,
"Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities," and Item 13, "Certain Relationships and Related
Transactions."
CONTINGENCIES
LEGAL
On November 1, 2005, as required by the provisions of the settlement of Northern
Border Pipeline's 1999 rate case, Northern Border Pipeline filed a rate case
with the FERC. Information about the rate case is included under Item 3, "Legal
Proceedings."
ENVIRONMENTAL
Our operations are subject to extensive federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to the protection of the environment. Failure to comply with
these laws and regulations can result in substantial penalties, enforcement
actions and remedial liabilities.
Dunavan Superfund Site - In July 2005, the U.S. EPA notified Midwestern Gas
Transmission and several other non-affiliated parties of possible liability
pursuant to the Comprehensive Environmental Response, Compensation and Liability
Act and requested information related to the Dunavan Oil Site located in
Oakwood, Illinois. The EPA identified Midwestern Gas Transmission as possibly
transporting and disposing of used oil at the contaminated site and classified
Midwestern Gas Transmission as a de minimis party. We believe costs related to
resolving this matter will not materially impact our results of operations or
financial position.
Nitrogen Oxides State Implementation Plan - In September 2005, the Illinois EPA
distributed a draft of a rule to control nitrogen oxide emissions from
reciprocating engines and turbines state-wide by January 1, 2009, to mitigate
ground level ozone. Under this rule, the state would require the installation of
necessary controls to comply with EPA rules regarding the Nitrogen Oxides State
Implementation Plan Call, ozone non-attainment and fine particulate standards.
Midwestern Gas Transmission participated in several stakeholder meetings to
provide comments concerning the draft rule. Another draft of the rule is
expected to be distributed before it is submitted to the Illinois Pollution
Control Board. As currently drafted, the rule affects five Midwestern Gas
Transmission engines in Illinois and preliminary cost estimates for the required
emission controls are less than $5 million.
48
RECENT ACCOUNTING PRONOUNCEMENTS
The FASB recently issued SFAS No. 123R, "Share-Based Payment" and Interpretation
47, "Accounting for Conditional Asset Retirement Obligations-an interpretation
of FASB Statement No. 143." In addition, the FERC issued guidance related to
accounting for pipeline integrity costs. Additional information about these
accounting pronouncements is included in Note 15 of the Consolidated Financial
Statements.
FORWARD-LOOKING STATEMENTS
The statements in this annual report that are not historical information,
including statements concerning plans and objectives of management for future
operations, economic performance or related assumptions, are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Exchange Act. Forward-looking statements may include words
such as "anticipate," "estimate," "expect," "project," "intend," "plan,"
"believe," "should" and other words and terms of similar meaning. Although we
believe that our expectations regarding future events are based on reasonable
assumptions, we can give no assurance that our goals will be achieved. Important
factors that could cause actual results to differ materially from those in the
forward-looking statements include:
- the impact of unsold capacity on Northern Border Pipeline being
greater or less than expected;
- the ability to market pipeline capacity on favorable terms, which is
affected by:
- future demand for and prices of natural gas;
- competitive conditions in the overall natural gas and electricity
markets;
- availability of supplies of Canadian and U.S. natural gas;
- availability of additional storage capacity;
- weather conditions; and
- competitive developments by Canadian and U.S. natural gas
transmission peers;
- final orders by the FERC which adversely impact changes requested in
Northern Border Pipeline's November 2005 rate case;
- performance of contractual obligations by our customers;
- the ability to recover operating costs, costs of property, plant and
equipment and regulatory assets in our FERC-regulated rates;
- timely receipt of approval by the FERC for construction and operation
of Midwestern Gas Transmission's Eastern Extension Project and
required regulatory clearances; our ability to acquire all necessary
rights-of-way and obtain agreements for interconnects in a timely
manner; and our ability to promptly obtain all necessary materials and
supplies required for construction;
- rate of development, well performance and competitive conditions near
our natural gas gathering systems in the Powder River and Williston
Basins and our investments in the Powder River and Wind River Basins;
- prices of natural gas and natural gas liquids;
- composition and quality of the natural gas we gather and process in
our plants;
- impact on drilling and production by factors beyond our control,
including the demand for natural gas and refinery-grade crude oil;
producers' desire and ability to obtain necessary permits; reserve
performance; and capacity constraints on the pipelines that transport
natural gas, crude oil and natural gas liquids from producing areas
and our facilities;
- efficiency of our plants in processing natural gas and extracting
natural gas liquids;
- renewal of the coal slurry pipeline transportation contract under
reasonable terms and our success in completing the necessary
reconstruction of the coal slurry pipeline;
- impact of potential impairment charges;
- developments in the December 2, 2001, filing by Enron of a voluntary
petition for bankruptcy protection under Chapter 11 of the U.S.
Bankruptcy Code affecting our settled claims;
- ability to control operating costs;
- conditions in the capital markets and our ability to access the
capital markets;
- risks inherent in the use of information systems in our respective
businesses, implementation of new software and hardware, and the
impact on the timeliness of information for financial reporting;
49
- our ability to consummate the acquisition of the ONEOK subsidiaries,
which could adversely affect our business, financial condition and
results of operations; our ability to successfully integrate the
operations of ONEOK with our current operations; the dilution of our
current unitholders' ownership interests upon issuance of units to
ONEOK in connection with the acquisition; and
- acts of nature, sabotage, terrorism or other similar acts causing
damage to our facilities or our suppliers' or shippers' facilities.
These factors are not necessarily all of the important factors that could cause
actual results to differ materially from those expressed in any of our
forward-looking statements. Other factors could also have material adverse
effects on our future results. These and other risks are described in greater
detail under Item 1A, "Risk Factors." All forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by these factors. Other than as required under securities laws,
we undertake no obligation to update publicly any forward-looking statement
whether as a result of new information, subsequent events or change in
circumstances, expectations or otherwise.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
OVERVIEW
Our exposure to market risk discussed below includes forward-looking statements
and represents an estimate of possible changes in future earnings that would
occur assuming hypothetical future movements in interest rates or commodity
prices. Our views on market risk are not necessarily indicative of actual
results that may occur and do not represent the maximum possible gains and
losses that may occur, since actual gains and losses will differ from those
estimated, based on actual fluctuations in interest rates or commodity prices
and the timing of transactions.
We are exposed to market risk due to interest rate and commodity price
volatility. Market risk is the risk of loss arising from adverse changes in
market rates and prices. We utilize financial instruments, including forwards,
swaps, collars and futures to manage the risks of certain identifiable or
anticipated transactions and achieve a more predictable cash flow. Our risk
management function follows established policies and procedures to monitor
interest rates and natural gas and natural gas liquids marketing activities to
ensure our hedging activities mitigate market risks. We do not use financial
instruments for trading purposes.
In accordance with SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," we record financial instruments on the balance sheet as
assets and liabilities based on fair value. We estimate the fair value of
financial instruments using available market information and appropriate
valuation techniques. Changes in financial instruments' fair value are
recognized in earnings unless the instrument qualifies as a hedge under SFAS No.
133 and meets specific hedge accounting criteria. Qualifying financial
instruments' gains and losses may offset the hedged items' related results in
earnings for a fair value hedge or be deferred in accumulated other
comprehensive income for a cash flow hedge.
INTEREST RATE RISK
We utilize both fixed- and variable-rate debt and are exposed to market risk due
to the floating interest rates on our credit facilities. We regularly assess the
impact of interest rate fluctuations on future cash flows and evaluate hedging
opportunities to mitigate our interest rate risk.
FAIR VALUE HEDGES - INTEREST RATE SWAPS
We maintain a significant portion of our debt at fixed rates to reduce our
sensitivity to interest rate fluctuations and utilize interest rate swap
agreements to convert fixed-rate debt to variable-rate debt to manage interest
expense. Our interest rate swap agreements are designated as fair value hedges
under SFAS No. 133 because they mitigate fluctuations in the market value of the
underlying fixed-rate debt. Under these agreements, we pay counterparties
variable interest rates based on LIBOR and receive interest payments based on
the senior notes' fixed rate.
50
EFFECTIVE NOTIONAL
HEDGED FIXED-RATE DEBT PERIOD COVERED BY SWAP INTEREST RATE AMOUNT
- ---------------------- -------------------------- ------------- -----------
Senior Notes, 7.10% fixed rate, January 2005 to March 2011 6.32% $75 million
due March 2011
Senior Notes, 7.10% fixed rate, January 2005 to March 2011 6.80% $75 million
due March 2011
As of December 31, 2005, the fair value of our hedges in effect was a liability
of $2.4 million. Consolidated interest expense for 2005 reflected a $1.0
million benefit from these swap agreements.
If interest rates hypothetically increased 1% compared with rates in effect as
of December 31, 2005, our annual consolidated interest expense would increase
and our consolidated income before income taxes would decrease by approximately
$3.8 million.
CASH FLOW HEDGES - FORWARD-STARTING INTEREST RATE SWAPS
In December 2004, we entered into forward-starting interest rate swap agreements
with a total notional amount of $100 million in anticipation of a ten-year
senior note issuance. We paid $2.7 million to counterparties when the swap
agreements expired in late May and early June of 2005. In June 2005, we entered
into a Treasury lock interest rate agreement with a total notional amount of
$200 million, which expired in July 2005 at which time we paid $0.1 million to
the counterparty. As of December 31, 2005, there were no forward-starting
interest rate swap agreements outstanding.
COMMODITY PRICE RISK
Our interstate natural gas pipelines generally are not exposed to commodity
price risk because they do not own the natural gas they transport. Northern
Border Pipeline and Viking Gas Transmission own the natural gas necessary to
maintain efficient pipeline operations and shippers provide the natural gas
necessary to operate the compressor stations. Midwestern Gas Transmission
collects a fixed amount of natural gas for its operations. When the amount of
natural gas utilized by Midwestern Gas Transmission differs from the amount
provided by its shippers, the pipeline must buy or sell natural gas and is
exposed to commodity price risk.
Bear Paw Energy receives a significant portion of its revenue from the sale of
commodities in exchange for gathering and processing services and is exposed to
market risk due to its sensitivity to natural gas and natural gas liquids
prices. To reduce our exposure to natural gas and natural gas liquids price
volatility, we enter into commodity financial instruments, including price swaps
and collars, which are designated as cash flow hedges.
In 2005, we entered into a limited number of commodity financial instruments to
manage our earnings on equity natural gas and natural gas liquids. Our equity
volumes for 2005 were hedged as follows:
2005 WEIGHTED
AVERAGE AVERAGE HEDGE
HEDGED COMMODITY HEDGED VOLUME PRICE PER UNIT
- ---------------- ------------- --------------
Natural Gas (in MMBtu/d) 5,500 $7.15
Natural Gas Liquids (in gallons/d) 65,600 $0.92
As of January 31, 2006, our projected natural gas and natural gas liquids
volumes were hedged for 2006 as follows:
2006 2006 WEIGHTED
PROJECTED EQUITY AVERAGE AVERAGE HEDGE
HEDGED COMMODITY VOLUME RANGE HEDGED VOLUME PRICE PER UNIT
- ---------------- ----------------- ------------- ----------------
Natural Gas (in MMBtu/d) 11,000 - 12,400 7,300 $8.08
Natural Gas Liquids (in gallons/d) 101,400 - 122,500 49,500 $1.01
Our natural gas is hedged based on pricing indexes at Colorado Interstate Gas
(CIG) and Northern Natural Gas (NNG) Ventura. Our natural gas liquids are hedged
based on pricing indexes at Conway and Koch West Texas Intermediate (WTI).
51
If the weighted average price of natural gas hypothetically decreased $1.00 per
MMBtu compared with the price at December 31, 2005, annual net income would
decrease approximately $4.4 million based on our projected 2006 volumes as of
January 31, 2006. If the weighted average price of natural gas liquids
hypothetically decreased $0.10 per gallon compared with the price in effect as
of December 31, 2005, annual net income would decrease approximately $4.3
million based on our projected 2006 volumes as of January 31, 2006.
Additional information about our financial instruments is included in Note 9 of
the Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth in
the "Index to Financial Statements" on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
The Partnership's principal executive officer and principal financial officer
have evaluated the effectiveness of the Partnership's "disclosure controls and
procedures," (as such term is defined in Exchange Act Rule 13a-15(e) or
15d-15(e)) as of the end of the period covered by this annual report. Based upon
their evaluation, the principal executive officer and principal financial
officer concluded that the Partnership's disclosure controls and procedures are
effective.
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Partnership's principal executive officer and principal financial officer
are responsible for establishing and maintaining adequate internal control over
financial reporting for the Partnership. The Partnership's internal control
system was designed to provide reasonable assurance to the Partnership's
management and members of the Partnership's Policy Committee and Audit Committee
regarding the fair presentation of published financial statements. All internal
control systems, no matter how well designed, have inherent limitations.
Therefore, even those systems determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and
presentation.
The Partnership's management assessed the effectiveness of the Partnership's
internal control over financial reporting as of December 31, 2005. In making
this assessment, it used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in Internal Control-Integrated
Framework. Based on the assessment, the Partnership's management believes that,
as of December 31, 2005, the Partnership's internal control over financial
reporting is effective based on those criteria.
The Partnership's independent registered public accounting firm has issued an
attestation report on management's assessment of the Partnership's internal
control over financial reporting. This report appears in the Report of
Independent Registered Public Accounting Firm below.
/s/ WILLIAM R. CORDES
----------------------------------------
William R. Cordes
Chief Executive Officer
/s/ JERRY L. PETERS
----------------------------------------
Jerry L. Peters
Chief Financial and Accounting Officer
52
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Northern Border Partners, L.P.:
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that Northern
Border Partners, L.P. maintained effective internal control over financial
reporting as of December 31, 2005, based on criteria established in Internal
Control--Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our opinion, management's assessment that Northern Border Partners, L.P.
maintained effective internal control over financial reporting as of December
31, 2005 is fairly stated, in all material respects, based on COSO. Also, in our
opinion, Northern Border Partners, L.P. maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2005,
based on COSO.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheets of
Northern Border Partners, L.P. and subsidiaries as of December 31, 2005 and
2004, and the related consolidated statements of income, comprehensive income,
cash flows, and changes in partners' equity for each of the years in the
three-year period ended December 31, 2005, and our report thereon dated March 2,
2006 expressed an unqualified opinion on those consolidated financial
statements.
/s/ KPMG LLP
Omaha, Nebraska
March 2, 2006
53
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in our internal control over financial reporting that
occurred during our last fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting. In the quarter ended December 31, 2005, however, we began
implementing a new contracting and billing system to support the natural gas
gathering and processing segment. The new system will automate certain
transactional processes, including scheduling, plant allocations and invoicing,
that are currently handled manually. Implementation is scheduled for April 2006.
In conjunction with Northern Border Pipeline's rate case, we will complete
system modifications to meet the proposed new transportation billing
requirements. Implementation is scheduled for May 2006. These two activities
will cause changes to our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
On January 19, 2006, the Board of Directors of ONEOK granted restricted stock
units and performance units under ONEOK's Equity Compensation Plan to our Chief
Executive Officer, William R. Cordes and our Chief Financial and Accounting
Officer, Jerry L. Peters, as well as the following persons that have been
designated as officers for purposes of Section 16 of the Exchange Act: Paul F.
Miller, Raymond D. Neppl, Janet K. Place, Gaye Lynn Schaffart, Christopher R
Skoog, Michel E. Nelson and Pierce H. Norton. The restricted stock units vest
three years from the date of grant at which time the grantee is entitled to
shares of ONEOK common stock. The performance units granted vest three years
from the date of grant at which time the holder is entitled to receive a
percentage (0% to 200%) of the performance shares granted based on ONEOK's total
shareholder return over the period January 19, 2006, to January 19, 2009,
compared to the total shareholder return of a peer group of 20 other companies.
The grant is payable in shares of ONEOK common stock. In addition, our executive
officers participate in the ONEOK Employee Stock Purchase Plan. These plans and
form of award agreements are filed as exhibits to this Form 10-K and their terms
and provisions are incorporated herein by reference as follows: ONEOK's Equity
Compensation Plan - Exhibit 10.13; ONEOK, Inc. Form of Restricted Unit Award
Agreement under Equity Compensation Plan - Exhibit 10.21; ONEOK, Inc. Form of
Performance Unit Award Agreement under Equity Compensation Plan - Exhibit 10.22;
and ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005 -
Exhibit 10.14.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
PARTNERSHIP POLICY, NORTHERN BORDER MANAGEMENT AND AUDIT COMMITTEES
We are managed under the direction of the Partnership Policy Committee
consisting of three members, one of whom is appointed by each of our general
partners. The members appointed by Northern Plains, Pan Border and Northwest
Border have 50%, 32.5% and 17.5%, respectively, of the voting power. Because we
are a limited partnership, we are not required by the listing standards of the
NYSE to have a majority of independent directors or a nominating/corporate
governance or compensation committee. None of our Policy Committee Members are
independent.
We also have an Audit Committee consisting of individuals who are neither
officers nor employees of any general partner nor any affiliate of a general
partner. The Audit Committee members are not members of, and do not vote on
matters submitted to, the Partnership Policy Committee. The Partnership Policy
Committee delegated to the Audit Committee oversight responsibility with respect
to the integrity of our financial statements, the performance of our internal
audit function, the independent auditor's qualification and independence and
compliance with legal and regulatory requirements. The Audit Committee directly
appoints, retains, evaluates and may terminate our independent auditors. The
Audit Committee reviews the annual financial statements and resolves, if
necessary, any significant disputes between management and the independent
auditor that arise in connection with the preparation of our financial
statements. The Audit Committee also has the authority to review, at the request
of a general partner, specific matters that a general partner believes may be a
conflict of interest in order to determine if the resolution of such conflict
proposed by the Partnership Policy Committee is fair and reasonable to us. The
Audit Committee has all other responsibilities required by the NYSE Listing
Standards and SEC rules.
All members of the Partnership Policy Committee and our representatives on the
Northern Border Management Committee serve at the discretion of the general
partner that appointed them. The members of our Partnership Policy Committee and
Audit Committee are not elected by unitholders. Accordingly, we do not have a
procedure by which security holders may recommend nominees to our Partnership
Policy Committee or Audit Committee. The persons designated as executive
officers serve in that capacity at the discretion of the Partnership Policy
Committee. The Audit Committee members are elected, and may be removed, by the
Partnership Policy Committee.
The members of the Partnership Policy Committee receive no management fee or
other remuneration for serving on this committee. The chairman of the Audit
Committee receives an annual fee of $50,000 and the other Audit Committee
members each receive an annual fee of $40,000 and are paid $1,500 for each
meeting attended. In lieu of meeting fees, the Audit Committee chairman may be
compensated an additional amount up to $80,000 and the other members may be
compensated an additional amount up to $65,000 for the review of a conflict of
interest transaction, as requested by the Partnership Policy Committee.
54
There are no family relationships between any of our executive officers or
members of the Partnership Policy Committee and the Audit Committee.
NAME AGE POSITION
- ---- --- --------
William R. Cordes 57 Chief Executive Officer
Member, Partnership Policy Committee
Chairman, Northern Border Management Committee
David L. Kyle 53 Chairman, Partnership Policy Committee
Member, Northern Border Management Committee
Paul E. Miller 47 Member, Partnership Policy Committee
Member, Northern Border Management Committee
Jerry L. Peters 48 Chief Financial and Accounting Officer
Gary N. Petersen 54 Member, Audit Committee
Gerald B. Smith 55 Chairman, Audit Committee
Gil J. Van Lunsen 63 Member, Audit Committee
William R. Cordes was named chief executive officer of the Partnership and
appointed to the Partnership Policy Committee in 2000. He served as chairman of
the Partnership Policy Committee from 2000 until 2004. Mr. Cordes was appointed
president of Northern Plains and Pan Border in 2000 and president of NBP
Services in 2004. Mr. Cordes was named chairman of the Northern Border
Management Committee in 2000. In 1970, he started his career with Northern
Natural Gas Company, an Enron subsidiary until 2002, where he worked in several
management positions. From 1993 until 2000, he was president of Northern Natural
Gas Company, and from 1996 until 2000, he was also president of Transwestern
Pipeline, a subsidiary of Enron.
David L. Kyle was named chairman of the Partnership Policy Committee and
designated a member of the Northern Border Management Committee in 2004. Mr.
Kyle is chairman and chief executive officer of Northern Plains, Pan Border and
NBP Services. Mr. Kyle is also the chairman of the board, president, and chief
executive officer of ONEOK. He was employed by Oklahoma Natural Gas Company in
1974 as an engineer trainee. He served in a number of positions prior to being
elected vice president of Gas Supply in 1986 and executive vice president in
1990. He was elected president of Oklahoma Natural Gas Company in 1994. He was
elected president of ONEOK in 1997, and elected chairman of the board and
appointed the chief executive officer of ONEOK in 2000. Mr. Kyle is a member of
the board of directors of Bank of Oklahoma Financial Corporation.
Paul E. Miller was designated by TransCanada as its member on the Partnership
Policy Committee in 2003. Mr. Miller is also a representative on the Northern
Border Management Committee. In addition, Mr. Miller serves as director,
Corporate Development of TransCanada, a position he has held since 2003. From
1998 to 2003, Mr. Miller was director, Finance of TransCanada. Prior to 1998,
Mr. Miller was manager, Finance of TransCanada.
Jerry L. Peters was named chief financial and accounting officer in 1994. Mr.
Peters has held several management positions with Northern Plains since 1985 and
was elected vice president of Finance in 1994 and treasurer in 1998. Mr. Peters
was also elected vice president of Finance for NBP Services in 2004. Mr. Peters
was vice president, Finance of the following former affiliates of Northern
Plains: Florida Gas Transmission Company from February 2001 to May 2002;
Transportation Trading Services Company from September 2001 to July 2002; Citrus
Corp. from October 2001 to July 2002; and Transwestern Pipeline Company from
November 2001 to May 2002. Prior to joining Northern Plains in 1985, Mr. Peters
was employed as a certified public accountant by KPMG LLP.
