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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 2004
[ ] 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: 333-88577
NORTHERN BORDER PIPELINE COMPANY
(Exact name of registrant as specified in its charter)
TEXAS 74-2684967
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
13710 FNB PARKWAY, OMAHA, NEBRASKA 68154-5200
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: 402-492-7300
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class registered Name of each exchange on which
- ------------------------------ ------------------------------
None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [X]
Aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant on June 30, 2004, was $0.
DOCUMENTS INCORPORATED BY REFERENCE
None.
NORTHERN BORDER PIPELINE COMPANY
TABLE OF CONTENTS
PAGE NO.
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PART I
Item 1. Business 1
Item 2. Properties 12
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote of Security Holders 14
PART II
Item 5. Market for Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities 15
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk 30
Item 8. Financial Statements and Supplementary Data 30
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 30
Item 9A. Controls and Procedures 31
Item 9B. Other Information 31
PART III
Item 10. Directors and Executive Officers of Registrant 32
Item 11. Executive Compensation 35
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters 42
Item 13. Certain Relationships and Related Transactions 42
Item 14. Principal Accounting Fees and Services 43
PART IV
Item 15. Exhibits and Financial Statement Schedules 45
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PART I
ITEM 1. BUSINESS.
GENERAL
Northern Border Pipeline Company is a general partnership formed in 1978.
Our general partners are Northern Border Partners, L.P. ("Northern Border
Partners") and TC PipeLines, LP ("TC PipeLines"), both of which are publicly
traded partnerships. Each of Northern Border Partners and TC PipeLines holds its
interest in us, 70% and 30% of voting power, respectively, through a subsidiary
limited partnership. The general partners of Northern Border Partners and its
subsidiary limited partnership are Northern Plains Natural Gas Company
("Northern Plains") and Pan Border Gas Company, both subsidiaries of ONEOK, Inc.
("ONEOK"), and Northwest Border Pipeline Company, a subsidiary of TransCanada
PipeLines Limited, which is a subsidiary of TransCanada Corporation. The general
partner of TC PipeLines and its subsidiary limited partnership, TC PipeLines GP,
Inc., is also a subsidiary of TransCanada.
We own an interstate pipeline system that transports natural gas from the
Montana-Saskatchewan border to natural gas markets in the midwestern United
States. This pipeline system connects with multiple pipelines that provide
shippers with access to the various natural gas markets served by those
pipelines. For the year ended December 31, 2004, we estimate that we transported
approximately 22% of the total amount of natural gas imported from Canada to the
United States. Over the same period, approximately 88% of the natural gas
transported was produced in the western Canadian sedimentary basin located in
the provinces of Alberta, British Columbia and Saskatchewan.
We transport gas for shippers under a tariff regulated by the Federal
Energy Regulatory Commission ("FERC"). The tariff specifies the maximum and
minimum transportation rates and the general terms and conditions of
transportation service on the pipeline system. Our revenues are derived from
agreements for the receipt and delivery of gas at points along the pipeline
system as specified in each shipper's individual transportation contract. We do
not own the gas that we transport, and therefore we do not assume natural gas
commodity price risk for quantities transported. Any exposure to commodity risk
for imbalances on our system that may result from under or over deliveries to
customers or interconnecting pipelines is either recovered through provisions in
our tariff or is immaterial. We own the line pack, which is the amount of gas
necessary to maintain efficient operations of the pipeline. Our shippers are
responsible to provide fuel gas necessary for the operation of gas compressor
stations.
Our management is overseen by a four-member management committee. Three
representatives are designated by Northern Border Partners, with each of its
general partners selecting one representative; and one representative is
designated by TC PipeLines. Voting power on the management committee is
allocated among Northern Border Partners' three representatives in proportion to
their general partner interests in Northern Border Partners. As a result, the
70% voting power of
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Northern Border Partners' three representatives on the management committee is
allocated as follows: 35% to the representative designated by Northern Plains,
22.75% to the representative designated by Pan Border and 12.25% to the
representative designated by Northwest Border. Northern Plains and Pan Border
are subsidiaries of ONEOK. Therefore, ONEOK controls 57.75% of the voting power
of the management committee and has the right to select two of the members. In
November 2004, ONEOK purchased Northern Plains and Pan Border 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, LLC as part of its acquisition of CrossCountry
Energy, LLC ("CrossCountry"). See Item 7. "Management's Discussion and Analysis
of Financial Condition and Results of Operations - The Impact Of Enron's Chapter
11 Filing On Our Business."
Our pipeline system is operated by Northern Plains pursuant to an
operating agreement. As of December 31, 2004, Northern Plains employed
approximately 230 individuals located at its headquarters in Omaha, Nebraska and
at various locations along the pipeline route and also used employees and
information technology systems of its affiliates to provide its services.
Northern Plains' employees are not represented by any labor union and are not
covered by any collective bargaining agreements.
THE PIPELINE SYSTEM
We own a 1,249-mile interstate pipeline system that transports natural gas
from the Montana-Saskatchewan border near Port of Morgan, Montana to natural gas
markets in the midwestern United States. Construction of the pipeline was
initially completed in 1982. Our pipeline system was expanded and/or extended in
1991, 1992, 1998 and 2001. Our pipeline system connects directly and through
multiple pipelines to various natural gas markets in the United States.
Our pipeline system consists of: (i) 822 miles of 42-inch diameter pipe
from the Canadian border to Ventura, Iowa, capable of transporting, on a summer
design basis, a total of 2,374 million cubic feet per day ("mmcfd"); (ii)
30-inch diameter pipe and 36-inch diameter pipe, each approximately 147 miles in
length, capable of transporting 1,484 mmcfd in total from Ventura, Iowa to
Harper, Iowa; (iii) 224 miles of 36-inch diameter pipe and 21 miles of 30-inch
diameter pipe capable of transporting 844 mmcfd from Harper, Iowa to Manhattan,
Illinois (Chicago area); and (iv) 35 miles of 30-inch diameter pipe capable of
transporting 544 mmcfd from Manhattan, Illinois to a terminus near North Hayden,
Indiana. A summer design basis pipeline is capable of transporting, at a
minimum, the stated capacity at all times of the year. Along the pipeline there
are 16 compressor stations with total rated horsepower of 499,000 and
measurement facilities to support the receipt and delivery of gas at various
points. Other facilities include four field offices and a microwave
communication system with 50 tower sites.
Our pipeline system has pipeline access to natural gas reserves in the
western Canadian sedimentary basin in the provinces of Alberta, British Columbia
and Saskatchewan in Canada, domestic natural gas produced within the Williston
Basin and the Powder River Basin, and synthetic gas produced at the Dakota
Gasification plant in North
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Dakota. In addition, the pipeline is capable of physically receiving natural gas
at two locations near Chicago. For the year ended December 31, 2004, of the
natural gas transported on the pipeline system, approximately 88% was produced
in Canada, approximately 4% was produced by the Dakota Gasification plant, and
approximately 8% was produced in the Williston Basin.
INTERCONNECTS
To access markets, our pipeline system interconnects with pipeline
facilities of various interstate and intrastate pipeline companies and local
distribution companies, as well as with end-users. The larger interconnections
are:
- Northern Natural Gas Company at Ventura, Iowa as well as multiple
smaller interconnections in South Dakota, Minnesota and Iowa;
- Natural Gas Pipeline Company of America at Harper, Iowa;
- MidAmerican Energy Company at Iowa City and Davenport, Iowa and
Cordova, Illinois;
- Alliant Power Company at Prophetstown, Illinois;
- Northern Illinois Gas Company at Troy Grove and Minooka, Illinois;
- Midwestern Gas Transmission Company, a wholly owned subsidiary of
Northern Border Partners, near Channahon, Illinois;
- ANR Pipeline Company near Manhattan, Illinois;
- Vector Pipeline L.P. in Will County, Illinois;
- Guardian Pipeline, L.L.C., an affiliate of Northern Border Partners,
in Will County, Illinois;
- The Peoples Gas Light and Coke Company near Manhattan, Illinois; and
- Northern Indiana Public Service Company near North Hayden, Indiana
at the terminus of the pipeline system.
Several market centers, where natural gas transported on the pipeline
system is sold, traded and received for transport to consuming markets in the
Midwest and to interconnecting pipeline facilities, have developed on the
pipeline system. The largest of these market centers is at our Ventura, Iowa
interconnection with Northern Natural Gas Company. Two other market center
locations are the Harper, Iowa connection with Natural Gas Pipeline Company of
America and our multiple interconnects in the Chicago area that include
connections with Northern Illinois Gas Company, The Peoples Gas Light and Coke
Company and Northern Indiana Public Service Company, as well as four interstate
pipelines.
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SHIPPERS
All of our summer design capacity was under contract as of December 31,
2004 and, assuming no extensions of existing contracts or execution of new
contracts, approximately 61% and 51% of summer design capacity is under contract
as of December 31, 2005 and 2006, respectively. Our pipeline system serves
approximately 40 firm transportation shippers with diverse operating and
financial profiles. Based upon shippers' contractual obligations, as of December
31, 2004, 92% of firm capacity contracted is with producers and marketers. The
remaining firm capacity contracted primarily is with local distribution
companies (7%) and end-users (1%). As of December 31, 2004, the termination
dates of these contracts ranged from December 31, 2004 to December 21, 2013, and
the weighted average contract life was approximately two and three-quarters
years based upon contractual obligations and summer design capacity. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview."
Our shippers may change throughout the year as a result of our shippers
utilizing capacity release provisions that allow them to release all or part of
their capacity, either permanently for the full term of their contract or
temporarily. Under the terms of Northern Border Pipeline's tariff, a temporary
capacity release does not relieve the originally contracted shipper from its
payment obligations if the new shipper fails to pay.
At December 31, 2004, Nexen Marketing U.S.A. Inc., BP Canada Energy
Marketing Corp., EnCana Marketing U.S.A. Inc. and Cargill Incorporated were
obligated for approximately 18%, 14%, 13% and 12%, respectively, of our summer
design capacity. Contracts for approximately 63% of the capacity contracted by
these shippers are due to expire by November 1, 2005. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Overview."
One of our shippers, ONEOK Energy Services Company, LP, ("ONEOK Energy") a
subsidiary of ONEOK, is affiliated with us. ONEOK Energy holds firm contracts
representing 3% of summer design capacity. ONEOK Energy has also committed to be
a shipper on the Chicago III Expansion project. See Item 13. "Certain
Relationships and Related Transactions."
DEMAND FOR TRANSPORTATION CAPACITY
Recent developments have resulted in proposed expansion of our pipeline.
In September 2004, we announced we had received commitments from shippers
sufficient to support a proposed expansion of the pipeline system into the
Chicago market area. The "Chicago III Expansion" project, with 130 mmcfd of
capacity, would involve construction of a new compressor station and minor
modifications to two other compressor stations, and is estimated to cost
approximately $21 million. The projected in-service date is April 1, 2006. FERC
approval of this project is required and we expect to file the required
certificate application in March 2005.