Gary N. Petersen was appointed to the Audit Committee in 2002. Since 1998, he
has provided consulting services related to strategic and financial planning.
Additionally, he is president of Endres Processing LLC. From 1977 to 1998, Mr.
Petersen was employed by Reliant Energy-Minnegasco. He served as president and
chief operating officer of Reliant Energy-Minnegasco from 1991 to 1998. Prior to
his employment at Minnegasco, he was a senior
55
auditor with Andersen. He currently serves on the boards of the YMCA of
Metropolitan Minneapolis and the Dunwoody Institute.
Gerald B. Smith was appointed to the Audit Committee in 1994. He is chairman and
chief executive officer and co-founder of Smith, Graham & Company Investment
Advisors, a global investment management firm, which was founded in 1990. He is
a member of the board of trustees of the Charles Schwab Family of Funds and a
director and member of the Cooper Industries audit committee. He is a former
director of the Fund Management Board of Robeco Group, Rorento N.V.
(Netherlands).
Gil J. Van Lunsen was appointed to the Audit Committee in March 2005. Prior to
his retirement in 2000, Mr. Van Lunsen was a managing partner of KPMG LLP at the
firm's Tulsa, Oklahoma office. He began his career with KPMG in 1968. He is
currently a director and audit committee chairman of Array Biopharma in Boulder,
Colorado and Sirenza Microdevices in Broomfield, Colorado.
OFFICERS
At the Partnership Policy Committee meeting on March 3, 2006, the following
persons were deemed to be officers of the Partnership for purposes of Section 16
of the Exchange Act. Some of these individuals are officers at certain
subsidiaries or affiliates of the Partnership.
NAME AGE POSITION
- ---- --- --------
Paul F. Miller 39 Vice President and General Manager, Northern Border
Pipeline
Northern Plains
Michel E. Nelson 58 Vice President, Operations
Northern Plains
Raymond D. Neppl 61 Vice President, Regulatory Affairs and Market
Services
Northern Plains
Pierce H. Norton 46 President, Bear Paw Energy
Janet K. Place 57 Vice President, General Counsel and Secretary
Northern Plains and NBP Services
Fred G. Rimington 55 Vice President, Administration
Northern Plains and NBP Services
President, Black Mesa Pipeline
Gaye Lynn Schaffart 46 Vice President and General Manager, Interstate
Pipelines
Northern Plains
Christopher R Skoog 42 Executive Vice President
Northern Plains and NBP Services
Paul F. Miller was elected vice president and general manager of Northern
Border Pipeline by Northern Plains in January 2005. From 2002 until January
2005, Mr. Miller was vice president of Marketing for Northern Plains. Mr. Miller
was previously account executive, Marketing from 1998 until 2000, when he was
promoted to director, Marketing. Mr. Miller joined Northern Plains in 1990.
Michel E. Nelson was elected vice president, Operations for Northern Plains in
2004. Mr. Nelson was previously vice president of Operations and Support
Services for CrossCountry Energy, LLC, an Enron subsidiary, from 2002 to 2004.
From 1997 to 2002, Mr. Nelson held various positions for Enron Transportation
Services with responsibility for pipeline operations. Mr. Nelson started his
pipeline operations career with Northern Natural Gas Company in 1968.
CrossCountry Energy, Enron Transportation Services and Northern Natural Gas
Company were formerly affiliated with Northern Plains.
56
Raymond D. Neppl is vice president, Regulatory Affairs and Market Services, a
position he has held since 1994. Mr. Neppl was previously vice president of
Regulatory Affairs from 1991 to 1994. Mr. Neppl joined Northern Natural Gas
Company, formerly affiliated with Northern Plains, in 1975 and transferred to
Northern Plains in 1980.
Pierce H. Norton was appointed president of Bear Paw Energy in 2003. Mr. Norton
was appointed president of ONEOK's gathering and processing segment in January
2006. Mr. Norton was previously appointed senior vice president of ONEOK's
gathering and processing segment in July 2005. Mr. Norton was appointed vice
president and general manager for midstream businesses for NBP Services in 2003.
Mr. Norton served as vice president, Business Development for Bear Paw Energy
from 2001 to 2003. Prior to the Partnership's purchase of Bear Paw Energy, Mr.
Norton was vice president, Business Development for Bear Paw Energy and its
predecessor from 1999 to 2001.
Janet K. Place is vice president, general counsel and secretary of Northern
Plains. Ms. Place was elected as vice president in 1994 and secretary in 2004.
She was also elected vice president, general counsel and secretary of NBP
Services in 2004. In 1993, Ms. Place was named general counsel. Ms. Place joined
Northern Plains in 1980 as an attorney.
Fred G. Rimington was elected vice president, Administration of Northern Plains
and NBP Services in February 2005. He was appointed president of Black Mesa in
2000. Mr. Rimington was director, Business Development from 1994 to 1999 for
Northern Plains. Mr. Rimington joined Northern Plains in 1980.
Gaye Lynn Schaffart was elected vice president and general manager, Interstate
Pipelines of Northern Plains in February 2005. Ms. Schaffart was previously
director, Business Development and Planning from 1993 to 2004 and was promoted
to vice president, Business Development and Strategic Planning in 2004. Ms.
Schaffart joined Northern Plains in 1982.
Christopher R Skoog was appointed executive vice president of Northern Plains
and NBP Services in February 2005. Mr. Skoog is responsible for all commercial,
operational and regulatory functions of the Partnership's natural gas businesses
and coordinates the Partnership's business development initiatives. From 1999 to
January 2005, Mr. Skoog served as president of ONEOK Energy Services Company,
II. From 1995 to 1999, he was vice president of ONEOK Gas Marketing Company.
AUDIT COMMITTEE MATTERS
INDEPENDENCE DETERMINATIONS
The Partnership has a separately-designated standing Audit Committee in
accordance with Section 3(a)(58)(A) of the Exchange Act. The Partnership's
guidelines for determining independence are included in the Partnership's
Governance Guidelines, which, along with the Audit Committee Charter, are
available on the "Governance" section of the Partnership's website at
www.northernborderpartners.com. Copies of the Governance Guidelines as well as
the Audit Committee Charter are available in print to any security holder who
requests them by sending a written request to Investor Relations Department,
Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. The
Governance Guidelines provide that the members of the Audit Committee shall at
all times qualify as independent members under the independence standards of the
NYSE, Section 10A(m)(3) of the Exchange Act, the rules and regulations of the
SEC and other applicable laws. At least annually the Partnership Policy
Committee reviews the relationships of each Audit Committee member with the
Partnership to affirmatively determine the independence of each member. In March
2006, the Partnership Policy Committee affirmatively determined that Messrs.
Petersen, Smith, and Van Lunsen meet the standards for independence set forth in
the Governance Guidelines and are independent from management.
FINANCIAL EXPERTS
Annually, the Partnership Policy Committee reviews the financial expertise of
the members of the Audit Committee. In March 2006, the Partnership Policy
Committee determined that Messrs. Petersen, Smith and Van Lunsen were "audit
committee financial experts," as defined by the rules and regulations of the
SEC.
57
SEPARATE SESSIONS OF NON-MANAGEMENT COMMITTEE MEMBERS
The Partnership Policy Committee has documented its governance practices in our
Governance Guidelines, which are available on the "Governance" section of the
Partnership's website at www.northernborderpartners.com. The chairman of the
Audit Committee, Mr. Smith, presides at regular sessions of the non-management
committee members, which include the members of the Audit Committee and Messrs.
Kyle and Miller of the Partnership Policy Committee. Meetings of the
non-management committee members are scheduled quarterly or as requested by any
non-management committee member.
Interested parties desiring to communicate with the chairman of the Audit
Committee, the non-management members of the Partnership Policy Committee or the
Audit Committee members regarding the Partnership may contact such member(s)
directly by utilizing the Partnership Ethics and Compliance Hotline which is
posted on the "Governance-Contact Information" section of our website at
www.northernborderpartners.com.
SERVICE ON OTHER AUDIT COMMITTEES
Mr. Van Lunsen serves on the audit committees of two other public companies. The
Partnership Policy Committee has determined that Mr. Van Lunsen's service on
these other audit committees does not impair his ability to effectively serve on
the Partnership's Audit Committee.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires executive officers, members of the
Partnership Policy Committee and persons who own more than 10% of a registered
class of the equity securities issued by us to file reports of ownership and
changes in ownership with the SEC and the NYSE and to furnish the Partnership
with copies of all Section 16(a) forms they file. Based solely on our review of
the copies of such forms received by us during and with respect to the 2005
fiscal year, or written representations from certain reporting persons that no
Form 5's were required for those persons, we believe that during 2005 our
reporting persons complied with all applicable filing requirements in a timely
manner, except for one transaction related to the sale of units from Pierce H.
Norton's trust which was not reported within two business days as required.
CODE OF ETHICS AND CODE OF CONDUCT
We have adopted an Accounting and Financial Reporting Code of Ethics applicable
to the Partnership's chief executive officer and chief financial and accounting
officer. A copy of the Accounting and Financial Reporting Code of Ethics is
posted on the "Governance" section of our website at
www.northernborderpartners.com and is available in print to any security holder
who requests it by writing to: Investor Relations Department, Northern Border
Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. We intend to post on our
website any amendment to, or waiver from, any provision of our Accounting and
Financial Reporting Code of Ethics that applies to our chief executive officer
and chief financial and accounting officer within four business days following
such amendment or waiver, in accordance with SEC rules.
We have also adopted a Code of Conduct applicable to the members of the
Partnership Policy Committee and Audit Committee, our officers and deemed
executive officers and the employees of Northern Plains and NBP Services. The
Code of Conduct is intended to meet the requirements of a "code of business
conduct and ethics" under Section 303A.10 of the NYSE Listed Company Manual. A
copy of the Code of Conduct is posted on the "Governance" section of our website
at www.northernborderpartners.com and is available in print to any security
holder who requests it by writing to: Investor Relations Department, Northern
Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. We intend to
promptly post on our website any amendments to, or waivers from (including any
implicit waivers), any provision of our Code of Conduct according to the rules
of the NYSE.
CERTIFICATION
As required by the NYSE corporate governance listing standards, William R.
Cordes, our chief executive officer, certified on May 4, 2005, that he was not
aware of any violation by the Partnership of such standards. The certifications
required by Section 302 of the Sarbanes-Oxley Act are attached as exhibits 31.1
and 31.2 to this annual report.
58
ITEM 11. EXECUTIVE COMPENSATION
We are managed by a three-member Partnership Policy Committee, with one member
appointed by each general partner. The Partnership Policy Committee designated
two executive officers to serve as officers of the Partnership at the discretion
of the Partnership Policy Committee. Certain officers of the general partners
and certain officers of the Partnership's subsidiaries were also deemed to be
executive officers of the Partnership by the Partnership Policy Committee.
The following table summarizes the compensation paid for the last three years to
the chief executive officer of the Partnership and the four most highly
compensated executive officers of the Partnership during 2005, which we
collectively refer to as the "named executive officers." From January 1, 2003,
through November 17, 2004, compensation plans were administered by Enron.
Beginning November 18, 2004, compensation plans are administered by ONEOK.
SUMMARY COMPENSATION TABLE
LONG-TERM
ANNUAL COMPENSATION COMPENSATION
----------------------------------------------- ------------
OTHER ANNUAL RESTRICTED ALL OTHER
COMPENSATION(1) STOCK AWARDS COMPENSATION
NAME AND PRINCIPAL POSITION YEAR SALARY ($) BONUS ($) ($) ($) ($)
- --------------------------- ---- ---------- --------- --------------- ------------ ------------
William R. Cordes 2005 $330,000 $365,000 $ -- $111,760(5) $21,607(6)
Chief Executive Officer 2004 325,000 175,000 -- -- 4,908
2003 324,583 200,000 -- 99,972(4) 3,000
Jerry L. Peters 2005 190,000 140,000 -- 55,880(5) 13,616(7)
Chief Financial and 2004 171,380 110,000 -- -- 5,658
Accounting Officer 2003 163,324 107,500 -- -- 76,386
Christopher R Skoog (2) 2005 315,000 300,000 $71,981(3) 83,820(5) 43,294(8)
Executive Vice President
Janet K. Place 2005 185,000 135,000 -- 37,253(5) 13,475(9)
Vice President, General 2004 182,552 115,000 -- -- 8,675
Counsel and Secretary 2003 177,592 110,000 -- -- 6,233
Paul F. Miller 2005 175,000 140,000 -- 46,566(5) 12,594(10)
Vice President and General 2004 153,298 118,000 -- -- 5,335
Manager for Northern 2003 148,958 111,000 -- -- 90,325
Border Pipeline
(1) Except as specifically noted below, with respect to Mr. Skoog, the named
executive officers did not receive any annual compensation not properly
categorized as salary or bonus, except for certain perquisites and other
personal benefits, which include vehicle allowances and country club dues.
The aggregate amount of such perquisites and other personal benefits, if
any, for the named executive officers during the fiscal year did not exceed
the lesser of $50,000 or 10% of total salary and bonus reported for such
named executive officer. The aggregate amount of perquisites and other
personal benefits received in the last fiscal year, for the named executive
officers other than Mr. Skoog, were as follows: Mr. Cordes, $26,340; Mr.
Peters, $14,400; Ms. Place, $14,400; and Mr. Miller, $14,400.
(2) Mr. Skoog was appointed as executive vice president of Northern Plains in
February 2005.
(3) Includes $52,500 in relocation expenses under ONEOK's relocation plan,
which plan is available generally to all salaried employees, $18,000
vehicle allowance and $1,481 physical examination cost.
(4) On June 1, 2003, 669 Northern Border Partners' phantom units valued at
$149.4346 per unit were granted in accordance with Mr. Cordes' employment
agreement. The phantom units vest on the fifth anniversary of the date of
each grant. As of December 31, 2005, Mr. Cordes held 4,162 phantom units
valued at $643,397 ($154.5885 per unit). Distributions accrued on the
phantom units as of December 31, 2005, were $198,336.
59
(5) Represents restricted stock incentive units granted under ONEOK's Long-Term
Incentive Plan. The market value of restricted stock incentive unit awards
is based on the closing market price of a share of ONEOK common stock on
the NYSE on the date of grant. Each grant vests three years from the date
of grant at which time the grantee is entitled to receive two-thirds of the
grant in shares of ONEOK common stock and one-third of the grant in cash.
Since no shares of ONEOK common stock are issued under a restrictive stock
incentive unit until the unit vests, no dividends are payable with respect
to restricted stock incentive units. The aggregate number of restricted
stock incentive units (excluding fractional shares) held by the named
executive officers at December 31, 2005, and the market value of these
restricted stock incentive units as of that date are indicated in the table
below. In addition to restricted stock incentive units, Mr. Skoog holds
12,274 aggregate shares (excluding fractional shares) of restricted stock
with a market value of $326,857 as of December 31, 2005. Restricted stock
is granted under ONEOK's Long Term Incentive Plan. Each grant vests three
years from the date of grant. Dividends are paid on unvested shares of
restricted stock and reinvested in additional shares of restricted stock at
the average of the high and low trading prices of a share of ONEOK's common
stock on the NYSE on the date the dividend is paid. Restricted stock
acquired as a result of the reinvestment of dividends vests at the same
time as the restricted stock with respect to which the dividend was paid
vests. The market value was determined based on a per share price for ONEOK
common stock of $26.63, which reflects the closing market price of ONEOK
common stock on the NYSE on December 30, 2005.
AGGREGATE NUMBER OF MARKET VALUE OF RESTRICTED
RESTRICTED STOCK INCENTIVE UNITS HELD AT STOCK INCENTIVE UNITS HELD AT DECEMBER 31,
NAME DECEMBER 31, 2005 2005
- ---- ---------------------------------------- --------------------------------------------
William R. Cordes 6,000 $159,780
Christopher R Skoog 16,000 426,080
Jerry L. Peters 3,000 79,890
Janet K. Place 2,000 53,260
Paul F. Miller 2,500 66,575
(6) Amount includes: (i) $7,402 paid as a company match under ONEOK's
Non-Qualified Deferred Compensation Plan; (ii) $12,600 paid as a company
match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries;
(iii) $1,276 paid as a service award; and (iv) $329 representing the value
of ONEOK shares received under ONEOK's Employee Stock Award Program based
on the closing market price of ONEOK's common stock on the NYSE on the date
of issue.
(7) Amount includes: (i) $12,485 paid as a company match under the Thrift Plan
for Employees of ONEOK, Inc. and Subsidiaries; (ii) $802 paid as a service
award; and (iii) $329 representing the value of ONEOK shares received under
ONEOK's Employee Stock Award Program based on the closing market price of
ONEOK's common stock on the NYSE on the date of issue.
(8) Amount includes: (i) $30,000 paid as a company match under ONEOK's
Non-Qualified Deferred Compensation Plan; (ii) $12,600 paid as a company
match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries;
(iii) $365 paid as a service award; and (iv) $329 representing the value of
ONEOK shares received under ONEOK's Employee Stock Award Program based on
the closing market price of ONEOK's common stock on the NYSE on the date of
issue.
(9) Amount includes: (i) $12,234 paid as a company match under the Thrift Plan
for Employees of ONEOK, Inc. and Subsidiaries; (ii) $912 paid as a service
award; and (iii) $329 representing the value of ONEOK shares received under
ONEOK's Employee Stock Award Program based on the closing market price of
ONEOK's common stock on the NYSE on the date of issue.
(10) Amount includes: (i) $11,664 paid as a company match under the Thrift Plan
for Employees of ONEOK, Inc. and Subsidiaries; (ii) $601 paid as a service
award; and (iii) $329 representing the value of ONEOK shares received under
ONEOK's Employee Stock Award Program based on the closing market price of
ONEOK's common stock on the NYSE on the date of issue.
For 1999, 2000 and 2001, employees of Northern Plains were able to elect to
receive Northern Border phantom units, Enron phantom stock, and/or Enron stock
options in lieu of all or a portion of an annual bonus payment. Mr. Cordes, Mr.
Peters, Ms. Place and Mr. Miller elected to receive Northern Border phantom
units under the Northern Border Phantom Unit Plan in lieu of a portion of the
cash bonus payment. As a result of this deferral, Mr. Cordes received 1,914
units in 2001; Mr. Peters received 1,532 units in 1999, 1,450 units in 2000 and
842 units in 2001; Ms. Place received 901 units in 1999 and 240 units in 2001;
and Mr. Miller received 137 units in 1999, 123 units in 2000 and 230 units in
2001. In each case, units will be released based upon the holding period
selected by the participant. For the release in January 2004 Mr. Peters received
4,727 common units and $2,234 in cash and he received 6,734 common units for the
release in January 2005. For the release in January 2003, Ms. Place received
1,091 common units and for the release in January 2004, she elected a redemption
payment in cash of $83,232. For the release in January 2003, Mr. Miller received
329 common units and for the release in January 2004, he elected a redemption
payment in cash of $25,283. As of December 31, 2005, Mr. Peters held 842 phantom
units valued at $130,164 ($154.5885 per unit).
60
Distributions accrued on Mr. Peters' phantom units as of December 31, 2005, were
$46,760. As of December 31, 2005, Ms. Place held 230 phantom units valued at
$35,555 ($154.5885 per unit). Distributions accrued on Ms. Place's phantom units
as of December 31, 2005, were $12,773. As of December 31, 2005, Mr. Miller held
115 phantom units valued at $17,778 ($154.5885 per unit). Distributions accrued
on Mr. Miller's phantom units as of December 31, 2005, were $6,387. Mr. Cordes'
information is included above in footnote 5 to the Summary Compensation Table.
On January 19, 2006, the Board of Directors of ONEOK granted restricted stock
units and performance units under ONEOK's Equity Compensation Plan to the named
executive officers as follows: (i) Mr. Cordes, 6,000 restricted stock units and
10,500 performance units; Mr. Skoog, 2,500 restricted stock units and 4,000
performance units; Mr. Peters, 2,500 restricted stock units and 4,000
performance units; Ms. Place 1,500 restricted stock units and 2,500 performance
units; and Mr. Miller 1,500 restricted stock units and 2,500 performance units.
The restricted stock units vest three years from the date of grant at which time
the grantee is entitled to shares of ONEOK common stock. The performance units
granted vest three years from the date of grant at which time the holder is
entitled to receive a percentage (0% to 200%) of the performance shares granted
based on ONEOK's total shareholder return over the period January 19, 2006, to
January 19, 2009, compared to the total shareholder return of a peer group of 20
other companies. The grant is payable in shares of ONEOK common stock.
LONG-TERM INCENTIVE PLANS -- AWARDS IN LAST FISCAL YEAR
The following table sets forth the certain information concerning performance
share units granted in 2005 to the named executive officers under ONEOK's
Long-Term Incentive Plan.
PERFORMANCE SHARE GRANTS
ESTIMATED FUTURE PAYOUTS UNDER
PERFOMANCE OR NON-STOCK PRICE-BASED PLANS
NUMBER OF OTHER PERIOD -----------------------------------------------
SHARES, UNITS UNTIL TARGET MAXIMUM
OR OTHER RIGHTS MATURATION OR THRESHOLD --------------- -----------------
NAME (1,2) (#) PAYOUT ($ OR #) (#) ($)(3) (#) ($)(3)
- ---- --------------- ------------- --------- ----- ------- ------ --------
William R. Cordes 10,500 3 Years -- 7,000 $93,205 14,000 $186,410
Christopher R Skoog 9,000 3 Years -- 6,000 79,890 12,000 159,780
Jerry L. Peters 4,500 3 Years -- 3,000 39,945 6,000 79,890
Janet K. Place 3,500 3 Years -- 2,333 31,077 4,666 62,154
Paul F. Miller 4,000 3 Years -- 2,666 35,524 5,333 71,022
(1) Restricted stock incentive units granted under ONEOK's Long-Term Incentive
Plan in 2005 are set forth in the Summary Compensation Table above.
(2) Reflects performance share units granted which vest three years from the
date of grant. Upon vesting, a holder of performance share units is
entitled to receive a number of shares of ONEOK common stock equal to a
percentage (0% to 200%) of the performance share units granted based on
ONEOK's total shareholder return over the period January 20, 2005, to
January 20, 2008, compared to the total shareholder return of a peer group
of 20 other energy companies over the same period. Upon vesting, if any,
the performance share awards are payable two-thirds in shares of ONEOK
common stock and one-third in cash.
(3) The value for the one-third of the grant payable in cash was determined
based on a per share price for ONEOK common stock of $26.63, which reflects
the closing market price of ONEOK common stock on the NYSE on December 30,
2005.
TERMINATION AGREEMENT
ONEOK has entered into termination agreements with each of the named executive
officers.
Each termination agreement has an initial term of one year and is automatically
extended in one-year increments after the expiration of the initial term unless
ONEOK provides notice to the officer or the officer provides notice to ONEOK at
least 90 days before January 1, preceding the initial or any subsequent
termination date of the agreement that the party providing notice does not wish
to extend the term. If a "change in control" of ONEOK occurs, the term of each
termination agreement will not expire for at least three years after the change
in control.
61
Under the termination agreements, severance payments and benefits are payable if
the officer's employment is terminated by ONEOK without "just cause" or by the
officer for "good reason" at any time during the three years after a change in
control. In general, severance payments and benefits include a lump sum payment
in an amount equal to (1) two times (three times, in the case of William Cordes)
the officer's annual compensation and (2) a prorated portion of the officer's
targeted short-term incentive compensation. The officer would also be entitled
to an accelerated vesting of retirement and other benefits under the
Supplemental Executive Retirement Plan (discussed below) and continuation of
welfare benefits for 24 months (36 months in case of Mr. Cordes). Severance
payments will be reduced if the net after-tax benefit to such officer exceeds
the net after-tax benefit if such reduction were not made. Gross up payments
will be made to such officers only if the severance payments, as reduced, are
subsequently deemed to constitute excess parachute payments.
For purposes of these agreements, a change in control generally means any of the
following events:
- an acquisition of voting securities of ONEOK by any person that
results in the person having beneficial ownership of 20% or more of
the combined voting power of ONEOK's outstanding voting securities,
other than an acquisition directly from ONEOK;
- the current members of ONEOK's Board of Directors, and any new
director approved by a vote of at least two-thirds of ONEOK's Board of
Directors, cease for any reason to constitute at least a majority of
ONEOK's Board of Directors, other than in connection with an actual or
threatened proxy contest (collectively, the "Incumbent Board");
- a merger, consolidation or reorganization with ONEOK or in which ONEOK
issues securities, unless (a) ONEOK's shareholders immediately before
the transaction do not, as a result of the transaction, own, directly
or indirectly, at least 50% of the combined voting power of the voting
securities of the company resulting from the transaction; (b) members
of ONEOK's Incumbent Board after the execution of the transaction
agreement do not constitute at least a majority of the members of the
Board of the company resulting from the transaction; or (c) no person
other than persons who, immediately before the transaction owned 30%
or more of ONEOK's outstanding voting securities, has beneficial
ownership of 30% or more of the outstanding voting securities of the
company resulting from the transaction; or
- ONEOK's complete liquidation or dissolution or the sale or other
disposition of all or substantially all of their assets.
ENRON CASH BALANCE PLAN
Enron maintained the Enron Corp. Cash Balance Plan (Cash Balance Plan), which
was a noncontributory defined benefit pension plan to provide retirement income
for employees of Enron and its subsidiaries. Participants in the Cash Balance
Plan with five years or more of service were entitled to retirement benefits in
the form of an annuity based on a formula that uses a percentage of final
average pay and years of service. Enron's Board of Directors voted to terminate
the Cash Balance Plan effective May 31, 2004. The process of terminating the
Cash Balance Plan involved a series of governmental filings seeking approval for
the termination and notices to participants and beneficiaries. Upon termination,
all employees became fully vested in the Cash Balance Plan. In 2005,
participants' cash balance accruals and accumulated interest credits were
distributed as either lump sum or monthly annuities, depending upon a
participant's election and particular circumstances. Lump sum payments could be
rolled over to other qualified retirement plans or IRAs, or received in cash.
The named executive officers received the following approximate payout amounts
in 2005 pursuant to the terms of the Cash Balance Plan termination: Mr. Cordes,
$77,144; Mr. Peters, $64,285; Ms. Place, $69,492; and Mr. Miller, $40,600.
PENSION PLAN - ONEOK
ONEOK's retirement plan is a tax-qualified, defined-benefit pension plan under
both the Internal Revenue Code of 1986, as amended, and the Employee Retirement
Income Security Act of 1974, as amended. The following table sets forth the
estimated annual retirement benefits payable to a non-bargaining unit plan
participant based upon the final average pay formulas under ONEOK's retirement
plan for employees in the compensation and years-of-service classifications
specified. The estimates assume that benefits are received in the form of a
single life annuity.
62
PENSION PLAN TABLE
YEARS OF SERVICE
----------------------------------------------------
REMUNERATION 15 20 25 30 35
- ------------ -------- -------- -------- -------- --------
$125,000 $ 32,119 $ 42,825 $ 53,531 $ 64,238 $ 74,944
150,000 39,244 52,325 65,406 78,488 91,569
175,000 46,369 61,825 77,281 92,738 108,194
200,000 53,494 71,325 89,156 106,988 124,819
225,000 60,619 80,825 101,031 121,238 141,444
250,000 67,744 90,325 112,906 135,488 158,069
300,000 81,994 109,325 136,656 163,988 191,319
400,000 110,494 147,325 184,156 220,988 257,819
450,000 124,744 166,625 207,906 249,488 291,069
500,000 138,994 185,325 231,656 277,988 324,319
Benefits under the ONEOK retirement plan become vested and non-forfeitable after
completion of five years of continuous employment. A vested participant receives
the monthly retirement benefit at normal retirement age under the retirement
plan, unless an early retirement benefit is elected under the plan, in which
case the retirement benefit is actuarially reduced for early commencement.
Benefits are calculated at retirement date based on a participant's credited
service, limited to a maximum of 35 years and final average earnings. The
credited year(s) of service under this plan for the named executive officers,
other than Mr. Skoog was one year and one month. As of December 31, 2005, Mr.
Skoog had 10 years and five months of credited service.
For purposes of the table, the annual social security covered compensation
benefit of $48,696 was used in the excess benefit calculation. Benefits payable
under ONEOK's retirement plan are not offset by social security benefits.
Under the Internal Revenue Code, the annual compensation of each employee to be
taken into account under ONEOK's retirement plan for 2005 cannot exceed
$210,000.
Amounts shown in the table are estimates only and are subject to adjustment
based on rules and regulations applicable to the method of distribution and
survivor benefit options selected by the retiree.
The compensation covered by the retirement plan benefit formula for
non-bargaining unit employees is the base salary and bonus paid to an employee
within the employee's final average earnings. Final average earnings mean the
employee's highest earnings during any 60 consecutive months during the last 120
months of employment. For any named executive officer who retires with vested
benefits under the plan, the compensation shown as "Salary" and "Bonus" in the
Summary Compensation Table could be considered covered compensation in
determining benefits, except that the plan benefit formula takes into account
only a fixed percentage of final average earnings which is uniformly applied to
all employees. The amount of covered compensation that may be considered in
calculating retirement benefits is also subject to limitations in the Internal
Revenue Code of 1986, as amended, applicable to the plan.
SUPPLEMENTAL EXECUTIVE RETIREMENT
ONEOK maintains a Supplemental Executive Retirement Plan (SERP) for certain of
its elected or appointed officers, and certain other employees in a select group
of management and highly compensated employees. Participants are selected by
ONEOK's chief executive officer, or, in the case of ONEOK's chief executive
officer, by ONEOK's Board of Directors. All of our named officers participate in
the SERP.
Benefits payable under the SERP are based upon a specified percentage (reduced
for early retirement) of the highest 36 consecutive months' compensation of the
employee's last 60 months of service. The SERP will, in any case, pay a benefit
at least equal to the benefit which would be payable to the participant under
ONEOK's retirement plan if limitations imposed by the Internal Revenue Code were
not applicable, less the benefit payable under ONEOK's retirement plan with such
limitations. Benefits under the SERP are paid concurrently with the payment of
benefits under ONEOK's retirement plan or as ONEOK's Administrative Committee
may determine. SERP benefits are offset by benefits payable under ONEOK's
retirement plan, but are not offset by social security benefits. ONEOK's
63
board may amend or terminate the SERP at any time, provided that accrued
benefits to current participants may not be reduced.
The following table sets forth the estimated supplemental retirement benefits
payable under ONEOK's SERP based on the covered participant's age at retirement.
The estimates assume that a covered participant is fully vested. The amounts
shown would be reduced for commencement of payments prior to age 60.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN TABLE
ESTIMATED ANNUAL BENEFITS AT INDICATED AGE OF RETIREMENT
-----------------------------------------------------------
REMUNERATION 50 AND UNDER 55 60 62 65 AND OVER
- ------------ ------------ -------- -------- -------- -----------
$100,000 $ 50,000 $ 55,000 $ 59,000 $ 60,000 $ 60,000
150,000 75,000 82,500 88,500 90,000 90,000
200,000 100,000 110,000 118,000 120,000 120,000
250,000 125,000 137,500 147,500 150,000 150,000
300,000 150,000 165,000 177,000 180,000 180,000
350,000 175,000 192,500 206,500 210,000 210,000
400,000 200,000 220,000 236,000 240,000 240,000
450,000 225,000 247,500 265,500 270,000 270,000
500,000 250,000 275,000 295,000 300,000 300,000
550,000 275,000 302,500 324,500 330,000 330,000
600,000 300,000 330,000 354,000 360,000 360,000
650,000 325,000 357,500 383,500 390,000 390,000
700,000 350,000 385,000 413,000 420,000 420,000
750,000 375,000 412,500 442,500 450,000 450,000
ONEOK'S EMPLOYEE NON-QUALIFIED DEFERRED COMPENSATION PLAN
The named executive officers are also eligible to participate in ONEOK's
Non-Qualified Deferred Compensation Plan. ONEOK's Non-Qualified Deferred
Compensation Plan provides select employees, as approved by the Board of
Directors of ONEOK, with the option to defer portions of their compensation and
provides non-qualified deferred compensation benefits which are not otherwise
available due to limitations on employer and employee contributions to qualified
defined contribution plans under the federal tax laws. Under the plan,
participants have the option to defer their salary and/or bonus compensation to
a short-term deferral account, which pays out a minimum of five years from
commencement, or to a long-term deferral account, which pays out at retirement
or termination of the employment of the participant. Participants are
immediately 100% vested. Short-term deferral accounts are credited with a deemed
investment return based on the five-year Treasury bond fund. Long-term deferral
accounts are credited with a deemed investment return based on various
investment options, which do not include an option to invest in ONEOK common
stock. At the distribution date, cash is distributed to participants based on
the fair market value of the deemed investment of the participant at that date.
ONEOK EMPLOYEE STOCK AWARD PROGRAM
Under ONEOK's Employee Stock Award Program, ONEOK issued, for no consideration,
to all eligible employees (all full-time employees and employees on short-term
disability) one share of ONEOK common stock when the closing price on the NYSE
was for the first time at or above each one dollar increment above $26 per
share. The total number of shares of ONEOK common stock available for issuance
under this program is 100,000 shares.
SEVERANCE PLANS
Northern Plains' and NBP Services' Severance Pay Plans provide for the payment
of benefits to employees who are terminated for failing to meet performance
objectives or standards or who are terminated due to reorganization or similar
business circumstances. The amount of benefits payable for performance related
terminations is based on length of service and may not exceed eight weeks' pay.
For those terminated as the result of reorganization or similar business
circumstances, the benefit is based on length of service and amount of pay up to
a maximum payment of 52 weeks of base pay. The employee must sign a Waiver and
Release of Claims Agreement in order to receive any severance benefit.
64
COMPENSATION OF COMMITTEE MEMBERS
The members of the Partnership Policy Committee receive no management fee or
other remuneration for serving on the committee; however, they are reimbursed
for their expenses related to their attendance at Partnership Policy Committee
meetings. The chairman of the Audit Committee receives an annual fee of $50,000
and the other Audit Committee members receive an annual fee of $40,000. Each
Audit Committee member is paid $1,500 for each meeting attended. The Audit
Committee may receive additional compensation for the review of a conflict of
interest transaction, as requested by the Partnership Policy Committee, in lieu
of meeting fees. In connection with a review of a conflict of interest
transaction, the Audit Committee chairman would be compensated up to an
additional amount of $80,000 and the other members would be compensated up to an
additional amount of $65,000. In addition, Audit Committee members are
reimbursed for their expenses related to their attendance at Audit and
Partnership Policy Committee meetings. We are required to indemnify the members
of the Partnership Policy Committee and the general partners, their affiliates
and their respective officers, directors, employees, agents and trustees to the
fullest extent permitted by law against liabilities, costs and expenses incurred
by any such person who acted in good faith and in a manner reasonably believed
to be in, or (in the case of a person other than one of the general partners)
not opposed to, our best interests and with respect to any criminal proceedings,
had no reasonable cause to believe the conduct was unlawful.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
We do not have a Compensation Committee. During 2005, the compensation of our
named executive officers was determined by ONEOK's Compensation Committee
consisting of the following ONEOK Board Members: James C. Day, William L. Ford,
Bert H. Mackie, and Douglas Ann Newsom. No member of ONEOK's Compensation
Committee is, or was formerly, an officer or employee of Northern Border
Partners or any if its subsidiaries. We reimburse ONEOK for the direct and
indirect compensation costs of our named executive officers.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
BENEFICIAL OWNERSHIP
The following table sets forth the beneficial ownership of our common units and
the common stock of ONEOK, the parent company of two of our general partners, as
of January 31, 2006, by each named executive officer, each member of the
Partnership Policy Committee and Audit Committee, all executive officers and
members of the Partnership Policy Committee and Audit Committee as a group and
certain beneficial owners. Other than as set forth below, no person is known by
the general partners to beneficially own more than 5% of our common units.
PERCENT OF PERCENT OF
NAME AND ADDRESS OF COMMON COMMON ONEOK ONEOK
BENEFICIAL OWNER (1) UNITS UNITS SHARES(5) SHARES
- -------------------- ------- ---------- ---------- ----------
William R. Cordes 1,000 * 872 *
David L. Kyle -- * 553,812 *
Paul F. Miller -- * 782 *
ONEOK 501,603(2) 1.06 -- *
Jerry L. Peters 7,734(3) * 849 *
Gary N. Petersen 5,854 * -- *
Janet K. Place 1,691(4) * 341 *
Christopher R Skoog -- * 157,682 *
All Policy Committee members, 24,001 * 716,093 *
and executive officers as a group
(16 persons)
* Less than 1%
(1) The business address for each of the beneficial owners is c/o Northern
Border Partners, L.P., 13710 FNB Parkway, Omaha, Nebraska 68154-5200,
except for Mr. Kyle, whose business address is c/o ONEOK, Inc., 100 West
Fifth Street, Tulsa, Oklahoma 74103-4298.
65
(2) Indirect ownership through its subsidiaries. Northern Plains is the
beneficial owner of 501,603 common units which includes 1,603 common units
to satisfy obligations under the Amended and Restated Northern Border
Phantom Unit Plan.
(3) Includes 1,000 units held by immediate family members for which Mr. Peters
has shared voting or investment power.
(4) Includes 500 units held by immediate family members for which Ms. Place has
shared voting or investment power.
(5) Includes shares of ONEOK common stock held by members of the family of the
committee members or executive officer for which the committee members or
executive officer has sole or shared voting or investment power, shares of
common stock held in ONEOK's Direct Stock Purchase and Dividend
Reinvestment Plan, shares held through ONEOK's Thrift Plan, shares of
restricted stock, and shares that the committee member or executive officer
had the right to acquire within 60 days of March 1, 2006. For Mr. Kyle and
Mr. Skoog includes 219,355 and 87,724 respectively the number of shares of
ONEOK common stock which Mr. Kyle and Mr. Skoog had the right to acquire
within 60 days after March 1, 2006 (all such shares are issuable upon the
exercise of stock options granted under ONEOK's Long-Term Incentive Plan).
For Mr. Kyle, Mr. Cordes and Mr. Skoog includes 79,135, 638 and 15,574
respectively, which are held on each person's behalf by the Trustee of the
ONEOK Thrift Plan as of March 1, 2006.
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. By its terms, the Amended and Restated Northern Border Phantom
Unit Plan terminated on December 31, 2004. The Administrative Committee under
the plan, which consists of appointees of Northern Plains and NBP Services, will
continue to administer the outstanding phantom units, which are based upon the
general partner distribution rate. The Administrative Committee has complete
authority to determine the time and provisions for settlement of the phantom
units. 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, the participant will receive common units, 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.
NUMBER OF SECURITIES WEIGHTED AVERAGE NUMBER OF UNITS
TO BE ISSUED UPON EXERCISE PRICE OF REMAINING
EXERCISE OF OUTSTANDING OUTSTANDING AVAILABLE FOR
PLAN CATEGORY (1) PHANTOM UNITS PHANTOM UNITS FUTURE ISSUANCE
- ----------------- ----------------------- ----------------- ---------------
Equity Compensation
Plans Approved by
Unitholders
Equity Compensation
Plans Not Approved
by Unitholders 30,449(2) $42.00 179,500(3)
(1) Under our partnership agreement, the 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 on the closing price of the common units on December 31, 2005,
assuming that all outstanding phantom units were settled in common units as
of December 31, 2005.
(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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PROPOSED TRANSACTIONS
On February 15, 2006, we announced a series of transactions involving several
related parties. The Audit Committee, who determined the fairness of the
transactions, engaged independent legal counsel and an independent financial
advisor to assist in their determination. Additional information about the
proposed transactions is included under Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations-Executive Summary."
RELATIONSHIP WITH ONEOK
ONEOK owns two of our general partners, Northern Plains and Pan Border, and is
able to elect members with a majority of the voting power on the Partnership
Policy Committee and the Northern Border Management Committee. In addition,
ONEOK owns NBP Services, our administrative service provider. Other
relationships include the following:
Cash Distributions - ONEOK owns a combined general and limited partner interest
in us of 2.71% through Northern Plains and Pan Border. Northern Plains and Pan
Border hold a combined 1.65% general partner interest in us. In addition,
66
Northern Plains owns 501,603 of our common units, which represents a 1.06%
limited partner interest in us. In 2005, we paid ONEOK total cash distributions
of $10.8 million, which included $6.6 million related to their incentive
distribution rights. Additional information about our cash distribution policy
is included under Item 5, "Market for Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities."
Transition Services Agreement - Upon the sale of Northern Plains and NBP
Services by CCE Holdings to ONEOK in November 2004, CCE Holdings and ONEOK
entered into a transition services agreement. This transition services agreement
provided for the continuation of certain services, data applications, systems
and infrastructure relied on by Northern Plains and NBP Services in performing
under the operating agreements and administrative services agreement. The cost
of the transition services was $4.4 million for the full term of the agreement,
which expired on May 17, 2005, and was not extended.
Operating and Administrative Agreements - Northern Plains provides certain
administrative, operating and management services to us and Northern Border
Pipeline, Midwestern Gas Transmission and Viking Gas Transmission through
operating agreements. We and Northern Border Pipeline, Midwestern Gas
Transmission and Viking Gas Transmission are charged for the salaries, benefits
and expenses of Northern Plains incurred in connection with the operating
agreements.
NBP Services provides certain administrative, operating and management services
to us and our natural gas gathering and processing and coal slurry pipeline
businesses through an administrative services agreement. NBP Services is
reimbursed for its direct and indirect costs and expenses.
In 2005, 2004 and 2003, the aggregate amount charged by Northern Plains, NBP
Services and their affiliates for their services was approximately $52.6
million, $45.8 million and $57.6 million, respectively. In 2005 and 2004, $3.6
million and $0.8 million, respectively, were related to transition services.
Transportation Agreements - ONEOK Energy, a subsidiary of ONEOK, became an
affiliate of Northern Border Pipeline in November 2004 in connection with
ONEOK's purchase of Northern Plains. In 2005, 2% of Northern Border Pipeline's
design capacity was contracted on a firm basis with ONEOK Energy. Revenue from
ONEOK Energy for 2005 was $7.7 million. As of January 31, 2006, 1% of Northern
Border Pipeline's design capacity was contracted on a firm basis with ONEOK
Energy for 2006. In addition, ONEOK Energy entered into a precedent agreement
for transportation capacity on Northern Border Pipeline's Chicago III Expansion
Project for 25 MMcf/d of capacity for five and one-half years.
RELATIONSHIP WITH TRANSCANADA
Northwest Border, a subsidiary of TransCanada, owns a 0.35% general partner
interest in us and appoints one member to the Partnership Policy Committee. In
2005, we paid TransCanada total cash distributions of $2.0 million, which
included $1.4 million related to their incentive distribution rights. Additional
information about our cash distribution policy is included under Item 5, "Market
for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities."