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Our long-term financial condition is dependent on the continued
availability of economic western Canadian natural gas supplies for import into
the United States. Natural gas reserves may require significant capital
expenditures by others for exploration and development drilling and the
installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered to pipelines
that interconnect with the interstate pipelines' systems. Prices for natural
gas, the currency exchange rate between Canada and the United States, regulatory
limitations or the lack of available capital for these projects could adversely
affect the development of additional reserves and production, gathering, storage
and pipeline transmission of western Canadian natural gas supplies. Increased
Canadian consumption of natural gas related to the extraction process for oil
sands projects as well as restrictions on gas production to protect oil sand
reserves could also impact supplies of natural gas for export. Additional
pipeline export capacity also could accelerate depletion of these reserves.
Furthermore, the availability of export capacity could also affect the demand or
value of the transport on our pipeline system.
Our business also depends on the level of demand for natural gas in the
markets the pipeline system serves. The volumes of natural gas delivered to
these markets from other sources affect the demand for both the natural gas
supplies and the use of our pipeline system. Demand for natural gas to serve
other markets also influences the ability and willingness of shippers to use our
pipeline system to meet demand in the markets that we serve.
A variety of factors could affect the demand for natural gas in the
markets that we serve. These factors include:
- economic conditions;
- fuel conservation measures;
- alternative energy sources' requirements and prices;
- gas storage inventory levels;
- climatic conditions;
- government regulation; and
- technological advances in fuel economy and energy generation
devices.
Interstate pipelines' primary exposure to market risk occurs at the time
existing transportation contracts expire and are subject to renegotiation. A key
determinant of the capacity value for shippers that have competitive pipeline
alternatives is the basis differential, or market price spread, between two
points on the pipeline. The difference in natural gas prices between the points
along the pipeline where gas enters and where gas is delivered represents the
gross margin that a shipper can expect to achieve from holding transportation
capacity at any point in time. This margin and its variability become
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important factors in determining the transportation rate customers are willing
to pay when they renegotiate their transportation contracts. The basis
differential between markets can be affected by trends in production, available
capacity, storage inventories, weather and general market demand in the
respective areas.
Throughput on our pipeline may experience seasonal fluctuations depending
upon the level of winter heating load demand or summer electric generation usage
in the markets we serve. To the extent that capacity is contracted at maximum
rates under firm transportation agreements, 98% of the expected charges are from
demand charges that are not impacted materially by such seasonal throughput
variations. However, as contracts terminate, renewals and replacements may be
affected by seasonal fluctuations and historic usage patterns. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview."
We cannot predict whether these or other factors will have an adverse
affect on demand for use of our pipeline system or how significant that adverse
affect could be.
INTERSTATE PIPELINE COMPETITION
We compete with other pipeline companies that transport natural gas from
the western Canadian sedimentary basin or that transport natural gas to end-use
markets in the midwestern United States. Our competitive position is affected by
the availability of Canadian natural gas for export, the availability of other
sources of natural gas and demand for natural gas in the United States. Demand
for transportation services on our system is affected by natural gas prices, the
relationship between export capacity and production in the western Canadian
sedimentary basin, and natural gas shipped from producing areas in the United
States. Shippers of natural gas produced in the western Canadian sedimentary
basin also have other options to transport Canadian natural gas to the United
States, including transportation on the Alliance Pipeline to the Chicago market
area, on TransCanada's pipeline system through various interconnections with
U.S. interstate pipelines in the upper Midwest, including Viking Gas
Transmission Company which is owned by Northern Border Partners, and northeast
markets and on the Westcoast Pipeline and TransCanada B.C. systems and through
various interconnections with U.S. interstate pipelines serving northwest and
west coast markets. In the near term, our short-term contracted capacity
competes primarily with available and short-term capacity on the TransCanada and
Westcoast pipelines. Alliance Pipeline is not a competitor in the short-term for
us since substantially all of its capacity is contracted under long-term
contracts.
In addition, we compete in our markets with other interstate pipelines
that provide access to other supply basins. Our major deliveries into Northern
Natural Gas at Ventura, Iowa compete with gas supplied from the Rockies and
mid-continent regions. We also compete with these supply basins at our delivery
interconnect with Natural Gas Pipeline of America at Harper, Iowa. In the
Chicago area, we compete with many interstate pipelines that transport gas from
the Gulf Coast, mid-continent, Rockies and western Canada. In December 2004, the
Cheyenne Plains Pipeline system commenced service from the Cheyenne Hub
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in the Rocky Mountain area to the mid-continent area. The pipeline will provide
additional supply and transportation competition in markets served by us. The
supply balance in the mid-continent area can impact the value of gas that is
traded at Ventura, Iowa and Harper, Iowa delivery points and gas traded in the
Chicago area. A change in trading value at these market centers will affect the
corresponding transportation value of that portion of our system upstream and
downstream of these trading centers.
FERC REGULATION
We are subject to extensive regulation by the FERC as a "natural gas
company" under the Natural Gas Act. Under the Natural Gas Act and the Natural
Gas Policy Act, the FERC has jurisdiction with respect to virtually all aspects
of our business, including:
- transportation of natural gas;
- rates and charges;
- construction of new facilities;
- extension or abandonment of service and facilities;
- accounts and records;
- depreciation and amortization policies;
- the acquisition and disposition of facilities; and
- the initiation and discontinuation of services.
Where required, we hold certificates of public convenience and necessity
issued by the FERC covering our facilities, activities and services. Under
Section 8 of the Natural Gas Act, the FERC has the power to prescribe the
accounting treatment for items for regulatory purposes. Our books and records
may be periodically audited by the FERC under Section 8.
The FERC regulates the rates and charges for transportation in interstate
commerce. Natural gas companies may not charge rates that have been determined
not to be just and reasonable by the FERC. Generally, rates are based on the
cost of service including recovery of and a return on the pipeline's actual
prudent historical cost investment. In addition, the FERC prohibits natural gas
companies from unduly preferring or unreasonably discriminating against any
person with respect to pipeline rates or terms and conditions of service. Some
types of rates may be discounted without further FERC authorization and rates
may be negotiated subject to FERC approval. The rates and terms and conditions
for our service are found in our FERC approved tariff.
Transportation rates are established in FERC proceedings known as rate
cases. Under our tariff, we are allowed to charge for our services on the basis
of stated transportation rates established in our 1999 rate case. We may also
provide services under negotiated and discounted rates. Generally, firm shippers
are obligated to pay a
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monthly demand charge, regardless of the amount of natural gas they actually
transport, for the term of their contracts. Approximately 98% of the revenue
generated is attributed to demand charges. The remaining 2% of the agreed upon
revenue level is attributed to commodity charges based on the volumes of gas
actually transported.
Under the terms of settlement in our 1999 rate case, neither our existing
shippers nor we can seek rate changes until November 1, 2005, at which time we
must file a rate case. Prior to this rate case, we will not be permitted to
increase rates if costs increase or if our contracted demand decreases, nor will
we be required to reduce rates based on cost savings. As a result, our earnings
and cash flow will depend on costs incurred, contracted capacity, the volumes of
gas transported and our ability to recontract capacity at acceptable rates.
Until new depreciation rates are approved by the FERC, we continue to
depreciate our transmission plant at the FERC approved annual depreciation rate.
Our annual depreciation rate on transmission plant in service is 2.25%. The
effects of accumulated depreciation may be offset by acquiring or constructing
assets that replace or add to existing pipeline facilities or by adding new
facilities or our transportation rates may be decreased.
In our 1995 rate case, the FERC addressed the issue of whether the federal
income tax allowance included in our proposed cost of service was reasonable in
light of previous FERC rulings. In those previous rulings, the FERC held that an
interstate pipeline is not entitled to a tax allowance for income attributable
to limited partnership interests held by individuals. The settlement of our 1995
rate case provided that until at least December 2005, we could continue to
calculate the allowance for income taxes in the manner we had historically used.
In addition, a settlement adjustment mechanism was implemented, which
effectively reduced the return on rate base. These provisions of the 1995 rate
case were maintained in the settlement of our 1999 rate case.
On July 20, 2004, the D.C. Circuit Court of Appeals issued an opinion in
BP West Coast Products, LLC v. FERC ("SFPP, L.P. Proceeding") that reversed the
FERC decision that provided for an income tax allowance in the rates for SFPP,
LP, a limited partnership. The D.C. Circuit Court remanded the case to the FERC
for its determination regarding the proper income tax allowance. On December 2,
2004, the FERC initiated an inquiry open to all interested parties on whether
the court's ruling applies only to the specific facts of the SFPP, L.P.
Proceeding or if it extends to other capital structures involving partnerships
and other forms of ownership. The inquiry did not propose a particular rule. The
FERC inquired how the decision in the SFPP, L.P. Proceeding may impact
investment in energy infrastructure and if there are other methods in providing
an opportunity to earn an adequate return that are not dependent on the tax
implications of a particular capital structure.
Approximately 50 separate comments were filed by trade associations,
investor groups, producers, natural gas pipelines, electric utilities, oil
pipelines, and customers in January 2005. A number of comments, including ours,
suggested that an income tax
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allowance is a proper element of a pipeline's cost of service for all
jurisdictional entities regardless of legal structure. Some producers' and
customers' comments argued against the inclusion of an income tax allowance for
partnerships and other non-tax paying entities. It is not certain how, or when,
the FERC may proceed with respect to its Request for Comments or the affect on
us. In particular, we are a general partnership whose rates include an allowance
for income taxes. Our specific circumstances regarding our tariff, deferred
income tax treatment, FERC orders, past history and underlying agreements with
shippers are different from those of SFPP, L.P. The issue of whether the
inclusion of an income tax allowance in our rates is applicable, in light of the
FERC and court rulings, may be addressed in our 2005 rate case.
We are subject to the requirements of FERC Order Nos. 497 and 566, which
prohibit preferential treatment of transportation service providers' marketing
affiliates and govern how information may be provided to those marketing
affiliates. On November 25, 2003, the FERC issued a final rule, Order No. 2004,
adopting new standards of conduct for transmission providers when dealing with
their energy affiliates. Additional orders modifying Order No. 2004 were issued
on April 16, August 2 and December 21, 2004. Transmission providers were
required to comply with the standards of conduct by September 22, 2004. The
standards of conduct are designed to prevent transmission providers from giving
undue preferences to any of their energy affiliates. The final rule generally
requires that transmission function employees operate independently of the
marketing function employees and energy affiliates. As required of all
transmission providers, we posted our standards of conduct to our website on
September 22, 2004. By definition, Bear Paw Energy, LLC, a subsidiary of
Northern Border Partners and ONEOK Energy Services Company, L.P, as well as
other subsidiaries of ONEOK, are energy affiliates. Prior to September 22, 2004,
our operator, Northern Plains, provided after hours and weekend gas control
services for Bear Paw Energy, LLC and Crestone Energy Ventures, also a
subsidiary of Northern Border Partners that resulted in some cost savings to us.
We have requested a waiver, which is still pending at the FERC, to permit
Northern Plains to resume after hours and weekend gas control services for Bear
Paw Energy, LLC and Crestone Energy Ventures.
On July 17, 2002, the FERC issued a Notice of Inquiry Concerning Natural
Gas Pipeline Negotiated Rate Policies and Practices. Subsequently, the FERC
issued an order on July 25, 2003, modifying its prior policy on negotiated
rates. The FERC ruled that it would no longer permit the pricing of negotiated
rates based upon natural gas commodity price indices. Negotiated rates based
upon such indices may continue until the end of the contract period for which
such rates were negotiated, but such rates will not be prospectively approved by
FERC. FERC also imposed certain requirements on other types of negotiated rate
transactions to ensure that the agreements embodying such transactions do not
materially differ from the terms and conditions set forth in the tariff of the
pipeline entering into the transaction. This FERC ruling is not expected to have
a material effect on our business.