RELATIONSHIP WITH GUARDIAN PIPELINE
Northern Plains provides certain administrative, operating and management
services to Guardian Pipeline, of which we own a 33-1/3% interest, through an
operating agreement. The annual fixed fee charged by Northern Plains for its
services was $3.6 million and reimbursement for other services not included in
the fixed fee was approximately $0.6 million in 2005. We guarantee the financial
risks and benefits resulting from and arising out of Northern Plains'
responsibilities and obligations as operator of Guardian Pipeline.
CONFLICTS OF INTEREST
The Partnership Policy Committee, whose members are designated by our three
general partners, establishes our business policies. We also have three
representatives on the Northern Border Management Committee, each of whom votes
a portion of our 70% interest on the Northern Border Management Committee, with
the other 30% interest being voted by a representative of TC PipeLines, which is
an affiliate of one of our general partners.
67
Our general partners, which are subsidiaries of ONEOK and TransCanada, and their
respective affiliates currently engage or may engage in the businesses in which
we engage or in which we may engage in the future. As a result, conflicts of
interest may arise between our general partners and their affiliates, and us. If
such conflicts arise, the members of the Partnership Policy Committee generally
have a fiduciary duty to resolve such conflicts in a manner that is in our best
interest.
TC PipeLines (a 30% owner of Northern Border Pipeline whose general partner is
an affiliate of one of our general partners) and its affiliates are also engaged
in interstate natural gas pipeline transportation in the U.S. separate from
their interest in Northern Border Pipeline. As a result, conflicts also may
arise between TransCanada and its affiliates or TC PipeLines and its affiliates,
and Northern Border Pipeline. If such conflicts arise, the representatives on
the Northern Border Management Committee generally have a fiduciary duty to
resolve such conflicts in a manner that is in the best interest of Northern
Border Pipeline.
Unless otherwise provided for in a partnership agreement, the laws of Delaware
and Texas generally require a general partner of a partnership to adhere to
fiduciary duty standards under which it owes its partners the highest duties of
good faith, fairness and loyalty. Similar rules apply to persons serving on the
Partnership Policy Committee or the Northern Border Management Committee.
Because of the competing interests identified above, our partnership agreement
and the partnership agreement for Northern Border Pipeline contain provisions
that modify certain of these fiduciary duties. For example:
- Our partnership agreement states that our general partners, their
affiliates and their officers and directors will not be liable for
damages to us, our limited partners or their assignees for errors of
judgment or for any acts or omissions if the general partners and such
other persons acted in good faith.
- Our partnership agreement allows our general partners and our
Partnership Policy Committee to take into account the interests of
other parties in addition to our interests in resolving conflicts of
interest.
- Our partnership agreement provides that the general partners will not
be in breach of their obligations under our partnership agreement or
their duties to us or our unitholders if the resolution of a conflict
is fair and reasonable to us. The latitude given in our partnership
agreement in connection with resolving conflicts of interest may
significantly limit the ability of a unitholder to challenge what
might otherwise be a breach of fiduciary duty.
- Our partnership agreement provides that a purchaser of common units is
deemed to have consented to certain conflicts of interest and actions
of the general partners and their affiliates that might otherwise be
prohibited and to have agreed that such conflicts of interest and
actions do not constitute a breach by the general partners of any duty
stated or implied by law or equity.
- Our Audit Committee will, at the request of a general partner or a
member of the Partnership Policy Committee, review conflicts of
interest that may arise between a general partner and its affiliates
(or the member of the Partnership Policy Committee designated by it),
and the unitholders or us. Any resolution of a conflict approved by
the Audit Committee is conclusively deemed fair and reasonable to us.
- The partnership agreement of Northern Border Pipeline relieves us and
TC PipeLines, each of their affiliates and each of their transferees
from any duty to offer business opportunities to Northern Border
Pipeline, subject to specified exceptions.
We are required to indemnify the members of the Partnership Policy Committee and
the general partners, their affiliates and their respective officers, directors,
employees, agents and trustees to the fullest extent permitted by law against
liabilities, costs and expenses incurred by any such person who acted in good
faith and in a manner reasonably believed to be in, or (in the case of a person
other than one of the general partners) not opposed to, our
68
best interests and with respect to any criminal proceedings, had no reasonable
cause to believe the conduct was unlawful.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The fees for the years ended December 31, 2005, and 2004 for professional
services provided by KPMG LLP were as follows:
FOR THE YEARS ENDED
DECEMBER 31,
-------------------
2005 2004
-------- --------
Audit fees $787,235 $895,250
Audit-related fees -- --
Tax fees -- --
All other fees -- --
-------- --------
Total $787,235 $895,250
======== ========
AUDIT FEES
Audit fees include fees for the audit of annual financial statements and
internal control over financial reporting, reviews of the related quarterly
financial statements and related consents and comfort letters for documents
filed with the SEC.
AUDIT COMMITTEE POLICIES AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT
SERVICES
Consistent with SEC policies regarding auditor independence, the Audit Committee
is responsible for pre-approving all audit and non-audit services performed by
the independent auditor. In addition to its approval of the audit engagement,
the Audit Committee takes action at least annually to authorize the performance
by the independent auditor of several specific types of services within the
categories of audit services, audit-related services, tax services and all other
services. Audit services include assurance and related services that are
reasonably related to the performance of the audit or review of the financial
statements, attestations pursuant to Section 404 of the Sarbanes-Oxley Act,
quarterly reviews comfort letters, consents, review of registration statements,
accounting research from completed transactions and tax assistance related to
the audit services. Audit-related services include due diligence related to
potential business acquisitions/dispositions, accounting research and other
audit or attest services. Authorized tax services include compliance-related
services such as services involving tax filings, as well as consulting services
such as tax planning, transaction analysis and opinions. All other services
include special investigations to assist the Audit Committee or its counsel and
assistance with regulatory activities. Services are subject to pre-approval of
the specific engagement if they are outside the specific types of services
included in the periodic approvals covering service categories or if they are in
excess of specified fee limitations. The Audit Committee delegated pre-approval
authority to the Audit Committee chairman.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(A) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Financial Statements" on page F-1.
(A) (3) EXHIBITS
#2.1 Contribution Agreement between ONEOK, Inc. and Northern Border Intermediate
Limited Partnership dated February 14, 2006.
#2.2 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border
Partners, L.P. dated February 14, 2006.
#2.3 Partnership Interest Purchase and Sale Agreement by and between Northern
Border Intermediate Limited Partnership and TC PipeLines Intermediate
Limited Partnership dated as of December 31, 2005.
69
*3.1 Northern Border Partners, L.P. Certificate of Limited Partnership,
Certificate of Amendment dated February 16, 2001, and Certificate of
Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.1 to
the Partnership's Form 10-K for the year ended December 31, 2004 (File No.
1-12202) ("2004 Form 10-K")).
*3.2 Amended and Restated Agreement of Limited Partnership of Northern Border
Partners, L.P. dated October 1, 1993 (incorporated by reference to Exhibit
3.2 to the 2004 Form 10-K).
*3.3 Northern Border Intermediate Limited Partnership Certificate of Limited
Partnership, Certificate of Amendment dated February 16, 2001, and
Certificate of Amendment dated May 20, 2003 (incorporated by reference to
Exhibit 3.3 to the 2004 10-K).
*3.4 Amended and Restated Agreement of Limited Partnership for Northern Border
Intermediate Limited Partnership dated October 1, 1993 (incorporated by
reference to Exhibit 3.1 to the Partnership's Form 10-Q for the quarter
ended March 31, 2005 (File No. 1-12202) ("March 2005 10-Q")).
*4.1 Indenture, dated as of June 2, 2000, between Northern Border Partners,
L.P., Northern Border Intermediate Limited Partnership and Bank One Trust
Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the
Partnership's Form 10-Q for the quarter ended June 30, 2000 (File No.
1-12202) ("June 2000 10-Q")).
*4.2 First Supplemental Indenture, dated as of September 14, 2000, between
Northern Border Partners, L.P., Northern Border Intermediate Limited
Partnership and Bank One Trust Company, N.A. (incorporated by reference to
Exhibit 4.2 to the Partnership's Form S-4 Registration Statement filed on
September 20, 2000, (Registration No. 333-46212) ("NBP Form S-4")).
*4.3 Indenture, dated as of March 21, 2001, between Northern Border Partners,
L.P. and Northern Border Intermediate Limited Partnership and Bank One
Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.3 to
the Partnership's Form 10-K for the year ended December 31, 2001 (File No.
1-12202)).
*4.4 Indenture, dated as of August 17, 1999, between Northern Border Pipeline
Company and Bank One Trust Company, NA, successor to The First National
Bank of Chicago, Trustee. (incorporated by reference to Exhibit No. 4.1 to
Northern Border Pipeline Company's Form S-4 Registration Statement filed on
October 7, 1999, (Registration No. 333-88577) ("NB Form S-4")).
*4.5 Indenture, dated as of September 17, 2001, between Northern Border Pipeline
Company and Bank One Trust Company, N.A., Trustee (incorporated by
reference to Exhibit 4.2 to Northern Border Pipeline Company's Registration
Statement on Form S-4 filed on November 13, 2001, (Registration No.
333-73282) ("2001 NB Form S-4")).
*4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline
Company and Bank One Trust Company, N.A., Trustee (incorporated by
reference to Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q
for the quarter ended March 31, 2002 (File No. 333-88577)).
*10.1 Northern Border Pipeline Company General Partnership Agreement between
Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan
Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern
Ltd., effective March 9, 1978, as amended (incorporated by reference to
Exhibit 10.2 to the Partnership's Form S-1 Registration Statement filed on
July 16, 1993, (Registration No. 33-66158) ("Form S-1")).
*10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company
General Partnership Agreement dated September 23, 1993 (incorporated by
reference to Exhibit 10.15 to Form S-1).
*10.3 Eighth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement dated May 21, 1999 (incorporated by reference to
Exhibit 10.15 to NB Form S-4).
*10.4 Ninth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement July 16, 2001 (incorporated by reference to Exhibit
10.37 to 2001 NB Form S-4).
*10.5 Tenth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement dated March 2, 2005 (incorporated by reference to
Exhibit 3.5 to Northern Border Pipeline's Form 10-K for the year ended
December 31, 2004 filed on March 14, 2005 (File No. 333-88577)).
*10.6 Operating Agreement between Northern Border Pipeline Company and Northern
Plains Natural Gas Company, dated February 28, 1980 (incorporated by
reference to Exhibit 10.3 to Form S-1).
*10.7 Administrative Services Agreement between NBP Services Corporation,
Northern Border Partners, L.P. and Northern Border Intermediate Limited
Partnership (incorporated by reference to Exhibit 10.4 to Form S-1).
*10.8 Revolving Credit Agreement, dated as of May 16, 2005, among Northern
Border Partners, L.P., the lenders from time to time party thereto,
SunTrust Bank, as administrative agent, Wachovia Bank, National
Association, as syndication agent, Harris Nesbit Financing, Inc., Barclays
Bank PLC and Citibank, N.A., as
70
co-documentation agents, and SunTrust Capital Markets, Inc. and Wachovia
Capital Markets, LLC, as co-lead arrangers and book managers (incorporated
by reference to Exhibit 10.1 to the Partnership's current report on Form
8-K filed on May 20, 2005 (File No. 1-12202)).
*10.9 First Amendment to the Revolving Credit Agreement effective June 13, 2005,
among Northern Border Partners, L.P., the lenders from time to time party
thereto, SunTrust Bank, as administrative agent, Wachovia Bank, National
Association, as syndication agent and Harris Nesbit Financing, Inc.,
Barclays Bank PLC and Citibank, N.A., as co-documentation agents
(incorporated by reference to Exhibit 10.2 to the Partnership's Form 10-Q
for the quarter ended June 30, 2005 (File No. 1-12202)).
*10.10 Revolving Credit Agreement, dated as of May 16, 2005, among Northern
Border Pipeline Company, the lenders from time to time party thereto,
Wachovia Bank, National Association, as administrative agent, SunTrust
Bank, as syndication agent, Harris Nesbit Financing, Inc., Barclays Bank
PLC and Citibank, N.A., as co-documentation agents, and Wachovia Capital
Markets, LLC and SunTrust Capital Markets, Inc., as co-lead arrangers and
book managers (incorporated by reference to Exhibit 10.1 to Northern Border
Pipeline Company's current report on Form 8-K (File No. 333-88577) filed on
May 20, 2005 (File No. 333-88577)).
*10.11 Agreement between Northern Plains and Northern Border Intermediate
Limited Partnership regarding the costs, expenses and expenditures arising
under the operating agreement between Northern Plains and Guardian
Pipeline, LLC (incorporated by reference to Exhibit 10.3 to the
Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No.
1-12202)).
+*10.12 Form of Termination Agreement with ONEOK, Inc. dated as of January 5,
2005 (incorporated by reference to Exhibit 99.1 to the Partnership's
current report on Form 8-K filed on January 11, 2005 (File No. 1-12202)).
+*10.13 ONEOK, Inc. Equity Compensation Plan (incorporated by reference to
Exhibit 10.1 to ONEOK's current report on Form 8-K filed on February 23,
2005 (File No. 1-13643)).
+*10.14 ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005
(incorporated by reference to Exhibit 10.2 to ONEOK's current report on
Form 8-K filed on February 23, 2005 (File No. 1-13643)).
+*10.15 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan (incorporated by
reference to Exhibit 99.2 to the Partnership's current report on Form 8-K
filed on January 11, 2005 (File No. 1-12202)).
+*10.16 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference to
Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
+*10.17 ONEOK, Inc. Form of Restricted Stock Incentive Award pursuant to
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to
ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File
No. 1-13643)).
+*10.18 ONEOK, Inc. Form of Performance Shares Award pursuant to Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.5 to ONEOK's Form
10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)).
+*10.19 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as
amended, dated February 15, 2001 (incorporated by reference to Exhibit
10(g) to ONEOK's Form 10-K for the year ended December 31, 2001(File No.
1-13643)).
+*10.20 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference to
Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
+10.21 ONEOK, Inc. Form of Restricted Unit Award Agreement pursuant to Equity
Compensation Plan.
+10.22 ONEOK, Inc. Form of Performance Unit Award Agreement pursuant to Equity
Compensation Plan.
*10.23 Operating Agreement between Midwestern Gas Transmission Company and
Northern Plains Natural Gas Company dated as of April 1, 2001 (incorporated
by reference to Exhibit 10.38 to the Partnership's Form 10-K for the year
ended December 31, 2001 (File No. 1-12202)).
*10.24 Operating Agreement between Viking Gas Transmission Company and Northern
Plains Natural Gas Company dated as of January 17, 2003 (incorporated by
reference to Exhibit 10.18 to the Partnership's Form 10-K for the year
ended December 31, 2002 (File No. 1-12202)).
*10.25 Northern Border Pipeline Company Agreement among Northern Plains Natural
Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company,
TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border
Intermediate Limited Partnership, Northern Border Partners, L.P., and the
Management Committee of Northern Border Pipeline, dated as of March 17,
1999 (incorporated by reference to Exhibit 10.21 to the Partnership's Form
10-K/A for the year ended December 31, 1998 (File No. 1-12202)).
12.1 Statement re computation of ratios.
71
21 List of subsidiaries.
23.1 Consent of KPMG LLP.
31.1 Rule 13a-14(a)/15d-14(a) certification of principal executive officer.
31.2 Rule 13a-14(a)/15d-14(a) Certification of principal financial officer.
32.1 Section 1350 certification of principal executive officer.
32.2 Section 1350 certification of principal financial officer.
+*99.1 Northern Border Phantom Unit Plan (incorporated by reference to Exhibit
99.1 to Amendment No. 1 to the Partnership's Form S-8, Registration
Statement filed on November 15, 2000 (Registration No. 333-66949)).
* Indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith.
+ Management contract, compensatory plan or arrangement.
# The Partnership agrees to furnish supplementally to the Securities and
Exchange Commission, upon request, any schedules and exhibits to this
agreement, as set forth in the Table of Contents of the agreement, that
have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K.
The total amount of securities of the Partnership authorized under any
instrument with respect to long-term debt not filed as an exhibit does not
exceed 10% of the total assets of the Partnership and its subsidiaries on a
consolidated basis. The Partnership agrees, upon request of the Securities and
Exchange Commission, to furnish copies of any or all of such instruments to the
Securities and Exchange Commission.
72
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized on this 6th day of March,
2006.
NORTHERN BORDER PARTNERS, L.P.
(A Delaware Limited Partnership)
By: William R. Cordes
------------------------------------
William R. Cordes
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons in the capacities and on the
dates indicated.
SIGNATURE TITLE DATE
- --------- ----- ----
/s/ William R. Cordes Chief Executive Officer and Partnership Policy March 6, 2006
- ----------------------------- Committee Member
William R. Cordes
(Principal Executive Officer)
/s/ David L. Kyle Chairman of the Partnership Policy Committee March 6, 2006
- -----------------------------
David L. Kyle
/s/ Paul E. Miller Partnership Policy Committee Member March 6, 2006
- -----------------------------
Paul E. Miller
/s/ Jerry L. Peters Chief Financial and Accounting Officer March 6, 2006
- -----------------------------
Jerry L. Peters
(Principal Financial and
Accounting Officer)
73
NORTHERN BORDER PARTNERS, L.P.
ANNUAL REPORT ON FORM 10-K
INDEX TO FINANCIAL STATEMENTS
Page No.
-----------
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm........ F-2
Consolidated Balance Sheet - December 31, 2005, and 2004....... F-3
Consolidated Statement of Income -
Years Ended December 31, 2005, 2004 and 2003................ F-4
Consolidated Statement of Comprehensive Income -
Years Ended December 31, 2005, 2004 and 2003................ F-5
Consolidated Statement of Cash Flows -
Years Ended December 31, 2005, 2004 and 2003................ F-6
Consolidated Statement of Changes in Partners' Equity -
Years Ended December 31, 2005, 2004 and 2003................ F-7
Notes to Consolidated Financial Statements..................... F-8 to F-29
Financial Statements Schedule
Report of Independent Registered Public Accounting Firm on
Schedule.................................................... S-1
Schedule II - Valuation and Qualifying Accounts................ S-2
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Northern Border Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Northern Border
Partners, L.P. and subsidiaries (the Company) as of December 31, 2005 and 2004,
and the related consolidated statements of income, comprehensive income, cash
flows, and changes in partners' equity for each of the years in the three-year
period ended December 31, 2005. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Northern Border
Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2005, in conformity with U. S. generally
accepted accounting principles.
As discussed in note 5 to the consolidated financial statements, the
Partnership adopted Statement of Financial Accounting Standards (SFAS) No. 143,
Accounting for Asset Retirement Obligations, in 2003.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of Northern Border
Partners, L.P.'s internal control over financial reporting as of December 31,
2005, based on criteria established in Internal Control--Integrated Framework,
issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO), and our report thereon dated March 2, 2006 expressed an unqualified
opinion on management's assessment of, and the effective operation of, internal
control over financial reporting.
Omaha, Nebraska
March 2, 2006
F-2
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
-----------------------
2005 2004
---------- ----------
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 43,090 $ 33,980
Accounts receivable, net of allowance for doubtful accounts
of $18 and $9,175 in 2005 and 2004, respectively 81,451 68,930
Related party receivables 1,397 1,077
Materials and supplies, at cost 7,273 5,654
Prepaid expenses and other 5,211 5,650
Derivative financial instruments -- 1,996
---------- ----------
Total current assets 138,422 117,287
---------- ----------
Property, plant and equipment:
Interstate natural gas pipeline 2,668,645 2,630,713
Natural gas gathering and processing 284,199 265,484
Coal slurry pipeline 47,876 47,402
---------- ----------
Total property, plant and equipment 3,000,720 2,943,599
Less: Accumulated provision for depreciation and amortization 1,082,210 1,002,041
---------- ----------
Property, plant and equipment, net 1,918,510 1,941,558
---------- ----------
Investments and other assets:
Investment in unconsolidated affiliates 290,756 273,202
Goodwill 152,782 152,782
Derivative financial instruments -- 2,555
Regulatory assets 14,153 12,308
Other 13,143 14,998
---------- ----------
Total investments and other assets 470,834 455,845
---------- ----------
Total assets $2,527,766 $2,514,690
========== ==========
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 2,194 $ 5,126
Derivative financial instruments 4,571 --
Accounts payable 46,626 30,704
Related party payables 7,080 6,293
Accrued taxes other than income 33,081 32,563
Accrued interest 17,446 16,530
---------- ----------
Total current liabilities 110,998 91,216
---------- ----------
Long-term debt, net of current maturities 1,352,777 1,325,232
---------- ----------
Minority interests in partners' equity 274,510 290,142
---------- ----------
Reserves and deferred credits:
Deferred income taxes 10,311 7,186
Derivative financial instruments 2,362 840
Regulatory liabilities 2,591 2,232
Other 8,628 8,508
---------- ----------
Total reserves and deferred credits 23,892 18,766
---------- ----------
Commitments and contingencies (Note 13)
Partners' equity:
General Partners 15,351 15,603
Common Units, 46,397,214 units outstanding at
December 31, 2005, and 2004 752,191 764,550
Accumulated other comprehensive income (loss) (1,953) 9,181
---------- ----------
Total partners' equity 765,589 789,334
---------- ----------
Total liabilities and partners' equity $2,527,766 $2,514,690
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
YEARS ENDED DECEMBER 31,
------------------------------
2005 2004 2003
-------- -------- --------
(In thousands except
per unit amounts)
Operating revenue $678,560 $590,383 $550,948
-------- -------- --------
Operating expenses
Product purchases 167,257 103,213 80,774
Operations and maintenance 129,950 111,142 127,623
Depreciation and amortization, including impairment charges
of $219,080 in 2003 86,010 86,431 299,791
Taxes other than income 38,575 36,212 35,443
-------- -------- --------
Operating expenses 421,792 336,998 543,631
-------- -------- --------
Operating income 256,768 253,385 7,317
-------- -------- --------
Interest expense
Interest expense 87,690 77,346 79,159
Interest expense capitalized (787) (403) (179)
-------- -------- --------
Interest expense, net 86,903 76,943 78,980
-------- -------- --------
Other income (expense)
Allowance for equity funds used during construction 527 117 331
Equity earnings of unconsolidated affiliates 24,736 18,015 18,815
Other income 3,552 3,654 5,992
Other expense (707) (2,138) (1,459)
-------- -------- --------
Other income, net 28,108 19,648 23,679
-------- -------- --------
Minority interest in net income 45,674 50,033 44,460
-------- -------- --------
Income (loss) from continuing operations before income taxes 152,299 146,057 (92,444)
Income taxes 5,792 5,136 4,705
-------- -------- --------
Income (loss) from continuing operations 146,507 140,921 (97,149)
Discontinued operations, net of tax 506 3,799 9,338
Cumulative effect of change in accounting principle, net of tax -- -- (643)
-------- -------- --------
Net income (loss) to partners $147,013 $144,720 $(88,454)
======== ======== ========
Calculations of limited partners' interest in net income (loss):
Net income (loss) to partners $147,013 $144,720 $(88,454)
Less: General partners' interest in net income (loss) 10,900 10,854 5,969
-------- -------- --------
Limited partners' interest in net income (loss) $136,113 $133,866 $(94,423)
======== ======== ========
Limited partners' per unit net income (loss):
Income (loss) from continuing operations $ 2.92 $ 2.81 $ (2.27)
Discontinued operations, net of tax 0.01 0.08 0.20
Cumulative effect of change in accounting principle, net of tax -- -- (0.01)
-------- -------- --------
Net income (loss) $ 2.93 $ 2.89 $ (2.08)
======== ======== ========
Number of units used in computation 46,397 46,397 45,370
======== ======== ========
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31,
------------------------------
2005 2004 2003
-------- -------- --------
(In thousands)
Net income (loss) to partners $147,013 $144,720 $(88,454)
Other comprehensive income:
Changes associated with current period hedging transactions (10,560) 5,263 (4,383)
Changes associated with current period foreign currency
translation (574) (1,558) 2,345
-------- -------- ---------
Total comprehensive income (loss) $135,879 $148,425 $(90,492)
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31,
---------------------------------
2005 2004 2003
--------- --------- ---------
(In thousands)
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss) to partners $ 147,013 $ 144,720 $ (88,454)
--------- --------- ----------
Adjustments to reconcile net income (loss) to partners
to net cash provided by operating activities:
Depreciation and amortization, including impairment
charges of $219,080 in 2003 86,361 87,203 301,977
Minority interests in net income 45,674 50,033 44,460
Non-cash gains from risk management activities (106) (460) (209)
Provisions for regulatory refunds -- -- 261
Regulatory refunds paid -- -- (10,261)
Cumulative effect of change in accounting principle -- -- 643
Gain on sale of gathering and processing assets -- (6,621) (4,872)
Equity earnings in unconsolidated affiliates (24,736) (18,015) (18,928)
Distributions received from unconsolidated affiliates 16,440 12,536 17,672
Allowance for equity funds used during construction (527) (117) (331)
Reserves and deferred credits (340) (1,337) 3,062
Changes in components of working capital 3,673 (19,243) (18,592)
Other (6,080) (4,041) (1,768)
--------- --------- ---------
Total adjustments 120,359 99,938 313,114
--------- --------- ---------
Net cash provided by operating activities 267,372 244,658 224,660
--------- --------- ---------
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment (59,882) (43,477) (30,282)
Acquisition of businesses -- -- (123,194)
Sale of gathering and processing assets -- 22,685 40,250
Investment in unconsolidated affiliates (8,537) (84) (3,514)
--------- --------- ---------
Net cash used in investing activities (68,419) (20,876) (116,740)
--------- --------- ---------
CASH FLOW FROM FINANCING ACTIVITIES
Cash distributions:
General and limited partners (159,624) (159,624) (155,173)
Minority interests (60,870) (61,690) (46,194)
Equity contributions from minority interests -- 61,500 --
Issuance of partnership interests, net -- (40) 102,203
Issuance of long-term debt 165,000 259,000 342,000
Retirement of long-term debt (130,182) (327,521) (361,129)
Proceeds upon termination of derivatives (2,785) 7,575 12,250
Debt reacquisition costs -- (4,897) --
Long-term debt financing costs (1,382) -- (671)
--------- --------- ---------
Net cash used in financing activities (189,843) (225,697) (106,714)
--------- --------- ---------
Net change in cash and cash equivalents 9,110 (1,915) 1,206
Cash and cash equivalents at beginning of year 33,980 35,895 34,689
--------- --------- ---------
Cash and cash equivalents at end of year $ 43,090 $ 33,980 $ 35,895
========= ========= =========
Changes in components of working capital:
Accounts receivable (12,840) (12,992) (3,135)
Materials and supplies, prepaid expenses and other (1,180) 3,355 (3,833)
Accounts payable 16,260 (10,065) (8,525)
Accrued taxes other than income 518 (1,145) 437
Accrued interest 915 1,604 (3,536)
--------- --------- ---------
Total $ 3,673 $ (19,243) $ (18,592)
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
ACCUMULATED
OTHER TOTAL
GENERAL COMMON COMPREHENSIVE PARTNERS'
PARTNERS UNITS INCOME (LOSS) EQUITY
-------- --------- ------------- ---------
(In thousands)
Partners' equity at December 31, 2002 $ 18,730 $ 917,791 $ 7,514 $ 944,035
Net income (loss) to partners 5,969 (94,423) -- (88,454)
Changes associated with current period
hedging transactions -- -- (4,383) (4,383)
Changes associated with current period
foreign currency translation -- -- 2,345 2,345
Issuance of partnership interests, net
(2,587,500 common units) 2,044 100,159 -- 102,203
Distributions paid (10,841) (144,332) -- (155,173)
-------- --------- -------- ---------
Partners' equity at December 31, 2003 15,902 779,195 5,476 800,573
Net income to partners 10,854 133,866 -- 144,720
Changes associated with current period
hedging transactions -- -- 5,263 5,263
Changes associated with current period
foreign currency translation -- -- (1,558) (1,558)
Issuance of partnership interests, net (1) (39) -- (40)
Distributions paid (11,152) (148,472) -- (159,624)
-------- --------- -------- ---------
Partners' equity at December 31, 2004 15,603 764,550 9,181 789,334
Net income to partners 10,900 136,113 -- 147,013
Changes associated with current period
hedging transactions -- -- (10,560) (10,560)
Changes associated with current period
foreign currency translation -- -- (574) (574)
Distributions paid (11,152) (148,472) -- (159,624)
-------- --------- -------- ---------
Partners' equity at December 31, 2005 $ 15,351 $ 752,191 $ (1,953) $ 765,589
======== ========= ============= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Partners, L.P., through a subsidiary limited partnership,
Northern Border Intermediate Limited Partnership, both Delaware limited
partnerships, collectively referred to herein as the Partnership, owns a 70%
general partner interest in Northern Border Pipeline Company (Northern Border
Pipeline). The remaining 30% general partner interest in Northern Border
Pipeline is owned by TC PipeLines Intermediate Limited Partnership (TC
PipeLines). Crestone Energy Ventures, L.L.C. (Crestone Energy Ventures); Bear
Paw Energy, LLC (Bear Paw Energy); Border Midstream Services, Ltd. (Border
Midstream); Midwestern Gas Transmission Company (Midwestern Gas Transmission);
Viking Gas Transmission Company (Viking Gas Transmission) and Black Mesa
Pipeline, Inc. (Black Mesa) are wholly-owned subsidiaries of the Partnership.
In this report, references to "we," "us," "our" or the "Partnership"
collectively refer to Northern Border Partners, L.P. and our subsidiary,
Northern Border Intermediate Limited Partnership and its subsidiaries.
Northern Plains Natural Gas Company, LLC (Northern Plains), a wholly-owned
subsidiary of ONEOK, Inc. (ONEOK), Pan Border Gas Company, LLC (Pan Border), a
wholly-owned subsidiary of Northern Plains, and Northwest Border Pipeline
Company (Northwest Border), a wholly-owned subsidiary of TransCanada PipeLines
Limited, which is a subsidiary of TransCanada Corporation and an affiliate of TC
PipeLines, serve as our General Partners and collectively own a 2% general
partner interest. Northern Plains and Pan Border hold an aggregate 1.65% general
partner interest and Northwest Border holds a 0.35% general partner interest.
Northern Plains also owns common units representing a 1.1% limited partner
interest.
We are managed under the direction of the Partnership Policy Committee
consisting of one person appointed by each General Partner. The members
appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5%
and 17.5%, respectively, of the voting interest on the Partnership Policy
Committee.
In November 2004, ONEOK purchased Northern Plains, Pan Border and NBP Services
LLC (NBP Services) from CCE Holdings, LLC (CCE Holdings). CCE Holdings, a joint
venture between Southern Union Company and GE Commercial Finance Energy
Financial, purchased Northern Plains, Pan Border and NBP Services as part of its
acquisition of CrossCountry Energy, LLC (CrossCountry) from Enron Corp.
On March 31, 2004, Enron Corp. (Enron) transferred its ownership interest in
Northern Plains, Pan Border, and NBP Services to CrossCountry. In addition,
CrossCountry and Enron entered into a transition services agreement pursuant to
which Enron would provide to CrossCountry, on an interim, transitional basis,
various services, including but not limited to (i) information technology
services, (ii) accounting system usage rights and administrative support and
(iii) payroll, employee benefits and administrative services. In turn, these
services are provided to us through Northern Plains and NBP Services.
As part of the closing of its purchase of Northern Plains, Pan Border, and NBP
Services, ONEOK and CCE Holdings entered into a transition services agreement
referred to as the "Northern Border Transition Services Agreement" covering
certain transition services by and among ONEOK, CCE Holdings and Enron for a
period of six months. Certain of the services previously provided by Enron are
now being provided by ONEOK.
We have entered into an administrative services agreement with NBP Services, a
wholly-owned subsidiary of ONEOK. NBP Services provides certain administrative,
operating and management services to us and our gas gathering and processing and
coal slurry businesses and is reimbursed for its direct and indirect costs and
expenses. The day-to-day management of Northern Border Pipeline's, Midwestern
Gas Transmission's and Viking Gas Transmission's affairs is the responsibility
of Northern Plains, as defined by their respective operating agreements with
Northern Plains. Northern Border Pipeline, Midwestern Gas Transmission and
Viking Gas Transmission are charged for the salaries, benefits and expenses of
Northern Plains. Northern Plains and NBP Services also utilize their affiliates
for management services, including those provided through the Northern Border
Transition Services Agreement. For the years ended December 31, 2005, 2004 and
2003, charges from NBP Services, Northern Plains and their affiliates totaled
approximately $52.6 million, $45.8 million and $57.6 million, respectively.
F-8
Northern Border Pipeline is a Texas general partnership formed in 1978. Northern
Border Pipeline owns a 1,249-mile natural gas transmission pipeline system
extending from the United States-Canadian border near Port of Morgan, Montana,
to a terminus near North Hayden, Indiana.
Northern Border Pipeline is managed by a Management Committee that includes
three representatives from the Partnership (one representative appointed by each
of our General Partners) and one representative from TC PipeLines. Our
representatives selected by Northern Plains, Pan Border and Northwest Border
have 35%, 22.75% and 12.25%, respectively, of the voting interest on the
Northern Border Pipeline Management Committee. The representative designated by
TC PipeLines votes the remaining 30% interest.
Midwestern Gas Transmission system consists of a 350-mile interstate natural gas
pipeline extending from Portland, Tennessee to Joliet, Illinois. Midwestern Gas
Transmission's pipeline system connects with multiple pipeline systems,
including Northern Border Pipeline.
On January 17, 2003, we acquired Viking Gas Transmission (see Note 3). The
Viking Gas Transmission system is a 578-mile interstate natural gas pipeline
extending from the United States-Canadian border near Emerson, Manitoba to
Marshfield, Wisconsin. Viking Gas Transmission connects with multiple pipeline
systems.
Bear Paw Energy has extensive natural gas gathering, processing and
fractionation operations in the Williston Basin in Montana, North Dakota and
Saskatchewan as well as gas gathering operations in the Powder River Basin in
Wyoming. In the Williston Basin, Bear Paw Energy has over 3,500 miles of
gathering pipelines and five processing plants with 94 million cubic feet per
day of capacity. Bear Paw Energy has approximately 420 miles of high and low
pressure gathering pipelines and approximately 396,000 acres of dedicated
reserves in the Powder River Basin.
Border Midstream previously owned the Mazeppa and Gladys gas processing plants,
gas gathering systems and an undivided minority interest in the Gregg Lake/Obed
Pipeline. In June 2003, we sold our Gladys and Mazeppa processing plants and
related gas gathering facilities. Effective December 1, 2004, we sold our
undivided minority interest in the Gregg Lake/Obed Pipeline (see Note 3).
We own a 49% common membership interest in Bighorn Gas Gathering, L.L.C.
(Bighorn); a 37% interest in Fort Union Gas Gathering, L.L.C. (Fort Union); a
35% interest in Lost Creek Gathering, L.L.C. (Lost Creek); and a 33-1/3%
interest in Guardian Pipeline, L.L.C. (Guardian Pipeline). We acquired our
interest in Guardian Pipeline in January 2003 (see Note 3).
Collectively, Bighorn, Fort Union and Lost Creek own over 430 miles of gas
gathering facilities in Wyoming. The gathering facilities interconnect to the
interstate gas pipeline grid serving gas markets in the Rocky Mountains, the
Midwest and California. Guardian Pipeline is a 143-mile interstate natural gas
pipeline system that transports natural gas from Joliet, Illinois to a point
west of Milwaukee, Wisconsin.
Black Mesa owns a 273-mile, 18-inch diameter coal slurry pipeline that
originates at a coal mine in Kayenta, Arizona and ends at the 1,500 megawatt
Mohave Generating Station located in Laughlin, Nevada. On December 31, 2005, we
shut down our coal slurry pipeline operation (see Note 13).
F-9
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION AND USE OF ESTIMATES
The consolidated financial statements include the assets, liabilities and
results of operations for our majority-owned subsidiaries. We operate through a
subsidiary limited partnership of which the Partnership is the sole limited
partner and our General Partners are the sole general partners. The 30%
ownership of Northern Border Pipeline by TC PipeLines is accounted for as a
minority interest. All significant intercompany balances and transactions have
been eliminated in consolidation.
The preparation of financial statements in conformity with U.S. generally
accepted accounting principles (U.S. GAAP) requires management to make
assumptions and use estimates that affect the reported amount of assets,
liabilities, revenue and expenses as well as the disclosure of contingent assets
and liabilities during the reporting period. Actual results could differ from
these estimates if the underlying assumptions are incorrect.
GOVERNMENT REGULATION
Our interstate pipelines are subject to regulation by the Federal Energy
Regulatory Commission (FERC). These companies' 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 reflected on the balance sheet as
regulatory assets. We continually assess the potential recovery of the
regulatory assets based on such factors as regulatory changes and the impact of
competition to determine the probability of future recoverability of these
assets. We believe the recovery of the existing regulatory assets is probable.
If future recovery ceases to be probable, we would be required to write off the
regulatory assets at that time. At December 31, 2005 and 2004, we have reflected
regulatory assets, which are currently being recovered or are expected to be
recovered from their shippers, of approximately $14.2 million and $12.3 million,
respectively. The companies are recovering the regulatory assets from their
shippers over varying time periods up to 44 years.
The following table presents a summary of regulatory assets, net of
amortization, at December 31, 2005 and 2004.
DECEMBER 31,
-----------------
2005 2004
------- -------
(In thousands)
Fort Peck lease option $ 4,402 $ 1,887
Unamortized loss on reacquired debt 1,503 2,630
Pipeline extension project 7,106 7,290
Other 1,142 501
------- -------
Total regulatory assets $14,153 $12,308
======= =======
Our regulatory liabilities are related to the incremental costs of removal upon
retirement of an asset and represent revenue collected for asset removal costs
that we expect to incur in the future. These are costs incurred in the normal
course of business and are not related to asset retirement obligations. As of
December 31, 2005 and 2004, we reflected regulatory liabilities of $2.6 million
and $2.2 million, respectively.
Although Northern Border Pipeline is a general partnership, Northern Border
Pipeline's tariff establishes the method of accounting for and calculating
income taxes and requires Northern Border Pipeline to reflect in its financial
records the income taxes, which would have been paid or accrued if Northern
Border Pipeline were organized during the period as a corporation. As a result,
for purposes of determining transportation rates in calculating the return
allowed by the FERC, partners' capital and rate base are reduced by the amount
equivalent to the net accumulated deferred income taxes. Such amounts were
approximately $360 million and $355 million at December 31, 2005 and 2004,
respectively, and are primarily related to accelerated depreciation and other
plant-related differences.
CASH AND CASH EQUIVALENTS
Cash equivalents consist of highly liquid investments with original maturities
of three months or less. The carrying amount of cash and cash equivalents
approximates fair value due to the short maturity of these investments.
F-10
REVENUE RECOGNITION
Our interstate natural gas pipelines transport gas for shippers under tariffs
regulated by the FERC. For the interstate natural gas pipeline segment, we
recognize revenue according to each transportation contract for transportation
service that is provided to our customers. Customers with firm service
transportation agreements pay a reservation fee for capacity on our pipelines,
known as a demand charge, regardless of whether the shipper actually utilizes
its reserved capacity. Firm service transportation customers also pay a fee
based on the volume of natural gas transported. Customers with interruptible
service transportation agreements may utilize available capacity on our
pipelines; however, service is subject to interruption if capacity is required
for customers with firm transportation agreements. Interruptible service
customers are assessed a fee based only on the volume of natural gas
transported. The interstate pipelines do not own the gas that they transport,
and therefore do not assume the related natural gas commodity risk.
For the gas gathering and processing segment, operating revenue is recorded when
gas is processed in or transported through company facilities. Operating revenue
of the natural gas gathering and processing segment is derived primarily from
percentage-of-proceeds and fee-based contracts. Under percentage-of-proceeds
contracts, we retain a percentage of the commodities that we gather and process
in exchange for our services. We then sell the natural gas and natural gas
liquids we retain in the open market. Product purchases reflect the amounts we
paid to producers for raw natural gas. The gas gathering and processing segment
also receives certain cash payments from customers in advance for gathering
services to be provided in the future. These cash payments are deferred and
recognized into operating revenues by using a percentage based on the depletion
of natural gas reserves associated with the gathering system.
Black Mesa's operating revenue is derived from a pipeline transportation
agreement that expired at the end of 2005 (see Note 13). Black Mesa's revenue is
recognized based on a contracted demand payment, actual tons of coal transported
and direct reimbursement of certain other expenses.
Accounts receivable from customers are reviewed regularly for collectibility. An
allowance for doubtful accounts is recorded in situations where collectibility
is not reasonably assured.
INCOME TAXES
We are not a taxable entity for federal income tax purposes. As such, we do not
directly pay federal income tax. Our taxable income or loss, which may vary
substantially from the net income or loss reported in the consolidated statement
of income, is includable in the federal income tax returns of each partner. The
aggregate difference in the basis of our net assets for financial and income tax
purposes cannot be readily determined as we do not have access to all
information about each partner's tax attributes related to us.
Our corporate subsidiaries are required to pay federal and state income taxes.
Income taxes are accounted for under the asset and liability method. Deferred
income tax assets and liabilities are recognized by these entities for the
future tax consequences attributable to differences between the financial
statement carrying amount of existing assets and liabilities and their
respective tax bases and operating loss carry forwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled. Except for the companies whose accounting policies conform
to SFAS No. 71, the effect on deferred tax assets and liabilities of a change in
tax rates is recognized in income in the period that includes the enactment
date. For the companies whose accounting policies conform to SFAS No. 71, the
effect on deferred tax assets and liabilities of a change in tax rates is
recorded as regulatory assets and regulatory liabilities in the period that
includes the enactment date.
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION AND AMORTIZATION
Property, plant and equipment are stated at original cost. During periods of
construction, regulated entities are permitted to capitalize an allowance for
funds used during construction (AFUDC), which represents the estimated costs of
funds used for construction purposes. Property, plant and equipment on the
consolidated balance sheet include construction work in progress of $27.9
million and $13.8 million at December 31, 2005 and 2004, respectively.
The original cost of utility property retired is charged to accumulated
depreciation and amortization, net of salvage and cost of removal. For utility
property, no retirement gain or loss is included in income except in the case of
retirements or sales of entire operating units. Maintenance and repairs are
charged to operations in the period incurred.
F-11
For utility property, the provision for depreciation and amortization is an
integral part of the interstate pipelines' FERC tariffs. The effective
depreciation rate applied to the interstate transmission pipelines' plant ranges
from 1.9% to 2.25%. Composite rates are applied to all other functional groups
of utility property having similar economic characteristics. The effective
depreciation rate applied to natural gas gathering and processing assets ranges
from 5% to 33%. The effective depreciation rate applied to coal slurry assets
ranges from 1.87% to 20%.
FOREIGN CURRENCY TRANSLATION
For our Canadian subsidiary, Border Midstream, asset and liability accounts are
translated from its functional currency (the Canadian dollar) at year-end rates
of exchange and revenue and expenses are translated at average exchange rates
prevailing during the year. Translation adjustments are included as a separate
component of other comprehensive income and partners' equity. Currency
transaction gains and losses, which result when Border Midstream pays Canadian
dollars to us, are recorded in other income (expense) and discontinued
operations on the consolidated statement of income. During the years ended
December 31, 2005, 2004 and 2003, we recorded currency transaction gains of $0.6
million, $2.2 million and $6.0 million, respectively.