Recent FERC orders in proceedings involving other natural gas pipelines
have addressed certain aspects of a pipeline's
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creditworthiness provisions set forth in their tariffs. In addition, industry
groups, such as the North American Energy Standards Board ("NAESB"), are
studying creditworthiness standards. On February 12, 2004, the FERC issued a
Notice of Proposed Rulemaking to require interstate pipelines to follow
standardized procedures for determining the creditworthiness of their shippers.
The proposed rule would incorporate by reference ten consensus standards passed
within NAESB and would adopt additional standards requiring, among other things,
standardization of information shippers provide to establish credit, collateral
requirements for service, procedures for suspension and termination for
non-creditworthy shippers and procedures governing capacity release
transactions. The enactment of some of these standards may have the effect of
easing certain creditworthiness requirements and parameters currently reflected
in our tariffs on existing transportation capacity. However, recent FERC orders,
and this proposed rule, continue to allow more stringent collateral requirements
for the construction of new facilities by a pipeline. However, we cannot predict
the ultimate impact, if any, on us, of any resulting final rule.
In February 2004, the FERC adopted new quarterly financial reporting
requirements and accelerated the filing date for interstate pipeline's annual
financial report. The quarterly reports include a basic set of financial
statements and other selected data and are submitted electronically. There is no
impact for complying with these requirements other than the time and additional
expenses for preparation of these reports.
In November 2004, the FERC issued a Notice of Proposed Accounting Release
("PAR") to provide guidance on the accounting for costs of pipeline assessment
programs required under the Pipeline Safety Improvement Act of 2002 and
regulations established thereunder. The PAR concluded that such costs should be
treated as maintenance costs. Comments have been filed by the Interstate Natural
Gas Association of America as well as individual pipelines setting forth the
arguments that these costs should be capitalized.
In November 2004, the FERC issued a Notice of Inquiry on selective
discounting particularly as it relates to allowing discount adjustments for
contracts resulting from competition between interstate pipelines referred to as
gas-on-gas competition. The FERC noted that in several proceedings, parties have
objected to the FERC's current discounting policy, allowing selective
discounting for gas-on-gas competition, on the grounds that it no longer
benefits captive customers by allowing fixed costs to be spread over more units
of service. These parties have argued that while benefits may still exist to the
extent a discount is given to a customer who would otherwise use an alternative
fuel and not ship gas at all, benefits do not exist in situations where
discounts are given to meet competition from other gas pipelines. Although
the FERC has not disallowed discount adjustments for gas-on-gas competition, the
Notice of Inquiry seeks comments and responses to a series of questions that
will allow the FERC to explore the potential impact of eliminating the discount
adjustment for gas-on-gas competition and how the FERC should implement and
monitor such a policy.
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In August 2003, we filed revised tariff sheets to clarify its procedures
for the awarding of capacity. Several parties protested the filing. One party
requested a show cause proceeding to examine past tariff practices alleging that
we violated our tariff by denying a request for service that would have involved
transportation for a distance shorter than the available distance for less than
a one-year term. Our position is that selling capacity for shorter distances or
on a shorter term basis may cause portions of our system to be "stranded" or not
subject to firm transportation contracts on a consistent basis or may
effectively constitute a discounted rate service. On September 10, 2003, the
FERC rejected our tariff sheets based on the conclusion that certain aspects of
the proposal were not in accordance with the FERC's policy. The FERC affirmed
that, up to ninety days prior to the effective date, we had the right not to
sell capacity requested for shorter distances or on a short-term basis to
shippers offering the maximum mileage-based transportation rate. We filed a
timely request for rehearing of the FERC's Order in October 2003, which is still
pending. We also filed responses to requests for further information on the
award of capacity in the summer of 2003. We filed our compliance tariff sheets
in early December 2003 and are awaiting the FERC decision on these tariff
sheets. An order was issued on April 15, 2004, in which the FERC requested
comments from interested parties on whether the FERC's current policy on
awarding available capacity to a short-haul shipper appropriately balances the
risks to the pipeline, prospective shippers and current shippers on the
pipeline. Comments from us and other interested parties were filed on June 15,
2004. The timing of the issuance of the FERC's order in this proceeding is not
known.
ENVIRONMENTAL AND SAFETY MATTERS
Our operations are subject to federal, state and local laws and
regulations relating to safety and the protection of the environment, which
include the Resource Conservation and Recovery Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended,
Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas
Pipeline Safety Act of 1969, as amended, the Pipeline Safety Act of 1992 and the
Pipeline Safety Improvement Act of 2002.
The Pipeline Safety Improvement Act ("Act") of 2002 was signed into law in
December 2002, providing guidelines for interstate pipelines in the areas of
risk analysis and integrity management, public education programs, verification
of operator qualification programs and filings with the National Pipeline
Mapping System. The Act requires pipeline companies to perform integrity
assessments on pipeline segments that exist in high population density areas or
near specifically identified sites that are designated as high consequence
areas. Pipeline companies are required to perform the integrity assessments
within ten years of the date of enactment and must perform subsequent integrity
assessments on a seven-year cycle. At least 50% of the highest risk segments
must be assessed within five years of the enactment date. In addition, within
one year of enactment, the pipeline's operator qualification programs, in force
since the mandatory compliance date of October 2002, must also conform to
standards provided by the Department of Transportation. The regulations
implementing the Act are final. Rules on integrity
11
management, direct assessment usage, and the operator qualification standards
have been issued. We have made the required filings with the National Pipeline
Mapping System and have reviewed and revised our public education program.
Compliance with the Act is expected to increase our operating costs particularly
related to integrity assessments for our pipeline. As required, we have
developed an overall plan for pipeline integrity management. Detailed analysis
is being performed to determine the priorities and costs for inspecting and
testing our pipeline. However, the plan will be modified as a result of the
findings noted and could result in additional assessment or remediation costs.
Presently we expect our annual costs for integrity assessments to be
approximately $0.5 million. We expect to include these costs in future rate case
filings. How these costs may be classified for all interstate pipelines is the
subject of the pending proceeding before the FERC. See "FERC Regulation" above.
Although we believe that our operations and facilities are in general
compliance in all material respects with applicable environmental and safety
regulations, risks of substantial costs and liabilities are inherent in pipeline
operations, and we cannot provide any assurances that we will not incur such
costs and liabilities. Moreover, it is possible that other developments, such as
the enactment of increasingly strict environmental and safety laws, regulations
and enforcement policies by Congress, the FERC, the Department of Transportation
and other federal agencies, state regulatory bodies and the courts, and claims
for damages to property or persons resulting from our operations, could result
in substantial costs and liabilities to us. If we are unable to recover such
resulting costs, earnings and cash distributions could be adversely affected.
ITEM 2. PROPERTIES.
See Item 1. "Business - The Pipeline System" and "Business -
Interconnects" for a brief description of the location and general
characteristics of our important physical properties.
We hold the right, title and interest in our pipeline system. With respect
to real property, the pipeline system falls into two basic categories: (a)
parcels which are owned in fee, such as sites for compressor stations, meter
stations, pipeline field offices, and microwave towers; and (b) parcels where
the interest derives from leases, easements, rights-of-way, permits or licenses
from landowners or governmental authorities permitting the use of such land for
the construction and operation of the pipeline system. The right to construct
and operate the pipeline system across certain property was obtained through
exercise of the power of eminent domain. We continue to have the power of
eminent domain in each of the states in which we operate, although we may not
have the power of eminent domain with respect to Native American tribal lands.
Approximately 90 miles of our pipeline are located on fee, allotted and
tribal lands within the exterior boundaries of the Fort Peck Indian Reservation
in Montana. Tribal lands are lands owned in trust by the United States for the
Fort Peck Tribes and allotted lands are lands owned in trust by the United
States for an individual Indian
12
or Indians. We do have the right of eminent domain with respect to allotted
lands.
In 1980, we entered into a pipeline right-of-way lease with the Fort Peck
Tribal Executive Board, for and on behalf of the Assiniboine and Sioux Tribes of
the Fort Peck Indian Reservation ("Tribes"). This pipeline right-of-way lease,
which was approved by the Department of the Interior in 1981, granted to us the
right and privilege to construct and operate our pipeline on certain tribal
lands. This pipeline right-of-way lease expires in 2011. We have been granted
options to renew the pipeline right-of-way lease to 2061. See Item 3.
"Legal Proceedings."
In conjunction with obtaining a pipeline right-of-way lease across tribal
lands located within the exterior boundaries of the Fort Peck Indian
Reservation, we also obtained a right-of-way across allotted lands located
within the reservation boundaries. Most of the allotted lands are subject to a
perpetual easement either granted by the Bureau of Indian Affairs ("BIA") for
and on behalf of individual Indian owners or obtained through condemnation.
Several tracts are subject to a right-of-way grant that has a term of 15 years,
expiring in 2015.
ITEM 3. LEGAL PROCEEDINGS.
On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian
Reservation ("Tribes) filed a lawsuit in Tribal Court against us to collect more
than $3 million in back taxes, together with interest and penalties. The lawsuit
related to a utilities tax on certain of our properties within the Fort Peck
Indian Reservation. The Tribes and we, 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
("Agreement") executed in August 2004. Through the terms of the Agreement, the
settlement grants to us, among other things: (i) an option to renew the pipeline
right-of-way lease upon agreed terms and conditions on or before April 1, 2011
for a term of 25 years with a renewal right for an additional 25 years; (ii) a
right to use additional tribal lands for expanded facilities; and (iii) release
and satisfaction of all tribal taxes against us. In consideration of this option
and other benefits, we 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. We intend to seek regulatory recovery of the costs
resulting from the settlement. See Item 7. "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Risk Factors and Information
Regarding Forward-Looking Statements."
See Item 1. "Business - FERC Regulation" for a discussion on the
proceeding before the FERC.
We are not currently parties to any other legal proceedings that,
individually or in the aggregate, would reasonably be expected to have a
material adverse impact on our results of operations or financial position.
13
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the
fourth quarter of fiscal 2004.
14
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES.
The general partnership interests of Northern Border Pipeline Company are
not traded in an established public trading market.
In December 2003, our management committee voted to (i) issue equity cash
calls to our general partners in the total amount of $130 million in early 2004
and $90 million in 2007; (ii) fund future growth capital expenditures with 50%
equity capital contributions from our general partners; and (iii) change our
cash distribution policy to be effective January 1, 2004, when cash
distributions will be based upon 100% of distributable cash flow as determined
from the Company's financial statements as earnings before interest, taxes,
depreciation and amortization less interest expense and less maintenance capital
expenditures, until January 1, 2008 when the cash distribution policy will be
adjusted to maintain a consistent capital structure. Under the previous cash
distribution policy, approximately $28 to $30 million was retained annually by
us to periodically repay outstanding bank debt. The additional equity
contributions in 2004 were utilized to fully repay our existing bank debt and
thereby reducing our debt leverage in light of existing business conditions.
Upon repayment of the existing bank debt, our next scheduled debt maturity is
May 2007.