GOODWILL
The excess of cost over fair value of the net assets acquired in business
acquisitions is accounted for as goodwill. We account for goodwill according to
SFAS No. 142, "Goodwill and Other Intangible Assets." Among other things, SFAS
No. 142 requires entities to perform annual impairment tests by applying a
fair-value-based analysis on the goodwill in each reporting segment.
EQUITY METHOD OF ACCOUNTING
We account for our investments, which we do not control, by the equity method of
accounting. Under this method, an investment is carried at its acquisition cost,
plus the equity in undistributed earnings or losses since acquisition.
NATURAL GAS IMBALANCES
Natural gas imbalances occur when the actual amount of natural gas delivered
from or received by a pipeline system or storage facility differs from the
contractual amount of natural gas to be delivered or received. Imbalances due to
or from shippers and operators are valued at an appropriate index price.
Imbalances are settled in cash or made up in-kind, subject to the terms of the
pipelines' tariffs.
Imbalances due from others are reported on the balance sheet as accounts
receivable. Imbalances owed to others are reported on the balance sheet as
accounts payable. In addition, all imbalances are classified as current.
RISK MANAGEMENT
We use financial instruments in the management of our interest rate and
commodity price exposure. A control environment has been established which
includes policies and procedures for risk assessment and the approval, reporting
and monitoring of financial instrument activities. We do not use these
instruments for trading purposes. SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 137 and SFAS No.
138, requires that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded on the balance sheet as
either an asset or liability measured at its fair value. We determine the fair
value of a derivative instrument by the present value of its future cash flows
based on market prices from third party sources. We record changes in the
derivative's fair value in the current period earnings unless specific hedge
accounting criteria are met. Accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires us to formally document, designate and assess
the effectiveness of transactions that receive hedge accounting. See Note 9 for
a discussion of our derivative instruments and hedging activities.
UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE
We amortize premiums, discounts and expenses incurred in connection with the
issuance of long-term debt consistent with the terms of the respective debt
instrument.
OPERATING LEASES
We have non-cancelable operating leases on office space, pipeline equipment,
rights-of-way and vehicles. We record rent expense over the lease term as it
becomes payable. If operating leases include escalating rental payments, we
determine the cumulative rental payments anticipated and recognize rent expense
on a straight-line basis over the term of the lease.
F-12
CONTINGENCIES
Our accounting for contingencies covers a variety of business activities
including contingencies for legal exposures and environmental exposures. We
accrue these contingencies when our assessments indicate that it is probable
that a liability has been incurred or an asset will not be recovered and an
amount can be reasonably estimated in accordance with SFAS No. 5, "Accounting
for Contingencies." We base our estimates on currently available facts and our
estimates of the ultimate outcome or resolution. Actual results may differ from
our estimates resulting in an impact, positive or negative, on earnings.
IMPAIRMENT OF LONG-LIVED ASSETS
We assess our long-lived assets for impairment based on SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." A long-lived
asset is tested for impairment whenever events or changes in circumstances
indicate that its carrying amount may exceed its fair value. Fair values are
based on the sum of the undiscounted future cash flows expected to result from
the use and eventual disposition of the assets.
RECLASSIFICATIONS
Certain reclassifications have been made to the consolidated financial
statements for prior years to conform to the current year presentation.
3. BUSINESS ACQUISITIONS AND DISPOSITIONS
On January 17, 2003, we acquired all of the common stock of Viking Gas
Transmission, including a one-third interest in Guardian Pipeline, for
approximately $162 million, which included the assumption of $40 million of
debt.
We have accounted for the acquisition using the purchase method of accounting
and accordingly, operations of Viking Gas Transmission have been included since
the date of acquisition. The purchase price has been allocated based upon the
estimated fair value of the assets and liabilities acquired as of the
acquisition date. The investment in Guardian Pipeline, is reflected in
investments in unconsolidated affiliates on the consolidated balance sheet.
The following is a summary of the effects of the acquisition on our consolidated
financial position as of December 31, 2003:
DECEMBER 31,
2003
--------------
(In thousands)
Current assets $ 8,804
Property, plant and equipment 127,619
Investments in unconsolidated affiliates 27,600
Other assets 5,035
Current liabilities (5,559)
Long-term debt, including current maturities (40,025)
Other liabilities (280)
--------
$123,194
========
Border Midstream sold its undivided minority interest in the Gregg Lake/Obed
Pipeline (Gregg Lake/Obed) for $14.0 million, effective December 1, 2004. In
June 2003, Border Midstream sold its Gladys and Mazeppa processing plants and
related gas gathering facilities located in Alberta, Canada for approximately
$40.3 million. Operating revenues, operating expenses and other income and
expense have been classified as discontinued operations. Operating revenues for
discontinued operations for the years ended December 31, 2004 and 2003, were
$3.0 million and $9.9 million, respectively. No operating revenues were
recognized in 2005. Discontinued operations on the accompanying consolidated
statement of income consists of the following:
F-13
DECEMBER 31,
-------------------------
2005 2004 2003
------ ------- ------
(In thousands)
Operating income (loss) $ (58) $ 2,248 $3,259
Other income (expense) 1,319 (540) 1,747
Gain on sale of assets -- 5,026 4,056
Income tax (expense) benefit (755) (2,935) 276
------ ------- ------
Income for discontinued operations $ 506 $ 3,799 $9,338
====== ======= ======
4. GOODWILL AND ASSET IMPAIRMENT
At December 31, 2005 and 2004, our balance sheet included goodwill of
approximately $339 million and $334 million, respectively. Of the total
goodwill, approximately $186 million and $182 million were recorded in our
investment in unconsolidated affiliates at December 31, 2005 and 2004,
respectively. We have selected the fourth quarter to perform our annual
impairment testing unless conditions indicate earlier testing is needed. If
testing indicates an impairment of goodwill exists in a reporting segment, the
carrying value of tangible assets in that segment is also tested for impairment
under SFAS No. 144.
During 2003, due to lower throughput volumes experienced and anticipated in our
wholly owned subsidiaries in our natural gas gathering and processing business
segment, we accelerated our annual impairment test under SFAS No. 142 from the
fourth quarter to the third quarter for this segment. We engaged the services of
an outside independent consultant to assist in the determination of fair value,
as defined by SFAS No. 142, for purposes of computing the amount of the goodwill
impairment. Upon the determination of the existence of goodwill impairment, we
further analyzed, under SFAS No. 144, the carrying value of the tangible assets
in our wholly owned subsidiaries in our natural gas gathering and processing
business segment to determine the impairment attributed to the tangible assets.
We recorded total impairment charges of $219.1 million in the third quarter of
2003. This was comprised of $76.0 million related to the tangible assets in the
Powder River Basin and $143.1 million for the goodwill related to the natural
gas gathering and processing business segment. Beginning October 1, 2003, the
estimated depreciable life of our assets in the Powder River Basin was reduced
from 30 years to 15 years to reflect the results of the analysis performed.
Changes in the carrying amount of goodwill for the years ended December 31, 2005
and 2004, are summarized as follows:
INTERSTATE NATURAL GAS
NATURAL GAS GATHERING & COAL SLURRY
PIPELINE PROCESSING PIPELINE TOTAL
----------- ----------- ----------- --------
(In thousands)
Balance at December 31, 2003 $70,399 $255,567 $8,378 $334,344
Impairment losses -- -- -- --
------- -------- ------ --------
Balance at December 31, 2004 70,399 255,567 8,378 334,344
Impairment losses -- -- -- --
Goodwill acquired -- 4,196 -- 4,196
------- -------- ------ --------
Balance at December 31, 2005 $70,399 $259,763 $8,378 $338,540
======= ======== ====== ========
5. ASSET RETIREMENT OBLIGATIONS
In some instances, our subsidiaries are obligated by contractual terms or
regulatory requirements to remove facilities or perform other remediation upon
retirement. We have, where possible, developed our estimate of the retirement
obligations. We have determined that asset retirement obligations exist for
certain of our transmission assets and gas gathering and processing assets;
however, the fair value of the obligations cannot be determined because the end
of the system life is not determinable with the degree of accuracy necessary to
currently establish a liability for the obligations.
F-14
Effective January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
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 change in accounting
principle. A reconciliation of the beginning and ending aggregate carrying
amount of our asset retirement obligations for the years ended December 31,
2005, 2004 and 2003, is as follows:
(In thousands)
--------------
Balance at December 31, 2002 $ --
Cumulative effect of transition adjustment 3,496
Accretion expense 159
Liabilities transferred with asset sales (2,016)
-------
Balance at December 31, 2003 1,639
Accretion expense 102
-------
Balance at December 31, 2004 1,741
Accretion expense 114
Revision in estimated cash flows 479
-------
Balance at December 31, 2005 $ 2,334
=======
In March 2005, the Financial Accounting Standards Board (FASB) issued
Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement
Obligations - an interpretation of SFAS No. 143." The statement clarifies the
term "conditional asset retirement obligation," as used in SFAS No. 143, and the
circumstances under which an entity would have sufficient information to
reasonably estimate the fair value of an asset retirement obligation. We adopted
FIN 47 effective December 31, 2005. The effect of adopting FIN 47 was not
material to our results of operations or financial position.
6. RATES AND REGULATORY ISSUES
The FERC regulates the rates and charges for transportation on our interstate
natural gas pipelines. Interstate natural gas pipeline companies may not charge
rates that have been determined to be unjust and unreasonable 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 prudent historical
cost investment. The rates, terms and conditions for service are found in each
pipeline's FERC-approved tariff. 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.
As required by the provisions of the settlement of its last rate case, on
November 1, 2005, Northern Border Pipeline filed a rate case with the FERC. The
rate case filing proposes, among other things, a 7.8% increase to Northern
Border Pipeline's revenue requirement; a change to its rate design approach with
a supply zone and market area utilizing a fixed rate and a dekatherm-mile rate,
respectively; a compressor usage surcharge primarily to recover costs related to
powering electric compressors; and implementation of a short-term, rate
structure on a prospective basis. Also included in the filing is the
continuation of the inclusion of income taxes in the calculation of Northern
Border Pipeline's rates.
In December 2005, the FERC issued an order that identified issues that were
raised in the proceeding, accepted the proposed rates but suspended their
effectiveness until May 1, 2006, at which time the new rates will be collected
subject to refund until final resolution of the rate case. The FERC also issued
a procedural schedule which set a hearing commencement date of October 4, 2006,
with an initial decision scheduled for February 2007, unless a settlement of the
issues is reached with FERC and a majority of Northern Border Pipeline's
customers. At this time, Northern Border Pipeline can give no assurance as to
the outcome on any of these issues.
In February 2003, Northern Border Pipeline filed to amend its FERC tariff to
clarify the definition of company use gas, which is gas supplied by its shippers
for its operations. Northern Border Pipeline had included in its retention of
company use gas, quantities that were equivalent to the cost of electric power
at its electric-driven compressor stations during the period of June 2001
through January 2003. On March 27, 2003, the FERC issued an order rejecting
Northern
F-15
Border Pipeline's proposed tariff sheet revision and requiring refunds with
interest within 90 days of the order. Northern Border Pipeline made refunds to
its shippers of $10.3 million in May 2003.
Midwestern Gas Transmission and Viking Gas Transmission have no timing
requirements or restriction in regard to future rate case filings.
7. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS
Operating revenues for our interstate natural gas pipelines are collected
pursuant to their FERC tariffs through transportation service agreements.
Northern Border Pipeline's firm service agreements extend for various terms with
termination dates that range from December 2005 to December 2013. The
termination dates for Midwestern Gas Transmission's firm service agreements
range from October 2006 to October 2020. The termination dates for Viking Gas
Transmission's firm service agreements range from September 2006 to October
2014. Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas
Transmission also have interruptible transportation service agreements and other
transportation service agreements with numerous shippers.
Under the capacity release provisions of the interstate pipelines' FERC tariffs,
shippers are allowed to release all or part of their capacity either permanently
for the full term of the contract or temporarily. A temporary capacity release
does not relieve the original contract shipper from its payment obligations if
the replacement shipper fails to pay for the capacity temporarily released to
it.
For the interstate natural gas pipeline segment, Northern Border Pipeline's
revenues represented approximately 85%, 86% and 86% of the segment's revenues in
2005, 2004 and 2003, respectively. At December 31, 2005, Northern Border
Pipeline's largest shippers, BP Canada Energy Marketing Corp. (BP Canada) and
Nexen Marketing, U.S.A. Inc (Nexen), were obligated for approximately 20% and
12% of its design capacity, respectively. The BP Canada and Nexen firm service
agreements extend for various terms with termination dates from March 2006 to
February 2012 and December 2005 to December 2013, respectively.
For the year ended December 31, 2005, shippers providing significant operating
revenues were BP Canada, Nexen, EnCana Marketing (USA) Inc. (EnCana) and
Cargill Inc. (Cargill) with revenues of $56.1 million, $38.1 million,
$37.9 million and $34.1 million, respectively. For the year ended December 31,
2004, shippers providing significant operating revenues were BP Canada and
EnCana with revenues of $65.6 million and $56.3 million, respectively. For the
year ended December 31, 2003, Northern Border Pipeline's significant shippers
were BP Canada, EnCana, and Pan-Alberta Gas (U.S) Inc., with operating revenues
of $54.7 million, $32.9 million and $45.5 million, respectively.
At December 31, 2005 and 2004, Northern Border Pipeline had contracted firm
capacity held by one shipper affiliated with one of its general partners. ONEOK
Energy Services Company LP (ONEOK Energy Services), a subsidiary of ONEOK, holds
firm service agreements representing approximately 3% of its design capacity at
December 31, 2005. The firm service agreements with ONEOK Energy Services extend
for various terms with termination dates that range from February 2006 to March
2009. ONEOK Energy Services became affiliated with Northern Border Pipeline on
November 17, 2004, in connection with ONEOK's purchase of Northern Plains.
Revenue from ONEOK Energy Services for 2005 and the period from the date of
affiliation to December 31, 2004, was $7.7 million and $1.1 million,
respectively. At December 31, 2005, and 2004, Northern Border Pipeline had
outstanding receivables from ONEOK Energy Services of $0.9 million and $0.8
million, respectively. In 2003, there was no operating revenue from
affiliates.
The gas gathering and processing businesses provide services for gathering,
treating, processing and compression of natural gas and the fractionation of
natural gas liquids. For the year ended December 31, 2005, Bear Paw Energy's
largest customers, Lodgepole Energy Marketing (Lodgepole) and BP Canada
accounted for $123.2 million (45%) and $55.8 million (20%), respectively, of
Bear Paw Energy's operating revenues. For the year ended December 31, 2004, Bear
Paw Energy's largest customers, Lodgepole, BP Canada and Montana Dakota
Utilities accounted for $82.0 million (44%), $26.7 million (14%) and $21.7
million (12%), respectively, of Bear Paw Energy's operating revenues. For the
year ended December 31, 2003, Bear Paw Energy's largest customers, Lodgepole,
Tenaska Marketing Ventures (Tenaska) and BP Canada accounted for $62.4 million
(40%), $27.3 million (18%) and $16.6 million (11%), respectively, of Bear Paw
Energy's operating revenue. Crestone Energy Venture's revenues from affiliates
totaled $0.2 million, $0.2 million and $0.1 million in 2005, 2004 and 2003,
respectively.
F-16
Black Mesa's operating revenue is derived from a transportation agreement with
Peabody Western Coal, the coal supplier for the Mohave Generating Station that
expired in December 2005. The coal slurry pipeline is the sole source of fuel
for the Mohave plant. Operating revenues under the agreement totaled $24.6
million, $22.0 million and $21.4 million for the years ended December 31, 2005,
2004, and 2003, respectively.
8. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES
Detailed information on long-term debt is as follows:
DECEMBER 31,
-----------------------
2005 2004
---------- ----------
(In thousands)
Northern Border Pipeline:
2005 Pipeline Credit Agreement - average 5.11%
at December 31, 2005, due 2010 $ 27,000 $ --
1999 Pipeline Senior Notes - 7.75%, due 2009 200,000 200,000
2001 Pipeline Senior Notes - 7.50%, due 2021 250,000 250,000
2002 Pipeline Senior Notes - 6.25%, due 2007 150,000 150,000
Viking Gas Transmission:
Series A Senior Notes - 6.65%, due 2008 6,045 8,178
Series B Senior Notes - 7.10%, due 2011 2,520 2,520
Series C Senior Notes - 7.31%, due 2012 7,311 7,311
Series D Senior Notes - 8.04%, due 2014 13,111 13,111
Northern Border Partners:
2005 Partnership Credit Agreement - average 5.18% at
December 31, 2005, due 2010 204,000 --
2004 Partnership Credit Agreement - average 3.20% at
December 31, 2004, terminated in 2005 -- 191,000
2000 Partnership Senior Notes - 8.875%, due 2010 250,000 250,000
2001 Partnership Senior Notes - 7.10%, due 2011 225,000 225,000
Bear Paw Energy:
Capital leases 61 3,110
Fair value adjustment for interst rate swaps (Note 9) (2,362) 2,555
Unamortized debt premium 22,285 27,573
---------- ----------
Subtotal 1,354,971 1,330,358
Less: Current maturities of long-term debt 2,194 5,126
---------- ----------
Long-term debt $1,352,777 $1,325,232
========== ==========
The Partnership and Northern Border Pipeline have entered into revolving credit
facilities, which are used for capital expenditures, acquisitions and general
business purposes and for refinancing existing indebtedness. Northern Border
Pipeline entered into a $175 million five-year credit agreement (2005 Pipeline
Credit Agreement) with certain financial institutions in May 2005. We entered
into a $500 million five-year credit agreement (2005 Partnership Credit
Agreement) with certain financial institutions in May 2005. Both of the
revolving credit facilities permit the Partnership and Northern Border Pipeline
to choose the lender's base rate or the London Interbank Offered Rate (LIBOR)
plus a spread (based on each of our long-term unsecured debt ratings) as the
interest rate on our outstanding borrowings, specify the portion of the
borrowings to be covered by specific interest rate options and to specify the
interest rate period. Both the Partnership and Northern Border Pipeline are
required to pay a fee on the principal commitment amounts.
On December 1, 2004, Northern Border Pipeline redeemed $75 million of the 2002
Pipeline Senior Notes. In connection with the redemption, Northern Border
Pipeline was required to pay a premium of $4.8 million and received $2.5 million
from the termination of interest rate swaps associated with the debt (see Note
9). The net loss from the redemption, including unamortized debt costs and
discounts associated with the debt, is recorded as a loss on reacquired debt and
amortized to interest expense over the remaining life of the 2002 Pipeline
Senior Notes. At December 31, 2005 and
F-17
2004, the unamortized loss on reacquired debt was $1.5 million and $2.6 million
respectively and is included in regulatory assets on the consolidated balance
sheet.
Interest paid, net of amounts capitalized, during the years ended December 31,
2005, 2004 and 2003 was $91.2 million, $77.7 million and $86.7 million,
respectively.
Aggregate repayments of long-term debt required for the next five years,
excluding payments required under Bear Paw Energy's capital leases, are as
follows: $2 million, $152 million, $2 million, $200 million and $481 million for
2006, 2007, 2008, 2009 and 2010, respectively.
Each of the 2005 Partnership and Pipeline Credit Agreements require the
Partnership and Northern Border Pipeline to comply with certain financial,
operational and legal covenants. The agreements require, among other things,
that the Partnership and Northern Border Pipeline maintain ratios of EBITDA (net
income plus minority interests in net income, interest expense, income taxes and
depreciation and amortization) to interest expense of greater than 3 to 1. The
agreements also require the maintenance of ratios of indebtedness to adjusted
EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made
during the year) of no more than 4.75 to 1 for the Partnership and 4.50 to 1 for
Northern Border Pipeline. Pursuant to the credit agreements, if one or more
acquisitions are consummated in which the aggregate purchase price is $25
million or more, the allowable ratios of indebtedness to adjusted EBITDA are
increased to 5.25 to 1 for the Partnership and 5 to 1 for Northern Border
Pipeline for two calendar quarters following the acquisition. Upon any breach of
these covenants, amounts outstanding under the 2005 Partnership and Pipeline
Credit Agreements may become due and payable immediately. As of December 31,
2005, the Partnership and Northern Border Pipeline were in compliance with these
covenants.
At December 31, 2005 and 2004, Viking Gas Transmission has four series of senior
notes outstanding. In November 2004, Viking Gas Transmission amended the
indenture on its senior notes. Prior to the amendment, Viking Gas Transmission
made monthly principal and interest payments on the four series of notes. As a
result of the amendment, three of the series of senior notes due between 2011
and 2014 require payment of interest quarterly and payment of principal at
maturity. The senior notes due in 2008 continue to require monthly principal and
interest payments. We guarantee payment of the Viking Gas Transmission senior
notes. The senior notes contain certain financial covenants and at December 31,
2005, Viking Gas Transmission was in compliance with its financial covenants.
Bear Paw Energy has entered into non-cancelable capital leases on compressors.
The capital leases incorporate annual interest rates ranging from 7.10% to 8.85%
and are for a term of five years, after which Bear Paw Energy receives ownership
of the equipment. In 2006, the capital lease obligation will expire. At December
31, 2005, the capital lease obligation is $61 thousand, which is included in the
current maturities of long-term debt on the consolidated balance sheet.
The following estimated fair values of financial instruments represent the
amount at which each instrument could be exchanged in a current transaction
between willing parties. Based on quoted market prices for similar issues with
similar terms and remaining maturities, the estimated fair value of the
aggregate of the senior notes was approximately $1,167 million and $1,205
million at December 31, 2005 and 2004, respectively. We presently intend to
maintain the current schedule of maturities for the senior notes, which will
result in no gains or losses on their respective repayment. The fair value of
the 2005 Partnership Credit Agreement and the 2005 Pipeline Credit Agreement
approximates the carrying value since the interest rates are periodically
adjusted to reflect current market conditions.