On November 30, 2004, we issued an equity cash call to our partners in the
total amount of $75 million, which was paid on December 22, 2004. This
additional equity contribution was utilized to repay our existing bank debt and
thereby reduce our debt leverage in light of existing business conditions. This
equity contribution will reduce the previously approved 2007 equity cash call
from $90 million to $15 million.
15
ITEM 6. SELECTED FINANCIAL DATA.
(in thousands, except other financial and operating data)
The following table sets forth, for the periods and at the dates indicated,
selected historical financial data for us. The selected financial information
should be read in conjunction with the Financial Statements and the Notes and
Item 7. "Management's Discussion and Analysis of Financial Condition and Results
of Operations," which are included elsewhere in this report.
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------
2004 2003 2002 2001 2000
---------- ---------- ---------- ---------- ----------
INCOME DATA:
Operating revenues, net $ 329,115 $ 324,185 $ 321,050 $ 313,088 $ 311,022
Operations and
maintenance 33,763 43,791 41,442 33,695 41,548
Depreciation and
amortization 58,375 57,779 58,714 57,516 57,328
Taxes other than income 29,368 29,634 28,436 25,636 27,979
---------- ---------- ---------- ---------- ----------
Operating income 207,609 192,981 192,458 196,241 184,167
Interest expense, net 41,356 44,857 51,525 55,351 65,161
Other income (expense) 524 76 1,786 (432) 8,058
---------- ---------- ---------- ---------- ----------
Net income to partners $ 166,777 $ 148,200 $ 142,719 $ 140,458 $ 127,064
========== ========== ========== ========== ==========
CASH FLOW DATA:
Net cash provided by
operating activities $ 206,149 $ 193,270 $ 224,356 $ 197,322 $ 175,967
Capital expenditures 10,569 12,918 9,243 54,659 15,523
Distributions to
partners 205,635 153,978 164,126 143,032 134,904
Equity contributions
from partners 205,000 -- -- -- --
BALANCE SHEET DATA
(AT END OF YEAR):
Property, plant
and equipment, net $1,543,833 $1,591,755 $1,635,961 $1,685,665 $1,686,992
Total assets 1,623,348 1,691,309 1,740,037 1,751,869 1,768,505
Long-term debt,
including current
maturities 603,860 821,498 848,906 863,666 863,267
Partners' equity 967,140 802,438 809,772 833,594 826,995
OTHER FINANCIAL DATA:
Ratio of earnings to
fixed charges (1) 5.0 4.3 3.8 3.5 2.9
OPERATING DATA:
Natural gas delivered
(millions of cubic
feet) 844,963 849,920 838,736 820,851 852,674
Average receipts
(millions of cubic
feet per day) 2,377 2,396 2,369 2,312 2,400
- -------------------------------------------------------------------------------
(1) "Earnings" means the sum of pre-tax income from continuing operations and
fixed charges. "Fixed charges" means the sum of (a) interest expensed and
capitalized; (b) amortized premiums, discounts and capitalized expenses
related to indebtedness; and (c) an estimate of interest within rental
expenses.
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
Our discussion and analysis of our financial condition and operations are
based on our Financial Statements, which were prepared in accordance with
accounting principles generally accepted in the United States of America. You
should read the following discussion and analysis in conjunction with our
Financial Statements and the related notes included elsewhere in this report.
OVERVIEW
For Northern Border Pipeline, there are several major business drivers.
First, a healthy long-term supply outlook is critical. Because the primary
source of gas supply that is transported on our pipeline system is in the
western Canadian sedimentary basin, western Canadian supply trends are
particularly important to us. The current outlook for western Canadian supply
looks flat for the foreseeable future, however, production has exceeded new
reserve additions in recent years. To maintain an adequate gas supply/demand
balance in western Canada, production will need to grow in the future to meet
anticipated demand primarily driven by gas consumption in the extraction and
processing associated with Canadian oil sands development. Canada holds
substantial reserves of bitumen that is extracted from sand and can be upgraded
to synthesized crude oil through several processes. The extraction and
processing of bitumen require significant quantities of natural gas. We do not
know how many of the announced oil sands development projects will be approved
and constructed but the demand for transportation on our pipeline systems could
be affected adversely by the additional competition for Canadian gas supply that
would result. The supply outlook may be enhanced over time by new proposed
Alaskan and Mackenzie Delta supplies reaching the western Canadian pipeline grid
potentially beginning by the end of this decade, although there is no assurance
either project will be completed within that timeframe. Moreover, prices of
western Canadian supply must be competitive with prices from other supply basins
that serve our market areas. If prices are too high, other sources of supply may
satisfy demand that otherwise could be met by us. Increased demand for western
Canadian natural gas in markets other than those served by us may also cause a
reduction of demand for service on us.
Natural gas markets are also critical to our financial performance. Our
pipeline system serves natural gas markets in the upper midwestern area of the
United States and accesses a major trading hub in the Chicago area. Market
growth has been steady with both heating load growth and direct end-user growth,
such as power plants and ethanol plants. However, competitive pipeline projects
may have a negative impact on our profitability.
We charge fees for transportation, which are primarily fixed and are based
on the amount of capacity reserved by each shipper. Contracting with shippers to
reserve the available pipeline capacity as existing contracts expire is a
critical factor in our success. Based on our contracts in place at December 31,
2004, the percentage of summer design capacity contracted as of December 31,
2005 was 61%.
During 2004, we were successful in recontracting, at maximum
17
rates, essentially all of the summer design capacity under contracts that
expired on or before November 2004. However, most of those contracts were for
terms of five to six months so we have a significant amount of capacity,
approximately 800 mmcfd or 28% of summer design capacity, under contracts that
expire by May 31, 2005. Most of this capacity will become available on the
pipeline system from Port of Morgan, Montana to the Ventura, Iowa delivery
point.
Our objective is to recontract as much of the remaining pipeline capacity
at maximum transportation rates for the longest terms possible. Because the
forward natural gas basis differentials between Western Canada and our market
centers continue to be less than the total transportation cost at maximum tariff
rates, we may again sell a significant portion of this capacity on a short-term
basis. So long as we continue to provide economic value, gas will likely flow
from western Canada over our system and we will maintain our relatively high
utilization levels. However, in any given month, current conditions of weather
and storage in supply and market areas may affect the demand for capacity on us.
This could result in lower revenues in some months. Although, we believe a
reduction in expected 2005 net income and cash flow of approximately $7 million
to $14 million is possible, the impact on net income and cash flow may vary
outside this range depending on actual natural gas basis differentials
experienced during the year.
The composition of natural gas can affect the amount of energy that is
transported through a pipeline system. Beginning in 2000, the energy content of
natural gas that we receive at the Canadian border has declined modestly from
1,023 British Thermal Units ("Btus") per cubic foot ("cf") to 1,005 Btus/cf. Our
transportation contracts in conjunction with our tariff define both the volume
and equivalent Btu value of the gas to be transported. A reduction in the Btu
level results in a higher volume of natural gas to be transported to meet an
overall equivalent Btu value of the gas. This Btu decline that has been
experienced was primarily the result of greater processing capacity in Alberta.
The change caused us to reduce our available capacity by almost 2 percent to
maintain a high standard of system reliability for our customers. During 2004,
the Btu level remained near the level of 1,005 Btus/cf and it is expected to
remain at that level during 2005. This Btu variance will be addressed in our
November 1, 2005 rate case filing.
We will continue to focus on safe, efficient, and reliable operations and
the further development of our pipeline. We are working to maintain our position
as a low cost transporter of Canadian gas to the midwestern U.S. and provide
highly valued services to our customers. Growth may occur through incremental
projects intended to access new markets or supply areas and supported by
long-term contracts. In September 2004, we announced sufficient customer support
for a proposed expansion from various receipts point along the pipeline system
for deliveries into the Chicago area. The Chicago III Expansion Project, with
130 mmcfd of incremental capacity, involves construction of a new 16,000
horsepower compressor station in Iowa and minor modifications to existing
compressor facilities, in Iowa and Illinois. Capital costs are estimated to be
approximately $21 million. An April 1, 2006 in-service date is the target and
subject to timely receipt of regulatory approval, we anticipate that
approximately $15 million of the estimated $21 million
18
capital budget will be expended in 2005, with the remaining $6 million to be
spent in 2006.
We will focus on several regulatory matters. Under our settlement
agreement from the last rate case, it was agreed that we must file a proceeding
under section 4 of the Natural Gas Act to determine the just and reasonable
rates to be charged for our transportation services. During the rate case
process, the FERC staff and our customers will review the cost of service
elements, (including allowed return on capital, operations and maintenance
costs, depreciation and taxes) and contracted capacity levels used to determine
transportation rates.
As described more fully in Item 1. "Business - FERC Regulation", there is
a FERC inquiry regarding the proper income tax allowance in rates for regulated
entities other than corporations. In response, a number of comments, including
ours, suggested that an income tax allowance is proper for all jurisdictional
entities regardless of legal structure. Some producers' and customers' comments
argued against the inclusion of an income tax allowance for partnerships and
other non-tax paying entities. It is not certain how, or when, the FERC may
proceed with respect to its Request for Comments or any impact on the rate
methodology for interstate natural gas pipelines, including us. In particular,
we are a general partnership and one of the elements used to determine our cost
of service upon which our transportation rates are derived is an allowance for
income taxes. While we cannot predict the outcome of the FERC's inquiry, we do
believe that our specific circumstances regarding our tariff, deferred income
tax treatment, FERC orders, past history and underlying agreements with shippers
are different from those of SFPP, L.P. The issue of whether our rates should
include an income tax allowance, and if so, the amount thereof, may be
addressed in our 2005 rate case.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Certain amounts included in or affecting our financial statements and
related notes must be estimated, requiring us to make certain assumptions with
respect to values or conditions that cannot be known with certainty at the time
the financial statements are prepared. The preparation of financial statements
in conformity with accounting principles generally accepted in the United States
of America requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates. Any effects on our business, financial position or
results of operations resulting from revisions to these estimates are recorded
in the period in which the facts that gave rise to the revision become known.
Our significant accounting policies are summarized in Note 2 - Notes to
Financial Statements included elsewhere in this report. Certain of our
accounting policies are of more significance in our financial statement
preparation process than others. Our accounting policies conform to Statement of
Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of
Certain Types of Regulation." Accordingly, certain assets that result from the
19
regulated ratemaking process are recorded that would not be recorded under
accounting principles generally accepted in the United States of America for
nonregulated entities. We continually assess whether the regulatory assets are
probable of future recovery by considering such factors as regulatory changes
and the impact of competition. If future recovery ceases to be probable, we
would be required to write-off the regulatory assets at that time. At December
31, 2004, we have reflected regulatory assets of $11.8 million, which are being
recovered, or are expected to be recovered from our shippers over varying time
periods up to 44 years.
Our long-lived assets are stated at original cost. We must use estimates
in determining the economic useful lives of those assets. For utility property,
no retirement gain or loss is included in income except in the case of
retirements or sales of entire regulated operating units. The original cost of
utility property retired is charged to accumulated depreciation and
amortization, net of salvage and cost of removal.
Our accounting for financial instruments is in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 requires that every derivative instrument be recorded on the balance sheet
as either an asset or liability measured at its fair value. The statement
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement. At December 31, 2004, we had
no derivative financial instruments outstanding.