9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We reflect our 70% share of Northern Border Pipeline's accumulated other
comprehensive income in our consolidated accumulated other comprehensive income.
The remaining 30% is reflected as an adjustment to minority interests in
partners' equity. We also reflect in consolidated accumulated other
comprehensive income our ownership share of accumulated other comprehensive
income of our unconsolidated affiliates (see Note 10).
Prior to the anticipated issuance of fixed rate debt, both the Partnership and
Northern Border Pipeline have entered into forward starting interest rate swap
agreements. The interest rate swap agreements have been designated as cash flow
hedges as they hedge the fluctuations in Treasury rates and spreads between the
execution date of the swap agreements and the issuance of the fixed rate debt.
The notional amount of the interest rate swap agreements does not exceed the
expected principal amount of fixed rate debt to be issued. Upon issuance of the
fixed rate debt, the swap agreements
F-18
were terminated and the proceeds received or amounts paid to terminate the swap
agreements were recorded in accumulated other comprehensive income and amortized
to interest expense over the term of the hedged debt. We also recorded an
adjustment to minority interests in partners' equity for Northern Border
Pipeline's terminated swap agreements.
On December 9, 2004, we entered into forward starting interest rate swap
agreements with a total notional amount of $100 million in anticipation of a
ten-year senior note issuance. These swap agreements expired in late May and
early June of 2005, which resulted in us paying $2.7 million to counterparties.
In June 2005, we entered into a Treasury lock interest rate agreement with a
notional amount of $200 million in anticipation of a ten-year senior note
issuance. In July 2005, we paid $0.1 million to the counterparty at expiration
of the Treasury lock interest rate agreement. At December 31, 2005, the
unamortized portion of these agreements in accumulated other comprehensive
income was $2.7 million. In the event we do not enter into fixed rate debt, we
would be required to expense the balance recorded in other accumulated
comprehensive income to interest expense.
During the years ended December 31, 2005, 2004 and 2003, we amortized
approximately $1.9 million, $2.1 million and $2.2 million, respectively, related
to the terminated interest rate swap agreements, as a reduction to interest
expense from accumulated other comprehensive income. We expect to amortize
approximately $1.8 million in 2006 for these agreements.
At December 31, 2005 and 2004, we had outstanding interest rate swaps with
notional amounts totaling $150 million. Under the interest rate swap agreements,
we make payments to counterparties at variable rates based on the London
Interbank Offered Rate and in return we receive payments based on a 7.10% fixed
rate. At December 31, 2005 and 2004, the average effective interest rate on our
interest rate swap agreements was 6.56% and 4.60%, respectively.
Our interest rate swap agreements have been designated as fair value hedges as
they hedge the fluctuations in the market value of the senior notes issued by us
in 2001. The accompanying consolidated balance sheet at December 31, 2005 and
2004, reflects an unrealized loss and an unrealized gain of approximately $2.4
million and $2.6 million, respectively, in derivative financial instruments with
a corresponding offset in long-term debt.
In November 2004, Northern Border Pipeline terminated its interest rate swap
agreements with notional amounts totaling $225 million and received $7.5
million. Of the total proceeds, $2.5 million related to the redemption of $75
million of the 2002 Pipeline Senior Notes (see Note 8). In March 2003, the
Partnership terminated one of its interest rate swap agreements with a notional
amount of $75 million and received $12.3 million. We used the proceeds to repay
amounts borrowed under our credit facility.
We record in long-term debt amounts received or paid related to terminated or
amended interest rate swap agreements for fair value hedges with such amounts
amortized to interest expense over the remaining life of the interest rate swap
agreement. During the years ended December 31, 2005, 2004 and 2003, we amortized
approximately $5.1 million, $3.3 million and $3.4 million, respectively, as a
reduction to interest expense. We expect to amortize approximately $5.3 million
as a reduction to interest expense in 2006 for these agreements.
Bear Paw Energy periodically enters into commodity derivatives contracts and
fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps
and collars, which have been designated as cash flow hedges, to hedge its
exposure to gas and natural gas liquid price volatility. During the years ended
December 31, 2005, 2004 and 2003, respectively, Bear Paw Energy recognized
losses of $4.8 million, $9.4 million and $8.5 million from the settlement of
derivative contracts. At December 31, 2005, the consolidated balance sheet
reflected an unrealized loss of approximately $4.6 million in derivative
financial instruments with a corresponding decrease of $4.6 million in
accumulated other comprehensive income. At December 31, 2004, the consolidated
balance sheet reflected an unrealized gain of approximately $2.0 million in
derivative financial instruments with a corresponding increase of $2.0 million
in accumulated other comprehensive income. For 2006, if prices remain at current
levels, Bear Paw Energy expects to reclassify approximately $4.6 million from
accumulated other comprehensive income as a decrease to operating revenues.
However, this decrease would be offset with increased operating revenues due to
the higher prices assumed.
F-19
10. UNCONSOLIDATED AFFILIATES
Our investments in unconsolidated affiliates which are accounted for by the
equity method are as follows:
NET DECEMBER 31,
OWNERSHIP ---------------------
INTEREST 2005 2004
--------- -------- --------
(In thousands)
Bighorn Gas Gathering (a) 49% $ 96,485 $ 92,350
Fort Union Gas Gathering (c) 37% 79,319 71,710
Lost Creek Gathering (d) 35% 78,482 74,935
Guardian Pipeline 33-1/3% 36,470 34,207
-------- --------
$290,756(b) $273,202
======== ========
(a) We held a 49% common membership interest in Bighorn and 100% of the
non-voting preferred A shares of Bighorn at December 31, 2004. In July 2005, we
negotiated a settlement agreement with our partner in Bighorn Gas Gathering
related to provisions of the joint venture agreement that provided for cash flow
incentives based on well connections to the gathering system. These incentives
were provided to us through our ownership of preferred A shares in Bighorn Gas
Gathering. In August 2005, as a result of the settlement, we recognized $5.4
million of equity earnings through our ownership of the preferred A shares due
to us for 2004 and 2005. The settlement agreement cancelled and effectively
redeemed Bighorn Gas Gathering's outstanding preferred A and B shares and
eliminated future incentives and its capital accounts were adjusted accordingly.
The preferred B shares were held by our partner in Bighorn Gas Gathering.
(b) The unamortized excess of our investments in unconsolidated affiliates over
the underlying book value of the net assets accounted for under the equity
method was $185.8 million and $181.6 million at December 31, 2005 and 2004,
respectively.
(c) In August 2005, Crestone Energy Ventures acquired, for $5.1 million, an
additional 3.7% interest in Fort Union, bringing its total interest to 37%.
(d) Crestone Energy Ventures is also entitled to receive an incentive allocation
of earnings from third party gathering service revenues recognized by Lost Creek
Gathering. As a result of the incentive, Crestone Energy Ventures' share of Lost
Creek Gathering income exceeds its 35% ownership interest.
Our equity earnings of unconsolidated affiliates are as follows:
DECEMBER 31,
---------------------------
2005 2004 2003
------- ------- -------
(In thousands)
Bighorn Gas Gathering $ 9,411 $ 5,832 $ 6,467
Fort Union Gas Gathering 6,747 5,357 5,953
Lost Creek Gathering 6,315 5,176 4,403
Guardian Pipeline 2,263 1,650 1,992
------- ------- -------
$24,736 $18,015 $18,815
======= ======= =======
F-20
Summarized combined financial information of our unconsolidated affiliates is
presented below:
DECEMBER 31,
-------------------
2005 2004
-------- --------
(In thousands)
Balance Sheet:
Current assets $ 41,700 $ 39,565
Property, plant and equipment, net 463,083 466,320
Other noncurrent assets 2,292 3,090
Current liabilities 44,786 39,131
Long-term debt 202,392 228,006
Other noncurrent liabilities 70 2,185
Accumulated other conmprehensive income 549 (2,136)
Owners' equity 259,278 241,789
DECEMBER 31,
----------------------------
2005 2004 2003
-------- ------- -------
(In thousands)
Income Statement:
Operating revenue $101,390 $92,649 $94,318
Operating expenses 34,470 34,745 31,927
Net income 49,742 39,389 42,583
Distributions paid to the Partnership $ 16,440 $12,536 $17,672
11. PARTNERS' EQUITY
At December 31, 2005 and 2004, our equity consisted of 46,397,214 common units
representing an effective 98% limited partner interest in the Partnership and a
2% general partner interest. At December 31, 2005 and 2004, approximately 1.1%
of the limited partner interest was held by Northern Plains.
Under our partnership agreement, in conjunction with the issuance of additional
common units, our general partners are required to make equity contributions to
us in order to maintain a 2% general partner interest.
In May and June 2003, we sold 2,250,000 and 337,500 common units, respectively.
The net proceeds from the sales of common units and the general partners'
contributions totaled approximately $102.2 million which were primarily used to
repay indebtedness outstanding.
Under our partnership agreement, we make distributions to our partners with
respect to each calendar quarter in an amount equal to 100% of our Available
Cash. "Available Cash" generally consists of all our cash receipts adjusted for
our cash disbursements and net changes to cash reserves. Available Cash will
generally be distributed 98% to limited partners and 2% to the general partners.
As an incentive, the General Partners' percentage interest in quarterly
distributions is increased after certain specified target levels are met. Under
the incentive distribution provisions, the General Partners receive 15% of
amounts distributed in excess of $0.605 per common unit, 25% of amounts
distributed in excess of $0.715 per unit and 50% of amounts distributed in
excess of $0.935 per unit. Our income is allocated to the General Partners and
the limited partners in accordance with their respective partnership
percentages, after giving effect to any priority income allocations for
incentive distributions that are allocated to the General Partners. For the
years ended December 31, 2005, 2004 and 2003, incentive distributions to the
General Partners totaled $8.0 million, $8.0 million and $7.7 million,
respectively.
F-21
12. NORTHERN BORDER PIPELINE CASH DISTRIBUTION POLICY
The Northern Border Pipeline partnership agreement provides that distributions
to Northern Border Pipeline's partners are to be made on a pro rata basis
according to each partner's capital account balance. The Northern Border
Pipeline Management Committee determines the amount and timing of such
distributions. Any changes to, or suspension of, the cash distribution policy of
Northern Border Pipeline requires the unanimous approval of the Northern Border
Pipeline Management Committee. In December 2003, Northern Border Pipeline's
Management Committee voted to (i) issue equity cash calls to its partners in the
total amount of $130 million in early 2004 and $90 million in 2007; (ii) fund
future growth capital expenditures with 50% equity capital contributions from
its partners; and (iii) change the cash distribution policy of Northern Border
Pipeline. Effective January 1, 2004, cash distributions are equal to 100% of
distributable cash flow as determined from Northern Border Pipeline's financial
statements based upon earnings before interest, taxes, depreciation and
amortization less interest expense and maintenance capital expenditures. On
November 30, 2004, Northern Border Pipeline issued an equity cash call to its
partners in the total amount of $75 million, which was utilized to repay
existing bank debt. This equity contribution will reduce the previously approved
2007 equity cash call from $90 million to $15 million.
13. COMMITMENTS AND CONTINGENCIES
LEGAL PROCEEDINGS
Various legal actions that have arisen in the ordinary course of business are
pending. We believe that the resolution of these issues will not have a material
adverse impact on our results of operations or financial position.
ENVIRONMENTAL LIABILITIES
We are subject to federal, state and local environmental laws and regulations.
Also, it is possible that other developments, such as increasingly stringent
environmental laws, regulations and enforcement policies could result in
substantial costs and liabilities to us.
BLACK MESA
On December 31, 2005, we shut down our coal slurry pipeline operation. The
Mohave Generating Station co-owners, Navajo Nation, Hopi Tribe, Peabody Western
Coal Company and other interested parties continue to negotiate water source and
coal supply issues and Black Mesa is working to resolve coal slurry
transportation issues so that operations may resume in the future. If there are
successful resolutions of these issues and the project receives a favorable
Environmental Impact Statement, Black Mesa will reconstruct the coal slurry
pipeline in late 2008 and 2009 for an anticipated in service date during 2010.
If the pipeline is reconstructed, we anticipate Black Mesa's capital
expenditures for the project will be in the range of $175 million to $200
million, supported by revenue from a new transportation contract. If the Mohave
Generating Station is permanently closed, we expect to incur pipeline removal
and remediation costs of approximately $1 million to $2 million, net of salvage,
and a non-cash impairment charge of approximately $10 million related to the
remaining undepreciated cost of the pipeline assets and goodwill.
We incurred one time termination costs of $0.7 million in the fourth quarter
which were reflected in the segment's operation and maintenance expense. We
expect to incur an additional $4 million to $6 million of operations and
maintenance expense in 2006 primarily related to employee stand by costs. We may
be required to take an impairment charge in accordance with SFAS No. 142 and
SFAS No. 144 prior to final resolution of the issues concerning the Mohave
Generating Station even though the project may ultimately proceed.
FIRM TRANSPORTATION OBLIGATIONS AND OTHER COMMITMENTS
Crestone Energy Ventures has firm transportation agreements with Fort Union and
Lost Creek. The Fort Union agreement expires in 2009 and the Lost Creek
agreement expires in 2010. Under these agreements, Crestone Energy Ventures must
make specified minimum payments each month. Crestone Energy Ventures recorded
expenses of $11.7 million, $11.8 million and $11.7 million for the years ended
December 31, 2005, 2004 and 2003, respectively, related to these agreements. At
December 31, 2005, the estimated aggregate amounts of such required future
payments were $11.7 million annually for 2006 through 2008, $11.1 million for
2009 and $3.7 million for 2010.
F-22
At December 31, 2005, we have guaranteed certain of our unconsolidated
affiliates performance in connection with credit agreements that expire in March
2009 and September 2009. At December 31, 2005, the collective amount of both
guarantees was $4.4 million.
OPERATING LEASES
Future minimum lease payments under non-cancelable operating leases on office
space, pipeline equipment, rights-of-way and vehicles are as follows:
Year ending December 31, (In thousands)
- ------------------------ --------------
2006 $ 3,788
2007 3,458
2008 3,384
2009 2,511
2010 2,186
Thereafter 64,849
-------
$80,176
=======
Expenses incurred related to these lease obligations for the years ended
December 31, 2005, 2004 and 2003, were $3.6 million, $3.8 million and $3.7
million, respectively.
CASH BALANCE PLAN
As further discussed in Note 19, on December 31, 2003, Enron filed a motion
seeking approval of the Bankruptcy Court to provide additional funding to, and
for authority to terminate, the Enron Corp. Cash Balance Plan and certain other
defined benefit plans. We recorded charges associated with the termination of
the cash balance plan of $6.2 million in 2003. In 2004, we reduced our expenses
by $6.2 million, since we determined that we were no longer liable for
termination costs of the Cash Balance Plan.
CAPITAL EXPENDITURES
Total capital expenditures for 2006 are estimated to be $94 million. This
includes approximately $59 million for interstate natural gas pipeline
facilities, $32 million for natural gas gathering and processing facilities and
$3 million for information technology systems. Funds required to meet the
capital requirements for 2006 are anticipated to be provided from credit
facilities and operating cash flows.
OTHER
On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian
Reservation (Tribes) filed a lawsuit in Tribal Court against Northern Border
Pipeline to collect more than $3 million in back taxes, together with interest
and penalties. The lawsuit related 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
with respect to pipeline right-of-way lease and taxation issues documented
through an Option Agreement and Expanded Facilities Lease executed in August
2004. The 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 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 paid a lump sum amount of $7.4 million and
will make additional annual option payments of approximately $1.5 million
thereafter through March 31, 2011. Of the amount paid in 2004, $1.0 million was
determined to be a settlement of previously accrued property taxes. The
remainder has been recorded in other assets on the balance sheet. Northern
Border Pipeline is seeking regulatory recovery for the settlement in its pending
rate case.
F-23
14. INCOME TAXES
Components of the income tax provision applicable to continuing operations and
income taxes paid by our corporate subsidiaries are as follows:
YEAR ENDED DECEMBER 31,
------------------------
2005 2004 2003
------ ------ ------
(In thousands)
Taxes currently payable:
Federal $2,036 $1,346 $ 900
State 390 289 311
------ ------ ------
Total taxes currently payable 2,426 1,635 1,211
Deferred taxes:
Federal 2,639 2,789 2,842
State 727 712 652
------ ------ ------
Total deferred taxes 3,366 3,501 3,494
------ ------ ------
Total tax provision $5,792 $5,136 $4,705
====== ====== ======
Income taxes paid $1,351 $5,346 $1,544
====== ====== ======
The difference between the statutory federal income tax rate and our effective
income tax rate is summarized as follows:
YEAR ENDED DECEMBER 31,
-----------------------
2005 2004 2003
----- ----- -----
Federal income tax rate 35.0% 35.0% 35.0%
Increase (decrease) as a result of:
Partnership earnings not subject to tax (35.0) (35.0) (35.0)
Corporate subsidiary earnings subject to tax 3.1 2.8 (4.1)
State taxes 0.7 0.7 (1.0)
----- ----- -----
Effective tax rate 3.8% 3.5% (5.1)%
===== ===== =====
Deferred tax assets and liabilities result from the following:
YEAR ENDED DECEMBER 31,
-----------------------
2005 2004
------- -------
(In thousands)
Deferred tax assets:
Net operating losses $11,923 $ 6,606
Plant related differences 1,941 2,333
Other 843 410
------- -------
Total deferred tax assets 14,707 9,349
------- -------
Deferred tax liabilities:
Goodwill 6,579 5,458
Accelerated depreciation and other plant-related
differences 8,618 3,514
Partnership income 9,821 7,563
------- -------
Total deferred tax liabilties 25,018 16,535
------- -------
Net deferred tax liabilities $10,311 $ 7,186
======= =======
F-24
We had available, at December 31, 2005, approximately $11.9 million of tax
benefits related to net operating loss carry forwards, which will expire between
the years 2021 and 2025. We believe that it is more likely than not that the tax
benefits of the net operating loss carry forwards will be utilized prior to
their expiration; therefore, no valuation allowance is necessary.
15. ACCOUNTING PRONOUNCEMENTS
In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment" which
requires companies to expense the fair value of share-based payments and
includes changes related to the expense calculation for share-based payments.
Northern Plains and NBP Services adopted SFAS 123R as of January 1, 2006, and
will charge us for our proportionate share of the expense recorded by Northern
Plains and NBP Services. The impact of adopting Statement 123R does not have a
material impact on our results of operations or financial position.
In June 2005, the FERC issued guidance describing how FERC-regulated companies
should account for costs associated with implementing the pipeline integrity
management requirements of the U.S. Department of Transportation's Office of
Pipeline Safety. Under the guidance, costs to 1) prepare a plan to implement the
program, 2) identify high consequence areas, 3) develop and maintain a record
keeping system and 4) inspect, test and report on the condition of affected
pipeline segments to determine the need for repairs or replacements, are
required to be expensed. Costs of modifying pipelines to permit in-line
inspections, certain costs associated with developing or enhancing computer
software and costs associated with remedial and mitigation actions to correct an
identified condition can be capitalized. The guidance is effective January 1,
2006, to be applied prospectively. The effect of adopting this order is not
expected to be material to our results of operations or financial position.
16. BUSINESS SEGMENT INFORMATION
Our business is divided into three reportable segments, defined as components of
the enterprise about which financial information is available and evaluated
regularly by our executive management and the Partnership Policy Committee in
deciding how to allocate resources to an individual segment and in assessing
performance of the segment.
Our reportable segments are strategic business units that offer different
services. Each is managed separately because each business requires different
marketing strategies. These segments are as follows: the Interstate Natural Gas
Pipeline segment provides natural gas transportation services; the Natural Gas
Gathering and Processing segment provides services for the gathering, treating,
processing and compression of natural gas and the fractionation of natural gas
liquids; and the Coal Slurry Pipeline segment transports crushed coal suspended
in water. The accounting policies of the segments are described in the summary
of significant accounting policies in Note 2.
We evaluate our performance based on EBITDA, earnings before interest, taxes,
depreciation and amortization less the allowance for equity funds used during
construction (AFUDC). Management uses EBITDA to compare the financial
performance of its segments and to internally manage those business segments.
Management believes that EBITDA provides useful information to investors as a
measure of comparability to peer companies. EBITDA should not be considered an
alternative to, or more meaningful than, net income or cash flow as determined
in accordance with U.S. GAAP. EBITDA calculations may vary from company to
company, so our computation of EBITDA may not be comparable to a similarly
titled measure of another company. The following table shows how we calculate
EBITDA:
F-25
RECONCILIATION OF NET INCOME(LOSS) TO EBITDA
NATURAL GAS
INTERSTATE GATHERING
NATURAL GAS AND COAL SLURRY
PIPELINE PROCESSING PIPELINE OTHER (A) TOTAL
----------- ----------- ----------- --------- --------
(In thousands)
2005
Net income (loss) $123,604 $ 67,552 $3,902 $(48,045) $147,013
Minority interest 45,674 -- -- -- 45,674
Interest expense, net 44,990 219 3 41,691 86,903
Depreciation and amortization 67,608 16,045 2,546 162 86,361
Income tax 4,522 24 1,246 755 6,547
AFUDC (527) -- -- -- (527)
-------- --------- ------ -------- --------
EBITDA $285,871 $ 83,840 $7,697 $ (5,437) $371,971
======== ========= ====== ======== ========
2004
Net income (loss) $134,726 $ 44,488 $3,088 $(37,582) $144,720
Minority interest 50,033 -- -- -- 50,033
Interest expense, net 43,882 369 11 32,681 76,943
Depreciation and amortization 67,487 14,851 4,465 400 87,203
Income tax 4,783 26 327 2,935 8,071
AFUDC (117) -- -- -- (117)
-------- --------- ------ -------- --------
EBITDA $300,794 $ 59,734 $7,891 $ (1,566) $366,853
======== ========= ====== ======== ========
2003
Net income (loss) $119,620 $(183,016) $3,658 $(28,716) $(88,454)
Cumulative effect of change in
accounting principle, net of tax -- -- 434 209 643
Minority interest 44,460 -- -- -- 44,460
Interest expense, net 47,577 591 33 30,779 78,980
Depreciation and amortization 66,245 232,777 1,848 1,107 301,977
Income tax 3,629 -- 1,076 (276) 4,429
AFUDC (331) -- -- -- (331)
-------- --------- ------ -------- --------
EBITDA $281,200 $ 50,352 $7,049 $ 3,103 $341,704
======== ========= ====== ======== ========
F-26
BUSINESS SEGMENT DATA
NATURAL GAS
INTERSTATE GATHERING
NATURAL GAS AND COAL SLURRY
PIPELINE PROCESSING PIPELINE OTHER (A) TOTAL
----------- ----------- ----------- --------- ----------
(In thousands)
2005
Revenue from external customers $ 378,701 $ 275,287 $24,572 $ -- $ 678,560
Depreciation and amortization 67,257 16,045 2,546 162 86,010
Operating income (loss) 214,168 44,714 5,186 (7,300) 256,768
Interest expense, net 44,990 219 3 41,691 86,903
Equity earnings of unconsolidated
affiliates 2,263 22,473 -- -- 24,736
Other income (expense), net 2,359 608 (35) 440 3,372
Income tax expense 4,522 24 1,246 -- 5,792
Capital expenditures 39,641 16,602 -- 3,639 59,882
Identifiable assets 1,852,510 340,093 16,410 27,997 2,237,010
Investments in unconsolidated
affiliates 36,470 254,286 -- -- 290,756
Total assets 1,888,980 594,379 16,410 27,997 2,527,766
2004
Revenue from external customers $ 383,625 $ 184,738 $22,020 $ -- $ 590,383
Depreciation and amortization 67,115 14,851 4,465 -- 86,431
Operating income (loss) 231,027 28,278 3,446 (9,366) 253,385
Interest expense, net 43,882 369 11 32,681 76,943
Equity earnings of unconsolidated
affiliates 1,649 16,366 -- -- 18,015
Other income (expense), net 748 239 (20) 666 1,633
Income tax expense 4,783 26 327 -- 5,136
Capital expenditures 16,258 25,646 1,573 -- 43,477
Identifiable assets 1,870,482 337,502 18,268 15,236 2,241,488
Investments in unconsolidated
affiliates 34,207 238,995 -- -- 273,202
Total assets 1,904,689 576,497 18,268 15,236 2,514,690
2003
Revenue from external customers $ 375,256 $ 154,284 $21,408 $ -- $ 550,948
Depreciation and amortization (b) 65,881 232,063 1,847 -- 299,791
Operating income (loss) 212,841 (203,067) 5,144 (7,601) 7,317
Interest expense, net 47,577 591 33 30,779 78,980
Equity earnings of unconsolidated
affiliates 1,992 16,823 -- -- 18,815
Other income (expense), net 453 3,819 57 535 4,864
Income tax expense 3,629 -- 1,076 -- 4,705
Capital expenditures 19,497 8,981 1,804 -- 30,282
Identifiable assets 1,938,249 317,182 21,319 25,667 2,302,417
Investments in unconsolidated
affiliates 32,558 235,608 -- -- 268,166
Total assets 1,970,807 552,790 21,319 25,667 2,570,583
F-27
(a) Includes other items not allocable to segments.
(b) Natural gas gathering and processing results includes goodwill and asset
impairment charges of $219,080 (see Note 4).
17. OTHER INCOME (EXPENSE)
Other income (expense) on the consolidated statement of income includes such
items as investment income, nonoperating revenues and expenses, foreign currency
gains and losses, and nonrecurring other income and expense items. For the year
ended December 31, 2003, other income also included a $3.3 million payment
received for a change in ownership of the other partner in Bighorn.
18. QUARTERLY FINANCIAL DATA (Unaudited)
PER UNIT
INCOME INCOME
FROM FROM
OPERATING OPERATING CONTINUING CONTINUING
REVENUE INCOME OPERATIONS OPERATIONS
--------- --------- ---------- ----------
(In thousands)
2005
First Quarter $160,379 $63,538 $34,279 $0.68
Second Quarter 149,417 53,464 27,732 0.54
Third Quarter 183,023 74,848 48,838 0.99
Fourth Quarter 185,741 64,918 35,658 0.71
2004
First Quarter $143,773 $61,761 $35,852 $0.71
Second Quarter 142,476 60,595 32,872 0.65
Third Quarter 147,355 62,093 34,400 0.68
Fourth Quarter 156,779 68,936 37,797 0.76
19. RELATIONSHIPS WITH ENRON
In December 2001, Enron and certain of its subsidiaries filed a voluntary
petition for bankruptcy protection under Chapter 11 of the United States
Bankruptcy Code. Until November 17, 2004, each of Northern Plains, Pan Border
and NBP Services were subsidiaries of Enron. Northern Plains, Pan Border and NBP
Services were not among the Enron companies filing for Chapter 11 protection.
Enron North America Corp. (Enron North America), a wholly owned subsidiary of
Enron that is in bankruptcy, was a party to transportation contracts which
obligated Enron North America to pay for 3.5% of Northern Border Pipeline's
capacity. Through the bankruptcy proceeding in 2002, Enron North America
rejected and terminated all of its firm transportation contracts on Northern
Border Pipeline. Northern Border Pipeline had previously fully reserved for
amounts invoiced to Enron North America. Since Enron guaranteed the obligations
of Enron North America under those contracts, Northern Border Pipeline filed
claims against both Enron North America and Enron for damages in the bankruptcy
proceedings. As a result of a settlement agreement between Enron North America,
Enron and Northern Border Pipeline, each of Enron North America and Enron agreed
to allow Northern Border Pipeline's claim of approximately $20.6 million.
In addition, Bear Paw Energy filed claims against Enron North America relating
to terminated swap agreements in the amount of $6.7 million. Also, Crestone
Energy Ventures filed claims against Enron North America for unpaid gas
gathering and administrative services fees in the amount of $2.3 million.
In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated
recovery of $3.4 million ($3.0 million, net to the Partnership) for the claims.
In June 2005, we executed term sheets with a third party for the sale of our
bankruptcy claims for contracts and associated guarantees held against Enron
Corp. and Enron North America Corp.
F-28
Proceeds from the sale of the claims were $14.6 million. In the second quarter
of 2005, we made an adjustment to our allowance for doubtful accounts of $1.8
million ($1.6 million, net to the Partnership) to reflect the agreements for the
sale. In the third quarter of 2005, Northern Border Pipeline recognized revenue
of $9.4 million ($6.6 million, net to the Partnership) as a result of the sale.
On December 31, 2003, Enron filed a motion seeking approval of the Bankruptcy
Court to provide additional funding to, and for authority to terminate, the
Enron Corp. Cash Balance Plan and certain other defined benefit plans of Enron's
affiliates (the Plans) in 'standard terminations' within the meaning of Section
4041 of the Employee Retirement Income Security Act of 1974, as amended (ERISA).
Northern Plains and NBP Services were considered members of Enron's ERISA
controlled group of corporations. As of December 31, 2003, the amount of
approximately $6.2 million was estimated for Northern Plains' and NBP Services'
proportionate share of the up to $200 million estimated termination costs for
the Plans authorized by the Bankruptcy Court order. Since under the operating
agreement with Northern Plains and the administrative agreement with NBP
Services, these costs could be our responsibility, we accrued $6.2 million to
satisfy claims of reimbursement for these termination costs. As a result of
further evaluation and negotiation of Enron's proposed allocation of the
termination costs, Northern Plains and NBP Services advised us that no claim of
reimbursement for the termination costs would be made, resulting in a reduction
in reserves during 2004 of $6.2 million for the termination costs. Pursuant to
the agreement whereby ONEOK purchased Northern Plains and NBP Services, the
purchase price under the agreements was deemed to include all contributions
which otherwise would have been allocable to Northern Plains and NBP Services.
20. SUBSEQUENT EVENTS
On January 20, 2006, we declared a cash distribution of $0.80 per unit ($3.20
per unit on an annualized basis) for the quarter ended December 31, 2005. The
distribution was paid February 14, 2006, to unitholders of record at January 31,
2006.
On February 15, 2006, we announced a series of transactions. In separate
transactions, we will sell a 20% partnership interest in Northern Border
Pipeline to TC PipeLines, for approximately $300 million. The price of the 20%
interest, along with the related share of Northern Border Pipeline's outstanding
debt, totals $420 million. Following completion of the sale, we will own a 50%
interest in Northern Border Pipeline and TC PipeLines will own the remaining 50%
interest. In 2006, Northern Border Pipeline's cash distributions will be split
equally between us and TC PipeLines. In April 2007, an affiliate of TransCanada
will become the operator of Northern Border Pipeline.
Northern Plains will purchase TransCanada's 0.35% general partner interest in
us, increasing ONEOK's general partner interest to 2%. We will acquire ONEOK's
entire gathering and processing, natural gas liquids, and pipelines and storage
segments in a transaction valued at approximately $3 billion. We will pay ONEOK
approximately $1.35 billion in cash and 36.5 million Class B units. Upon
completion of these transactions, ONEOK will own approximately 37.0 million of
our limited partner units, which, when combined with the general partner
interest acquired from TransCanada, will increase its total interest in us to
45.7%. The limited partner units and the related general partner interest
contribution are valued at approximately $1.65 billion.
Closings of the transactions are subject to regulatory approvals and other
conditions, including antitrust clearance from the Federal Trade Commission
under the Hart-Scott-Rodino Act. The transaction is expected to be completed by
April 1, 2006.
For financial reporting purposes, the transfer of the ONEOK assets to us will be
accounted for at the historical cost basis of the assets being transferred, and
accordingly we will not record any goodwill related to the transaction. As a
result of our sale of the 20% interest in Northern Border Pipeline, we will
report the pipeline's results on the equity method of accounting and therefore,
will no longer report the pipeline's results on a consolidated basis since we
will no longer have voting control. The change will be effective January 1,
2006.
F-29
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE
Northern Border Partners, L.P.:
We have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements of Northern Border Partners, L.P. and subsidiaries as of December 31,
2005 and 2004 and for each of the years in the three-year period ended December
31, 2005 included in this Form 10-K, and have issued our report thereon dated
March 2, 2006, which report includes an explanatory paragraph discussing the
adoption of FASB Statement No. 143 in 2003.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule of Northern Border Partners,
L.P. and subsidiaries listed in Item 15 of Part IV of this Form 10-K is the
responsibility of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects, the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
Omaha, Nebraska
March 2, 2006
S-1
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULEII - VALUATION AND QUALIFYING ACCOUNTS
ADDITIONS DEDUCTIONS
--------------------- FOR PURPOSE
BALANCE AT CHARGED TO CHARGED FOR WHICH BALANCE
BEGINNING COSTS AND TO OTHER RESERVES WERE AT END
OF YEAR EXPENSES ACCOUNTS CREATED OF YEAR
---------- ---------- -------- ------------- -------
(In thousands)
Reserve for regulatory
issues:
2005 $ 1,955 $ 25 $-- $ 1,350 $ 630
2004 7,644 640 -- 6,329 1,955
2003 12,294 5,611 -- 10,261 7,644
Allowance for doubtful
accounts:
2005 $ 9,175 $ 171 $-- $ 9,328 $ 18
2004 11,988 569 -- 3,382 9,175
2003 11,936 52 -- -- 11,988
S-2
Exhibit Index
#2.1 Contribution Agreement between ONEOK, Inc. and Northern Border Intermediate
Limited Partnership dated February 14, 2006.
#2.2 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border
Partners, L.P. dated February 14, 2006.
#2.3 Partnership Interest Purchase and Sale Agreement by and between Northern
Border Intermediate Limited Partnership and TC PipeLines Intermediate
Limited Partnership dated as of December 31, 2005.
*3.1 Northern Border Partners, L.P. Certificate of Limited Partnership,
Certificate of Amendment dated February 16, 2001, and Certificate of
Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.1 to
the Partnership's Form 10-K for the year ended December 31, 2004 (File No.
1-12202) ("2004 Form 10-K")).
*3.2 Amended and Restated Agreement of Limited Partnership of Northern Border
Partners, L.P. dated October 1, 1993 (incorporated by reference to Exhibit
3.2 to the 2004 Form 10-K).
*3.3 Northern Border Intermediate Limited Partnership Certificate of Limited
Partnership, Certificate of Amendment dated February 16, 2001, and
Certificate of Amendment dated May 20, 2003 (incorporated by reference to
Exhibit 3.3 to the 2004 10-K).
*3.4 Amended and Restated Agreement of Limited Partnership for Northern Border
Intermediate Limited Partnership dated October 1, 1993 (incorporated by
reference to Exhibit 3.1 to the Partnership's Form 10-Q for the quarter
ended March 31, 2005 (File No. 1-12202) ("March 2005 10-Q")).
*4.1 Indenture, dated as of June 2, 2000, between Northern Border Partners,
L.P., Northern Border Intermediate Limited Partnership and Bank One Trust
Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the
Partnership's Form 10-Q for the quarter ended June 30, 2000 (File No.
1-12202) ("June 2000 10-Q")).
*4.2 First Supplemental Indenture, dated as of September 14, 2000, between
Northern Border Partners, L.P., Northern Border Intermediate Limited
Partnership and Bank One Trust Company, N.A. (incorporated by reference to
Exhibit 4.2 to the Partnership's Form S-4 Registration Statement filed on
September 20, 2000, (Registration No. 333-46212) ("NBP Form S-4")).
*4.3 Indenture, dated as of March 21, 2001, between Northern Border Partners,
L.P. and Northern Border Intermediate Limited Partnership and Bank One
Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.3 to
the Partnership's Form 10-K for the year ended December 31, 2001 (File No.
1-12202)).
*4.4 Indenture, dated as of August 17, 1999, between Northern Border Pipeline
Company and Bank One Trust Company, NA, successor to The First National
Bank of Chicago, Trustee. (incorporated by reference to Exhibit No. 4.1 to
Northern Border Pipeline Company's Form S-4 Registration Statement filed on
October 7, 1999, (Registration No. 333-88577) ("NB Form S-4")).
*4.5 Indenture, dated as of September 17, 2001, between Northern Border Pipeline
Company and Bank One Trust Company, N.A., Trustee (incorporated by
reference to Exhibit 4.2 to Northern Border Pipeline Company's Registration
Statement on Form S-4 filed on November 13, 2001, (Registration No.
333-73282) ("2001 NB Form S-4")).
*4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline
Company and Bank One Trust Company, N.A., Trustee (incorporated by
reference to Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q
for the quarter ended March 31, 2002 (File No. 333-88577)).
*10.1 Northern Border Pipeline Company General Partnership Agreement between
Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan
Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern
Ltd., effective March 9, 1978, as amended (incorporated by reference to
Exhibit 10.2 to the Partnership's Form S-1 Registration Statement filed on
July 16, 1993, (Registration No. 33-66158) ("Form S-1")).
*10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company
General Partnership Agreement dated September 23, 1993 (incorporated by
reference to Exhibit 10.15 to Form S-1).
*10.3 Eighth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement dated May 21, 1999 (incorporated by reference to
Exhibit 10.15 to NB Form S-4).
*10.4 Ninth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement July 16, 2001 (incorporated by reference to Exhibit
10.37 to 2001 NB Form S-4).
*10.5 Tenth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement dated March 2, 2005 (incorporated by reference to
Exhibit 3.5 to Northern Border Pipeline's Form 10-K for the year ended
December 31, 2004 filed on March 14, 2005 (File No. 333-88577)).
*10.6 Operating Agreement between Northern Border Pipeline Company and Northern
Plains Natural Gas Company, dated February 28, 1980 (incorporated by
reference to Exhibit 10.3 to Form S-1).
*10.7 Administrative Services Agreement between NBP Services Corporation,
Northern Border Partners, L.P. and Northern Border Intermediate Limited
Partnership (incorporated by reference to Exhibit 10.4 to Form S-1).
*10.8 Revolving Credit Agreement, dated as of May 16, 2005, among Northern
Border Partners, L.P., the lenders from time to time party thereto,
SunTrust Bank, as administrative agent, Wachovia Bank, National
Association, as syndication agent, Harris Nesbit Financing, Inc., Barclays
Bank PLC and Citibank, N.A., as
co-documentation agents, and SunTrust Capital Markets, Inc. and Wachovia
Capital Markets, LLC, as co-lead arrangers and book managers (incorporated
by reference to Exhibit 10.1 to the Partnership's current report on Form
8-K filed on May 20, 2005 (File No. 1-12202)).
*10.9 First Amendment to the Revolving Credit Agreement effective June 13, 2005,
among Northern Border Partners, L.P., the lenders from time to time party
thereto, SunTrust Bank, as administrative agent, Wachovia Bank, National
Association, as syndication agent and Harris Nesbit Financing, Inc.,
Barclays Bank PLC and Citibank, N.A., as co-documentation agents
(incorporated by reference to Exhibit 10.2 to the Partnership's Form 10-Q
for the quarter ended June 30, 2005 (File No. 1-12202)).
*10.10 Revolving Credit Agreement, dated as of May 16, 2005, among Northern
Border Pipeline Company, the lenders from time to time party thereto,
Wachovia Bank, National Association, as administrative agent, SunTrust
Bank, as syndication agent, Harris Nesbit Financing, Inc., Barclays Bank
PLC and Citibank, N.A., as co-documentation agents, and Wachovia Capital
Markets, LLC and SunTrust Capital Markets, Inc., as co-lead arrangers and
book managers (incorporated by reference to Exhibit 10.1 to Northern Border
Pipeline Company's current report on Form 8-K (File No. 333-88577) filed on
May 20, 2005 (File No. 333-88577)).
*10.11 Agreement between Northern Plains and Northern Border Intermediate
Limited Partnership regarding the costs, expenses and expenditures arising
under the operating agreement between Northern Plains and Guardian
Pipeline, LLC (incorporated by reference to Exhibit 10.3 to the
Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No.
1-12202)).
+*10.12 Form of Termination Agreement with ONEOK, Inc. dated as of January 5,
2005 (incorporated by reference to Exhibit 99.1 to the Partnership's
current report on Form 8-K filed on January 11, 2005 (File No. 1-12202)).
+*10.13 ONEOK, Inc. Equity Compensation Plan (incorporated by reference to
Exhibit 10.1 to ONEOK's current report on Form 8-K filed on February 23,
2005 (File No. 1-13643)).
+*10.14 ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005
(incorporated by reference to Exhibit 10.2 to ONEOK's current report on
Form 8-K filed on February 23, 2005 (File No. 1-13643)).
+*10.15 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan (incorporated by
reference to Exhibit 99.2 to the Partnership's current report on Form 8-K
filed on January 11, 2005 (File No. 1-12202)).
+*10.16 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference to
Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
+*10.17 ONEOK, Inc. Form of Restricted Stock Incentive Award pursuant to
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to
ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File
No. 1-13643)).
+*10.18 ONEOK, Inc. Form of Performance Shares Award pursuant to Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.5 to ONEOK's Form
10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)).
+*10.19 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as
amended, dated February 15, 2001 (incorporated by reference to Exhibit
10(g) to ONEOK's Form 10-K for the year ended December 31, 2001(File No.
1-13643)).
+*10.20 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference to
Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
+10.21 ONEOK, Inc. Form of Restricted Unit Award Agreement pursuant to Equity
Compensation Plan.
+10.22 ONEOK, Inc. Form of Performance Unit Award Agreement pursuant to Equity
Compensation Plan.
*10.23 Operating Agreement between Midwestern Gas Transmission Company and
Northern Plains Natural Gas Company dated as of April 1, 2001 (incorporated
by reference to Exhibit 10.38 to the Partnership's Form 10-K for the year
ended December 31, 2001 (File No. 1-12202)).
*10.24 Operating Agreement between Viking Gas Transmission Company and Northern
Plains Natural Gas Company dated as of January 17, 2003 (incorporated by
reference to Exhibit 10.18 to the Partnership's Form 10-K for the year
ended December 31, 2002 (File No. 1-12202)).
*10.25 Northern Border Pipeline Company Agreement among Northern Plains Natural
Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company,
TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border
Intermediate Limited Partnership, Northern Border Partners, L.P., and the
Management Committee of Northern Border Pipeline, dated as of March 17,
1999 (incorporated by reference to Exhibit 10.21 to the Partnership's Form
10-K/A for the year ended December 31, 1998 (File No. 1-12202)).
12.1 Statement re computation of ratios.
21 List of subsidiaries.
23.1 Consent of KPMG LLP.
31.1 Rule 13a-14(a)/15d-14(a) certification of principal executive officer.
31.2 Rule 13a-14(a)/15d-14(a) Certification of principal financial officer.
32.1 Section 1350 certification of principal executive officer.
32.2 Section 1350 certification of principal financial officer.
+*99.1 Northern Border Phantom Unit Plan (incorporated by reference to Exhibit
99.1 to Amendment No. 1 to the Partnership's Form S-8, Registration
Statement filed on November 15, 2000 (Registration No. 333-66949)).
* Indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith.
+ Management contract, compensatory plan or arrangement.
# The Partnership agrees to furnish supplementally to the Securities and
Exchange Commission, upon request, any schedules and exhibits to this
agreement, as set forth in the Table of Contents of the agreement, that
have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K.