RESULTS OF OPERATIONS
Our net income to partners was $166.8 million in 2004, $148.2 million in
2003 and $142.7 million in 2002. Our increase in net income in 2004 resulted
from increased operating revenues as a result of our ability to generate and
retain revenue from the sale of short-term capacity following the expiration of
a condition under the previous rate case settlement that restricted our sale of
short-term firm capacity and that had required us to share new service revenue
with our shippers, a reduction in operations and maintenance expense due to
adjustments to expenses previously recorded for termination costs of Enron
Corp.'s Cash Balance Plan ("Cash Balance Plan") and the settlement of previously
accrued charges for administrative services provided by Northern Plains and its
affiliates and a reduction in interest expense due to a decrease in average debt
outstanding. Our 2003 operating results benefited from increased operating
revenues as a result of our ability to generate and retain revenue from the sale
of short-term capacity following the expiration of a condition under the
previous rate case settlement that restricted our sale of short-term firm
capacity and that had required us to share interruptible transmission and new
service revenue with our shippers, the re-contracting of capacity previously
held by Enron North America Corp. ("ENA"), and a reduction in interest expense
due to lower interest rates. Partially offsetting these increases to our
operating results were higher operations and maintenance expenses for 2003 as
compared to 2002.
20
Operating revenues were $329.1 million in 2004, $324.2 million in 2003 and
$321.1 million in 2002. The $4.9 million increase in operating revenues in 2004
over 2003 was primarily due to the expiration of conditions under Northern
Border Pipeline's previous rate case settlement, which enabled us to generate
and retain approximately $2.0 million from the sale of short-term firm capacity
and approximately $2.0 million due to no longer being required to share new
service revenue with its shippers. In addition, we had an additional day of
transportation services due to leap year, which approximated an additional $0.9
million in revenue. The $3.1 million increase in operating revenues in 2003 over
2002 resulted primarily from additional revenues of approximately $1.8 million
related to the re-contracted capacity of ENA contracts. ENA filed for Chapter 11
bankruptcy protection in December 2001 (see "The Impact Of Enron's Chapter 11
Filing On Our Business"). In addition, we recognized revenues from our ability
to offer short-term firm contracts and also being able to retain revenue for
transportation service beyond a shipper's contracted transportation path.
Operations and maintenance expenses were $33.8 million in 2004, $43.8
million in 2003 and $41.4 million in 2002. The $10.0 million decrease in expense
from 2003 to 2004 included a reduction of expenses of $3.1 million, as we
determined we were no longer liable for termination costs of the Cash Balance
Plan. When compared to the impact of the charges recorded in 2003, this
represents a $6.2 million decrease in expense between 2003 and 2004.
Additionally in 2004, we reduced our operations and maintenance expense by
approximately $1.7 million and $0.6 million related to the settlement of
previously accrued charges for administrative services provided by Northern
Plains and its affiliates and a true-up for corporate compensation plans,
respectively. Also contributing to the decrease were adjustments to allowance
for doubtful accounts of $1.1 million for estimated recoveries of claims against
Enron. Operations and maintenance expense was increased by $1.0 million related
to costs incurred as part of our comprehensive effort to ensure compliance with
Section 404 of the Sarbanes Oxley Act of 2002. The 2003 expense included a $3.1
million charge for our allocation from Northern Plains related to the Cash
Balance Plan (see "The Impact of Enron's Chapter 11 Filing On Our Business"). In
2003, we also had increases in salaries and benefits, rights-of-way damages, and
telecommunication expenses offset by decreases in electric power costs, as
compared to 2002. The 2002 expense included a $10.0 million reserve for costs
associated with the treatment of previously collected quantities of natural gas
used in utility operations to cover electric power costs. The FERC ordered
refunds for these costs in 2003.
Depreciation and amortization expense was $58.4 million in 2004, $57.8
million in 2003 and $58.7 million in 2002. The increase in 2004 over 2003 is
primarily related to asset additions. The decrease from 2002 to 2003 primarily
reflects asset retirements.
Taxes other than income were $29.4 million in 2004, $29.6 million in 2003
and $28.4 million in 2002. The increase in 2003 from 2002 is due primarily to a
refund received in 2002 from Minnesota for previously paid use taxes resulting
from a ruling by the Minnesota Supreme Court.
21
Interest expense was $41.4 million in 2004, $44.9 million in 2003 and
$51.5 million in 2002. The $3.5 million decrease from 2003 to 2004 resulted from
a decrease in average debt outstanding partially offset by an increase in
average interest rates. Interest expense for 2003 decreased from 2002 due to a
decrease in our average interest rate as well as a decrease in our average debt
outstanding.
Other income (expense) was $0.5 million in 2004, $0.1 million in 2003 and
$1.8 million in 2002. Significant items included in the $0.4 million increase
between 2003 and 2004 are additional income of approximately $0.6 million for
interconnections constructed and the reimbursement for the use of previously
vacated microwave frequencies of $0.2 million partially offset by approximately
$0.5 million of bad debt expense and a $0.4 million inventory write off. In
2003, we recorded expense of approximately $0.6 million for a repayment of
amounts previously received for vacated microwave frequency bands, interest
expense of $0.3 million due to the FERC ordered refunds of electric power costs
and $0.2 million of interest income received related to a sales tax refund on
exempt purchases. The amount for 2002 includes approximately $0.6 million for
amounts received for previously vacated microwave frequency bands and income of
$0.2 million due to a reduction in reserves previously established.
LIQUIDITY AND CAPITAL RESOURCES
SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS
The following table sets forth our contractual obligations as of December
31, 2004.
Payments Due by Period
----------------------------------------------
Less Than After
Total 1 Year 1-3 Years 4-5 Years 5 Years
-------- --------- --------- --------- --------
(In Thousands)
Senior Notes due 2007 $150,000 $ -- $150,000 $ -- $ --
Senior Notes due 2009 200,000 -- -- 200,000 --
Senior Notes due 2021 250,000 -- -- -- 250,000
Credit Agreement due
2005 -- -- -- -- --
Operating Leases (a) 78,345 2,392 4,784 4,784 66,385
-------- ------ -------- -------- --------
Total $678,345 $2,392 $154,784 $204,784 $316,385
======== ====== ======== ======== ========
(a) See Note 7 - Notes to Financial Statements.
OVERVIEW
We believe that we have adequate liquidity to fund future recurring
operating activities and capital expenditures. Short-term liquidity needs will
be met by our operating cash flows and the 2002 Pipeline Credit Agreement
(defined below) or similar new credit facilities. Other liquidity needs are
expected to be funded through the issuance of long-term debt and capital
contributions made by our general partners. Our ability to complete future debt
offerings and the timing of any such offerings will depend on various factors,
including prevailing market conditions, interest rates and our financial
condition and credit ratings at the time.
22
DEBT AND CREDIT FACILITIES
We entered into a $175 million three-year credit agreement ("2002 Pipeline
Credit Agreement") with certain financial institutions in May 2002. The 2002
Pipeline Credit Agreement replaced a previous credit agreement. The 2002
Pipeline Credit Agreement is to be used to refinance existing indebtedness and
for general business purposes. At December 31, 2004, there were no amounts
outstanding under the 2002 Pipeline Credit Agreement. The 2002 Pipeline Credit
Agreement requires the maintenance of a ratio of EBITDA (net income plus
interest expense, income taxes and depreciation and amortization) to interest
expense of greater than 3 to 1. The 2002 Pipeline Credit Agreement also requires
the maintenance of the ratio of indebtedness to EBITDA of no more than 4.5 to 1.
At December 31, 2004, we were in compliance with these covenants. With the 2002
Pipeline Credit Agreement due to expire in May 2005, we have commenced
discussions with financial institutions and expect to have a facility in place
at terms and conditions similar to the current facility.
In April 2002, we completed a private offering of $225 million of 6.25%
Senior Notes due 2007 ("2002 Pipeline Senior Notes"). The indentures under which
the Pipeline Senior Notes were issued do not limit the amount of unsecured debt
we may incur, but they do contain material financial covenants, including
restrictions on incurrence of secured indebtedness. The proceeds from the
Pipeline Senior Notes were used to reduce indebtedness outstanding. In December
2004, we redeemed $75 million of the 2002 Pipeline Senior Notes.
CASH FLOWS FROM OPERATING ACTIVITIES
Cash flows provided by operating activities were $206.1 million in 2004,
$193.3 million in 2003 and $224.4 million in 2002. The increase in operating
revenues and lower interest expense in 2004 as compared to 2003 contributed to
the increase in operating cash flow. An additional $10.3 million of the increase
in 2004 over 2003 operating cash flows was due to FERC ordered refunds paid in
2003. Other cash flows from operating activities for 2004 reflect our initial
payment of $7.4 million to the Fort Peck Tribes, in accordance with the terms of
the Agreement. The $31.1 million decrease in 2003 from 2002 was primarily due to
the payment of the FERC ordered refunds related to the electric power costs and
the discontinuance of certain shipper transportation prepayments.
CASH FLOWS FROM INVESTING ACTIVITIES
Cash used in investing activities was $10.6 million for 2004 as compared
to $12.9 million for 2003 and $9.2 million for 2002. The capital expenditures
for 2004, 2003 and 2002 were primarily related to renewals and replacements of
existing facilities.
Total capital expenditures for 2005 are estimated to be approximately $40
million, which includes approximately $15 million for the Chicago III Expansion
Project. The remaining capital expenditures for 2005 are primarily related to
renewals and replacements of existing facilities. We currently anticipate
funding our 2005 capital expenditures primarily by borrowing on our credit
facility and using
23
operating cash flows.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flows used in financing activities were $204.0 million for the year
ended December 31, 2004 as compared to $177.0 million in 2003 and $200.8 million
in 2002. Distributions to our partners were $205.6 million, $154.0 million and
$164.1 million for 2004, 2003 and 2002, respectively. In 2004, contributions of
$205.0 million were received from our partners to pay existing bank debt. The
increase in distributions from 2003 to 2004 was primarily due to the change to
our cash distribution policy in 2004 (see Note 8 - Notes to Financial
Statements). The decrease from 2002 to 2003 in distributions was primarily due
to the impact of the refunds ordered by FERC on March 27, 2003.
For 2004, 2003 and 2002, our borrowings on long-term debt totaled $107.0
million, $142.0 million and $431.9 million, respectively. In 2004 and 2003, the
borrowings were made under our credit agreements. For 2002, we received net
proceeds from the 2002 Pipeline Senior Notes of approximately $223.5 million and
borrowed $207.0 million under our credit agreements. Total payments on debt were
$313.0 million, $165.0 million and $468.0 million in 2004, 2003 and 2002,
respectively. In 2004, we redeemed $75 million of the 2002 Senior Notes. In
connection with the redemption, we were required to pay a premium of $4.8
million.
In November 2004, we received $7.6 million from the termination of our
interest rate swap agreements with a total notional amount of $225 million. In
April 2002, we received $2.4 million from the termination of forward starting
interest rate swaps upon issuance of the 2002 Pipeline Senior Notes (see Note 6
- - Notes to Financial Statements).
THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS
On December 2, 2001, Enron filed a voluntary petition for bankruptcy
protection under Chapter 11 of the United States Bankruptcy Code. Certain wholly
owned Enron subsidiaries also filed for Chapter 11 bankruptcy protection on
December 2, 2001 and thereafter. Until November 17, 2004, each of Northern
Plains, our operator, and Pan Border, two of the general partners of Northern
Border Partners, were subsidiaries of Enron. Northern Plains and Pan Border were
not among the Enron companies who filed for Chapter 11 protection.
SALE OF ENRON ENTITIES
On March 31, 2004, Enron transferred its ownership interest in Northern
Plains, and Pan Border to CrossCountry Energy, LLC ("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.
On June 24, 2004, Enron announced that it had reached an agreement with a
joint venture of Southern Union Company and GE
24
Commercial Finance Energy Financial Services ("CCE Holdings") for the sale of
CrossCountry. On September 1, 2004, Enron announced that it reached an amended
agreement for the sale of CrossCountry to CCE Holdings ("CCE Holdings
Agreement"). On September 10, 2004, the Bankruptcy Court issued an order (the
"September 10 Order") approving the CCE Holdings Agreement.
On September 16, 2004, Southern Union Company and ONEOK, Inc. each
announced that ONEOK had entered into an agreement ("ONEOK Agreement") to
purchase Northern Plains and Pan Border (collectively the "Transfer Group
Companies") from CCE Holdings. This acquisition closed on November 17, 2004.
Under the CCE Holdings Agreement, Enron agreed to extend certain of the terms of
the transition services agreement and transition services supplemental agreement
between CrossCountry and Enron (together the "TSA") for a period of six months
from the closing date.
As part of the closing, ONEOK and CCE Holdings entered 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 through ONEOK. As services are
transitioned to Northern Plains or ONEOK, it is possible that additional costs
for computer hardware, software and personnel may result. The costs estimated to
date do not appear to be materially greater than the costs incurred in the past
by Northern Plains from Enron and CrossCountry.
PENSION LIABILITY
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 ("Cash Balance Plan") and certain
other defined benefit plans of Enron's affiliates (collectively the "Plans") in
"standard terminations" within the meaning of Section 4041 of the Employee
Retirement Income Security Act of 1974, as amended ("ERISA"). On January 30,
2004, the Bankruptcy Court entered an order authorizing the termination,
additional funding and other actions necessary to effect the relief requested.
Pursuant to the Bankruptcy Court order, any contributions to the Plans are
subject to the prior receipt of a favorable determination by the Internal
Revenue Service that the Plans are tax-qualified as of their respective dates of
termination.
On July 19, 2004, Enron was served with a complaint filed by the Pension
Benefits Guaranty Corporation ("PBGC") in the District Court for the Southern
District of Texas against Enron as the sponsor and/or administrator of the Plans
(the "Action"). By filing the Action, the PBGC is seeking an order (i)
terminating the Plans; (ii) appointing the PBGC the statutory trustee of the
Plans; (iii) requiring transfer to the PBGC of all records, assets or other
property of the Plans required to determine the benefits payable to the Plans'
participants; and (iv) establishing June 2, 2004 as the termination date of the
Plans. In the Bankruptcy Court September 10 Order, Enron was authorized to enter
into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron
deposited the amount of $321.8 million to an escrow account, which is
25
intended to ensure that none of CCE Holdings or its affiliates are exposed to
liability to the PBGC under Title IV of the Employee Retirement Income Security
Act of 1974, as amended, for which CCE Holdings may otherwise be indemnified
pursuant to the CCE Holdings Agreement. In addition, the form of escrow
agreement approved pursuant to the September 10 Order provides that, under
certain circumstances and upon approval by or notice to the parties to the
escrow agreement, some or all of the funds placed in escrow may be paid directly
in respect of the Cash Balance Plan to the PBGC. However, the September 10 Order
also provides that PBGC retains any rights or claims it may have against the
Transfer Group Companies.
Enron management previously informed Northern Plains that Enron would seek
funding contributions from each member of its ERISA controlled group of
corporations that employs, or employed, individuals who are, or were, covered
under the Cash Balance Plan. Northern Plains and NBP Services are 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' 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, these costs could be our
responsibility, we accrued $3.1 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 advised us that no claim of
reimbursement for the termination costs will be made, resulting in a reduction
in reserves during 2004 of $3.1 million for the termination costs. Under the
ONEOK Agreement, neither we nor Northern Plains will be required to contribute
to or otherwise be liable for any contributions to Enron in connection with the
Cash Balance Plan. The purchase price under the agreements will be deemed to
include all contributions which otherwise would have been allocable to Northern
Plains.
CLAIMS FILED IN BANKRUPTCY
At the time of the filing of the bankruptcy petition, we had a number of
contractual relationships with Enron and its subsidiaries.
On July 15, 2004, the Bankruptcy Court approved the amended joint Chapter
11 plan and related disclosure statement ("Chapter 11 Plan"). Under the approved
Chapter 11 Plan, assuming the previously announced sale of Portland General
Electric is consummated, Enron creditors, which should include us as a general
unsecured creditor, will receive a combination of cash and equity of Prisma
Energy International, Enron's international energy asset business. We have
previously fully reserved our claims against Enron.
ENA, a wholly owned subsidiary of Enron that is in bankruptcy, was a party
to transportation contracts which obligated ENA to pay for 3.5% of our capacity.
Through the bankruptcy proceeding in 2002, ENA rejected and terminated all of
its firm transportation contracts on us. Since Enron guaranteed the obligations
of ENA under those contracts, we filed claims against both ENA and Enron for
damages in the bankruptcy
26
proceedings. As a result of a settlement agreement between ENA, Enron and us,
each of ENA and Enron have agreed to allow our claim of approximately $20.6
million. The settlement agreement is expected to be presented to the Bankruptcy
Court for approval in March 2005. Based upon this settlement between the
parties, at December 31, 2004 we adjusted our allowance for doubtful accounts to
reflect an estimated recovery of $1.1 million for these claims.
We estimate that we could recognize, through future operating results,
additional recoveries of $6 million to $9 million for the claims in the Enron
bankruptcy proceedings. However, there can be no assurances on the amounts
actually recovered or timing of distributions under the Chapter 11 Plan.
VEBA TRUST
Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust (the
"Trust"), which when taken together with the Enron Corp. Medical Plan for
Inactive Participants (the "Medical Plan") constitutes a "voluntary employees'
beneficiary association" or "VEBA" under Section 501(c) (9) of the Internal
Revenue Code. In October 2002, Northern Plains was advised that Enron had
notified the committee that has administrative and fiduciary oversight related
to the Trust and the Medical Plan, that Enron had made the determination to
begin necessary steps to partition the assets of the Trust and the related
liabilities of the Medical Plan among all of the participating employers of the
Trust. The Trust was established as a regulatory requirement for inclusion of
certain costs for post-employment medical benefits in the rates established for
the affected pipelines, including us. Enron requested the enrolled actuary to
prepare an analysis and recommendation for the allocation of the Trust's assets
and associated liabilities among all the participating employers. On July 22,
2003, Enron sought approval of the Bankruptcy Court to terminate the Trust and
to distribute its assets among certain identified pipeline companies, one being
Northern Plains. If Enron's relief would have been granted as requested,
Northern Plains would have assumed retiree benefit liabilities, estimated as of
June 30, 2002, of $1.9 million with an asset allocation of $0.8 million. An
objection to the motion was filed. An additional actuary has been engaged by
Enron to review the analysis and recommendations for allocations. The results of
that review have not been provided to Northern Plains. It is anticipated that a
new motion will be filed and that the allocation of liabilities and assets will
change from those set forth in the prior motion. We do not, however, believe
that those changes will be material.
PUBLIC UTILITY HOLDING COMPANY ACT ("PUHCA") REGULATION
We were previously a subsidiary of a registered holding company. Upon
consummation of the sale of Northern Plains and Pan Border to CCE Holdings and
to ONEOK, we were no longer a subsidiary of a registered holding company.
RISK FACTORS AND INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
Statements in this Annual Report on Form 10-K that are not historical
information are forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of
27
the Securities Exchange Act of 1934. These forward-looking statements are
identified as any statement that does not relate strictly to historical or
current facts. Forward-looking statements are not guarantees of performance.
They involve risks, uncertainties and assumptions. The future results of our
operations may differ materially from those expressed in these forward-looking
statements. Such forward-looking statements include:
- the discussions in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - The Impact Of
Enron's Chapter 11 Filing On Our Business";
- the discussions in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Overview"; and
- the discussions in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and
Capital Resources."
Although we believe that our expectations regarding future events are
based on reasonable assumptions within the bounds of our knowledge of our
business, we cannot assure you that our goals will be achieved or that our
expectations regarding future developments will be realized.
With this in mind, you should consider the following important factors
that could cause actual results to differ materially from those in the
forward-looking statements:
- Any shipper's failure to perform its contractual obligations could
adversely impact our cash flows and financial condition. Some of our
shippers or their owners have experienced a deterioration of their
financial condition. Should one or more file for bankruptcy
protection, our ability to recover amounts owed or to resell the
capacity would be impacted.
- Since Northern Plains, our operator, is transitioning services
from Enron and CrossCountry, Northern Plains may be unable to
perform certain services under it operation agreement or may incur
increases in costs to continue or replace the services.
- Our ability to recontract capacity as existing contracts
terminate for maximum transportation rates will be subject to a
number of factors including availability of natural gas supplies
from the western Canadian sedimentary basin, the demand for natural
gas in our market areas and the basis differential between the
receipt and delivery points on our system. We may have to contract
for shorter periods or at less than maximum rates. See "Overview"
above and Item 1. "Business - Demand For Transportation Capacity."
- We are subject to extensive regulation by the FERC governing all
aspects of our business, including our transportation rates. Under
our 1999 rate case settlement,
28
neither our existing customers nor we can seek rate changes until
November 2005, at which time we are obligated to file a rate case.
We cannot predict what challenges we may have to our rates in the
future. See Item 1. "Business - FERC Regulation."
- In the event that the FERC ultimately determines that interstate
natural gas pipelines that are partnerships are not entitled to an
allowance for income tax in their rates and we are unsuccessful in
our arguments regarding our facts and circumstances, the
disallowance of this component of cost of service for rates could be
materially adverse to us. See Item 1. "Business - FERC Regulation."
- In a rate case proceeding setting the maximum rates that may be
charged, interstate pipeline systems are generally allowed the
opportunity to collect from their customers a return on their assets
or "rate base" as reflected in their financial records as well as
recover that rate base through depreciation. The amount they may
collect from customers, as a result of a subsequent rate case,
decreases as the rate base declines as a result of depreciation and
amortization. In order to avoid a reduction in the level of cash
available for distributions to its owners an interstate pipeline
must maintain or increase its rate base through projects that
maintain or add to existing pipeline facilities or increase its rate
of return in a future rate case.
- Our operations are subject to federal and state agencies for
environmental protection and operational safety. We may incur
substantial costs and liabilities in the future as a result of
stricter environmental and safety laws, regulations and enforcement
policies. See Item 1. "Business - Environmental and Safety Matters."
- Due to widespread state budget deficits, several states are
evaluating ways to increase revenues through taxation. Such taxation
may adversely impact us.
- We expect to seek rate recovery of our costs associated with the
settlement of pipeline right-of-way lease and taxation issues with
the Fort Peck Tribes and the costs associated with the early
redemption of $75 million of our senior notes. If we are unable to
recover these costs in rates, we will be required to expense costs
previously deferred as regulatory assets. See Item 3. "Legal
Proceedings."
Additional risks and uncertainties not currently known to us, or risks
that we currently deem immaterial may impair our business operations. Any of the
risk factors described above could significantly and adversely impair our
operating results.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We may be exposed to market risk through changes in interest
29
rates as discussed below. A control environment has been established which
includes policies and procedures for risk assessment and the approval, reporting
and monitoring of financial instrument activities.
We have utilized and expect to continue to utilize financial instruments
in the management of interest rate risks to achieve a more predictable cash flow
by reducing our exposure to interest rate fluctuations. We do not use these
instruments for trading purposes.
Our interest rate exposure results from variable rate borrowings from
commercial banks. To mitigate potential fluctuations in interest rates, we
attempt to maintain a significant portion of our debt portfolio in fixed rate
debt. We also use interest rate swaps as a means to manage interest expense by
converting a portion of fixed rate debt into variable rate debt to take
advantage of declining interest rates. At December 31, 2004, we had no variable
rate debt outstanding. For additional information on our debt obligations and
derivative instruments, see Note 5 and Note 6 to our Financial Statements,
included elsewhere in this report.
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 equivalent of our 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 report. Based upon
their evaluation, the equivalent of our principal executive officer and
principal financial officer concluded that our disclosure controls and
procedures are effective.
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. However, in the quarter ending December 31, 2004, the payroll system
used for the employees of Northern Plains was transitioned to ONEOK's payroll
system.
The Partnership relied on certain systems owned or services provided by
Enron and/or CrossCountry that support our financial accounting and reporting.
Since the sale of Northern Plains on November 17, 2004, the Partnership has
begun the transition of these systems to systems owned by us or provided by
ONEOK.
30
The Partnership's transition from the Enron and/or CrossCountry systems
and services should be completed in May 2005. This activity has and will cause
changes to the Partnership's internal control over financial reporting.
ITEM 9B. OTHER INFORMATION.
None.
31
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Northern Border Pipeline Company is overseen by the management committee,
which is composed of the following individuals:
William R. Cordes, Chairman(1)
David L. Kyle (1)
Max Feldman(2)
Paul E. Miller(1)
- ----------
(1) Designated by Northern Border Partners.
(2) Designated by TC PipeLines.
William R. Cordes (56) has been a member and Chairman of our management
committee since October 1, 2000. Mr. Cordes was named Chief Executive Officer of
Northern Border Partners in October 2000. Mr. Cordes is the President of
Northern Plains, Pan Border and NBP Services, ONEOK subsidiaries, having been
appointed to that position on October 1, 2000 for Northern Plains and Pan Border
and November 17, 2004 for NBP Services. In 1970, he started his career at
Northern Natural Gas Company, an Enron subsidiary until February 2002, where he
worked in several management positions. From June of 1993 until September of
2000, he was President of Northern Natural Gas Company and from May of 1996
until September of 2000, he was also the President of Transwestern Pipeline, an
Enron subsidiary.
David L. Kyle (52) was designated as a member of our Management
Committee and named Chairman of the Partnership Policy Committee of Northern
Border Partners in November 2004. Mr. Kyle is Chairman and Chief Executive
Officer of Northern Plains, Pan Border and NBP Services. Besides Chairman of the
Policy Committee of Northern Border Partners, Mr. Kyle is the Chairman of the
Board, President, and Chief Executive Officer of ONEOK, Inc. 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
September 1, 1986, and Executive Vice President May 17, 1990 of Oklahoma Natural
Gas Company. He was elected President of Oklahoma Natural Gas Company on
September 1, 1994. He was elected President of ONEOK, Inc. effective September
1, 1997, and was elected Chairman of the Board and appointed the Chief Executive
Officer of ONEOK, Inc. August 28, 2000. Mr. Kyle is a member of the boards of
directors of Bank of Oklahoma Financial Corporation and Blue Cross and Blue
Shield of Oklahoma.
In September 2003, TC PipeLines, LP designated Max Feldman (56) as its
member on our Management Committee. Mr. Feldman is Vice-President, Gas
Transmission-West, of TransCanada PipeLines Limited, a position he has held
since April 2003. From 1999 to 2003, he was Senior Vice-President, Customer
Sales and Service, and from 1995 to 1999, Mr. Feldman held several
Vice-President positions in the operations, customer service and marketing areas
of TransCanada PipeLines Limited.
32
In September 2003, TransCanada designated Paul E. Miller (45) as its
member on the Northern Border Partners, L.P. Policy Committee and designated Mr.
Miller as Northwest Border's representative on our Management Committee.
Additionally, Mr. Miller serves as Director Corporate Development of
TransCanada, a position he has held since February 2003. From July 1998 to
January 2003, Mr. Miller was Director Finance of TransCanada. Prior to July
1998, Mr. Miller was Manager, Finance of TransCanada.
Day-to-day management and operations are the responsibility of the
operator, Northern Plains, as set forth in the operating agreement. We have no
employees or executive officers. Officers and employees of Northern Plains, as
well as employees of its affiliates, provide services to our operations and we
reimburse Northern Plains for such costs. We do not compensate members of the
management committee for their services. The following individuals, as well as
Mr. Cordes whose information is provided above, are officers of the Operator
who are deemed to be executive officers of the partnership:
Jerry L. Peters was named Chief Financial and Accounting Officer of
Northern Border Partners, L.P. in July 1994. Mr. Peters has held several
management positions with Northern Plains since 1985 and was elected Vice
President of Finance in July 1994, and Treasurer in October 1998 for Northern
Plains. Mr. Peters was also elected Vice President of Finance for NBP Services
in November 2004. Mr. Peters was also 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.
Christopher R Skoog was appointed executive vice president of Northern
Plains and NBP Services effective February 1, 2005. Mr. Skoog is responsible for
all commercial, operational and regulatory functions of the Partnership's
natural gas businesses and will coordinate the Partnership's business
development initiatives. From 1999 to January 31, 2005, Mr. Skoog served as
President of ONEOK Energy Services Company, II. From 1995 to 1999, he was Vice
President, ONEOK Gas Marketing Company.
Paul F. Miller is Vice President and General Manager for Northern Border
Pipeline of Northern Plains, having been elected in January 2005. From March
2002 until January 2005, Mr. Miller was Vice President of Marketing for Northern
Plains. Mr. Miller was previously Account Executive, Marketing from December
1998 until August 2000, when he was promoted to Director, Marketing. Mr. Miller
joined Northern Plains in 1990.
Michel E. Nelson is Vice President, Operations for Northern Plains, having
been elected in November 2004. Mr. Nelson was previously Vice President of
Operations and Support Services for CrossCountry Energy, LLC, an Enron
subsidiary, from 2002 to November 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.
Raymond D. Neppl is Vice President, Regulatory Affairs and Market
Services, a position he has held since July 1994. Mr. Neppl was previously
33
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.
Janet K. Place is Vice President, General Counsel and Secretary of
Northern Plains, having been elected in August 1994 as Vice President and
November 2004 as Secretary. She was also elected Vice President, General Counsel
and Secretary of NBP Services in November 2004. In 1993, Ms. Place was named
General Counsel. Ms. Place joined Northern Plains in 1980 as an Attorney.
Fred G. Rimington is Vice President, Administration of Northern Plains and
NBP Services, having been elected in February 2005. He is also the President of
Black Mesa Pipeline, Inc., having been appointed in January 2000. Mr. Rimington
was Director, Business Development from 1994 to 1999 for Northern Plains. Mr.
Rimington joined Northern Plains in 1980.
There is also an audit committee composed of members appointed by the
management committee. The audit committee, consisting of Mr. Lee Hobbs, Vice
President and Controller, TransCanada, and Mr. Max Feldman, Vice President,
TransCanada, oversees the annual audit process and confers with KPMG LLP, our
independent auditors. There are only two members on the audit committee since no
member can be appointed by Northern Plains or any of its affiliates. The
Management Committee has determined that Mr. Lee Hobbs is our "audit committee
financial expert". Our audit committee financial expert is not independent and
is not required to be independent because we do not have securities that are
listed on a national exchange or national securities association.
Code of Ethics
The management committee has adopted an Accounting and Financial Reporting
Code of Ethics for those officers of Northern Plains that are the equivalent of
our principal executive officer and principal financial and accounting officer.
The code of ethics is posted on the "Other Postings" section of our website,
www.nbpl.nborder.com, and we intend to post on our website any amendments to, or
waivers from, any provision of our Accounting and Financial Reporting Code of
Ethics that applies to those officers of Northern Plains that are the equivalent
of our principal executive officer and principal financial and accounting
officer within four business days following such amendment or waiver.
34
ITEM 11. EXECUTIVE COMPENSATION.
The following table sets forth a summary of compensation paid for the last
three years, if applicable, of the equivalent of the chief executive officer of
the partnership and the other four most highly compensated executive officers of
the Operator during 2004, which we collectively refer to as the "Named
Officers." For the years 2002, 2003 and through November 17, 2004, compensation
plans were administered by Enron. Beginning November 18, 2004, compensation
plans are administered by ONEOK.
SUMMARY COMPENSATION TABLE
Annual Compensation
Other Annual Long-Term Compensation All Other
Compensation Restricted Stock Compensation
Name & Position Year Salary$ Bonus $(1) (2) Awards ($) (3)(4) ($) (5)
--------------- ---- -------- --------- ------------- ---------------------- -------
William R. Cordes 2004 $325,000 $ 175,000 -- $ -- $ 4,908
Chief Executive Officer 2003 $324,583 $ 200,000 -- $ 99,972 $ 3,000
2002 $319,333 $ 240,000 -- $100,051 $ 1,031
Jerry L. Peters 2004 $171,380 $ 110,000 -- -- $ 5,658
Chief Financial and 2003 $163,324 $ 107,500 -- -- $ 76,386
Accounting Officer 2002 $159,285 $ 110,000 -- -- $ 23,950
Janet K. Place 2004 $182,552 $ 115,000 -- -- $ 8,675
Vice President & General 2003 $177,592 $ 110,000 -- -- $ 6,233
Counsel and Secretary 2002 $171,500 $ 110,000 -- -- $ 7,266
NPNG
Paul F. Miller 2004 $153,298 $ 118,000 -- -- $ 5,335
Vice President & General 2003 $148,958 $ 111,000 -- -- $ 90,325
Manager for Northern 2002 $139,850 $ 92,000 -- -- $ 4,721
Border Pipeline
Raymond D. Neppl 2004 $165,393 $ 82,500 -- -- $ 5,489
Vice President, Regulator 2003 $160,905 $ 74,000 -- -- $ 4,965
Affairs & Market Services 2002 $155,433 $ 70,000 -- -- $ 5,112
(1) For bonus amounts for 2004, there was an early payout of an amount
equal to 10/12ths in October 2004 and the remaining 2/12s was paid
in March 2005.
(2) No Named Officer received perquisites or other personal benefits,
securities or property in an amount in excess of the lesser of
either $50,000 or 10% of the total of salary and bonus reported for
such officer in the two preceding columns.
(3) The aggregate total of shares in unreleased Enron restricted stock
holdings and their values as of December 31, 2003, for each of the
Named Officers is: Mr. Cordes, 4,295 shares valued at $0, Mr.
Peters, 1,701 shares valued at $0 and Ms. Place, 1,832 at $0.
Dividend equivalents for all restricted stock awards accrue from
date of grant and are paid upon vesting. Any dividends on Enron
Corp. stock accrued and unreleased as of the date of Enron Corp.'s
filing for bankruptcy protection will only be released in accordance
with applicable bankruptcy law.
(4) Mr. Cordes' employment agreement, as executed in September 2001,
provided for a grant of 882 Northern Border Phantom Units. On June
1, 2002 and 2003, grants of 697 and 669 Northern Border Phantom
Units valued at $143.5456 and $149.4346 per unit, respectively, were
made in accordance with his employment agreement. The phantom units
vest on the fifth anniversary of the date of the grant.
(5) The amounts shown for 2004 include the matching contributions to
employees' Enron Corp. Savings Plan and the Thrift Plan for
employees of ONEOK, and imputed income on life insurance benefits.
For each of Mr. Cordes and Mr. Peters, the amount shown for 2004 was
for matching contributions. For Ms. Place, the amount shown for 2004
for matching contributions was $6,050 and for imputed income was
$2,625. For Mr. Miller, the amount shown for 2004 for matching
contributions was $5,080 and for imputed income was $255. For Mr.
Neppl, the amount shown for 2004 for matching contributions was
$5,481 and for imputed income was $8. Mr. Peters' employment
agreement, as executed in April 2002, provided for a "stay" bonus in
which $23,950 of the amount was paid six months following the
implementation of the agreement. The remaining
35
amount of $71,853 was paid in March 2003 upon completion of the term
of the agreement. Mr. Miller's employment agreement, as executed in
October 2002, provided for a "stay" bonus in which 25% was to be
paid six months following the implementation of the agreement and
the remainder upon completion of the term of the agreement. The
entire bonus of $85,470 was distributed in 2003.
For 1999, 2000 and 2001, employees of Northern Plains were able to elect
to receive Northern Border phantom units, Enron Corp. phantom stock, and/or
Enron Corp. stock options in lieu of all or a portion of an annual bonus
payment. Messrs. Cordes, Peters, Neppl and Miller and Ms. Place 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; Mr. Miller received 137 units in 1999, 123
units in 2000 and 230 units in 2001 and Mr. Neppl received 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. For the release in January 2003, Ms. Place received 1,091 common units
and for the release in 2004, she elected a redemption payment in cash of
$83,232.28. For the release in January 2002, Mr. Miller received 333 common
units; for the release in 2003, he received 329 common units and for the release
in 2004, he elected a redemption payment in cash of $25,283.42.
On January 20, 2005, the Board of Directors of ONEOK granted restricted
stock incentive units and performance share units to the named executive
officers as follows: Mr. Cordes, 6,000 restricted stock incentive units and
10,500 performance share units; Mr. Peters, 3,000 restricted stock incentive
units and 4,500 performance share units; Ms. Place 2,000 restricted stock
incentive units and 3,500 performance share units; Mr. Neppl 1,500 restricted
stock incentive units and 2,500 performance share units; and Mr. Miller 2,500
restricted stock incentive units and 4,000 performance share units. The
restricted stock incentive units vest 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. The performance share
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 20,
2005 to January 20, 2008, compared to the total shareholder return of a peer
group of 20 other companies, payable two-thirds of the grant in shares of ONEOK
common stock and one-third of the grant in cash.
OPTION/SAR GRANTS IN 2004
Due to the bankruptcy filing by Enron Corp on December 2, 2001, there were
no grants of stock options pursuant to Enron's stock plans to the Named Officers
reflected in the Summary Compensation Table. No stock appreciation rights were
granted during 2004.
AGGREGATED OPTION/SAR EXERCISES IN 2004 AND YEAR-END 2004 OPTION/SAR VALUES
The following table sets forth information with respect to the Named
Officers concerning the exercise of Enron SARs and options during the last
fiscal year and unexercised Enron options and SARs held as of December 31, 2004:
36
Number of Securities
Underlying Unexercised Value of Unexercised
Options/SARs at In-the-Money Options/SARs
Shares December 31, 2004 December 31, 2004 (1)
Name Acquired on Value -------------------------- --------------------------
Exercisable Exercise (#) Realized($) Exercisable Unexercisable Exercisable Unexercisable
------------- ------------ ----------- ----------- ------------- ----------- -------------
William R. Cordes -- $-- 182,270 650 $-- $--
Jerry L. Peters -- $-- 62,850 305 $-- $--
Janet K. Place -- $-- 37,383 332 $-- $--
Raymond D. Neppl -- $-- 30,661 304 $-- $--
Paul F. Miller -- $-- 20,684 218 $-- $--
(1) Due to Enron's bankruptcy filing there is no dollar value assignable to
Enron Corp. stock options.
TERMINATION AGREEMENT
Effective January 5, 2005, ONEOK, Inc. entered into termination agreements
with Messrs. Cordes, Peters, Neppl and Miller and Ms. Place.
Each termination agreement has an initial term from January 5, 2005 until
January 1, 2007 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.
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 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
37
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 our assets.
RETIREMENT PLANS-ENRON
Enron maintains the Enron Corp. Cash Balance Plan (the "Cash Balance
Plan"), which is a noncontributory defined benefit pension plan to provide
retirement income for employees of Enron and its subsidiaries. Through December
31, 1994, participants in the Cash Balance Plan with five years or more of
service were entitled to retirement benefits in the form of an annuity based on
a formula that uses a percentage of final average pay and years of service. In
1995, Enron's Board of Directors adopted an amendment to and restatement of the
Cash Balance Plan changing the plan's name from the Enron Corp. Retirement Plan
to the Enron Corp. Cash Balance Plan. In connection with a change to the
retirement benefit formula, all employees became fully vested in retirement
benefits earned through December 31, 1994. The formula in place prior to January
1, 1995 was suspended and replaced with a benefit accrual in the form of a cash
balance of 5% of eligible annual base pay beginning January 1, 1996. Effective
January 1, 2003 Enron suspended future 5% benefit accruals under the Cash
Balance Plan. Each employee's accrued benefit will continue to be credited with
interest based on ten-year Treasury Bond yields.
Enron maintained a noncontributory employee stock ownership plan ("ESOP"),
which was merged into the Enron Corp. Savings Plan effective August 30, 2002 and
covered all eligible employees. Allocations to individual employees' retirement
accounts within the ESOP offset a portion of benefits earned under the Cash
Balance Plan prior to December 31, 1994. December 31, 1993 was the final date on
which ESOP allocations were made to employees' retirement accounts.
The following table sets forth the estimated annual benefits payable under
the Cash Balance Plan at normal retirement at age 65, assuming only interest
credits based on ten-year Treasury Bond yields and no future 5% benefit accruals
after January 1, 2003, with to the Named Officers under the provisions of the
foregoing retirement plans.
38
ESTIMATED
CURRENT CREDITED CURRENT ESTIMATED
CREDITED YEARS OF COMPENSATION ANNUAL BENEFIT
YEARS OF SERVICE COVERED PAYABLE UPON
SERVICE AT AGE 65 BY PLANS RETIREMENT
-------- ---------- ------------ --------------
Mr. Cordes 34.4 34.4 $ 0 $73,979
Mr. Peters 19.1 19.1 $ 0 $22,933
Ms. Place 24.1 24.1 $ 0 $30,096
Mr. Neppl 29.9 29.9 $ 0 $41,033
Mr. Miller 14.9 14.7 $ 0 $13,028
NOTE: The estimated annual benefits payable are based on the straight life
annuity form without adjustment for any offset applicable to a participant's
retirement subaccount in Enron's ESOP.
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.
PENSION PLAN TABLE
YEARS OF SERVICE
Remuneration 15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS
- ------------ --------- --------- --------- --------- ---------
125,000 $ 33,091 $ 44,122 $ 55,152 $ 66,182 $ 77,213
150,000 $ 40,404 $ 53,872 $ 67,340 $ 80,807 $ 94,275
175,000 $ 47,716 $ 63,622 $ 79,527 $ 95,432 $ 111,338
200,000 $ 55,029 $ 73,372 $ 91,715 $ 110,057 $ 128,400
225,000 $ 62,341 $ 83,122 $ 103,902 $ 124,682 $ 145,463
250,000 $ 69,654 $ 92,872 $ 116,090 $ 139,307 $ 162,525
300,000 $ 84,279 $ 112,372 $ 140,465 $ 168,557 $ 196,650
400,000 $ 113,529 $ 151,372 $ 189,215 $ 227,057 $ 264,900
450,000 $ 128,154 $ 170,872 $ 213,590 $ 256,307 $ 299,025
500,000 $ 142,779 $ 190,372 $ 237,965 $ 285,557 $ 333,150
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. Credited years of service under this plan for the Named
Officers as of December 31, 2004 is 1/12 years.
For purposes of the table, the annual social security covered compensation
benefit of $46,284 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 2004 cannot exceed
$205,000.
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.
39
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 means the
employee's highest earnings during any 60 consecutive months during the last 120
months of employment. For any Named 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 the Board of Directors. Effective January 5, 2005, Messrs.
Cordes, Peters, Miller and Neppl and Ms. Place were named participants.
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 our retirement plan, but are not offset by social
security benefits.
ONEOK'S EMPLOYEE NON-QUALIFIED DEFERRED COMPENSATION PLAN
The Named Officers are 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 ONEOK's Board of Directors, 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 percent
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.
40
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. As part of the sale and purchase agreement between ONEOK and CCE
Holdings, for a period of 12 months, neither Northern Plains nor NBP Services
may take any action that would change the Severance Pay Plans that would have
an adverse impact on the employees of Northern Plains or NBP Services.
41
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDERS MATTERS.
The following table sets forth the beneficial ownership of our general
partnership interests. There are no limited partnership interests.
GENERAL
NAME OF BENEFICIAL PARTNERSHIP
OWNER INTEREST
Northern Border 70%
Partners, L.P. (1)
TC PipeLines, LP (2) 30%
- ----------
(1) The address of Northern Border Partners is 13710 FNB Parkway, Omaha, NE
68154-5200. Northern Border Partners holds its 70% general partnership
interest through Northern Border Intermediate Limited Partnership, a
subsidiary limited partnership. Northern Border Partners has three general
partners: Northern Plains, Pan Border and Northwest Border. Northern
Plains and Pan Border are wholly-owned subsidiaries of ONEOK, Inc. and
Northwest Border is a wholly-owned subsidiary of TransCanada.
(2) The address of TC PipeLines is 110 Turnpike Road, Suite 203, Westborough,
Massachusetts 01581. TC PipeLines holds its 30% general partnership
interest through TC PipeLines Intermediate Limited Partnership, a
subsidiary limited partnership. TC PipeLines has one general partner, TC
PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
We have extensive ongoing relationships with our general partners and
ONEOK. Northern Plains has acted and will continue to act as the operator of our
pipeline system pursuant to the terms of the operating agreement. The initial
term of the operating agreement expires in 2007. The operating agreement will
continue in effect thereafter on a year-to-year basis unless terminated by us or
Northern Plains upon six months written notice by either party. The operator is
entitled to reimbursement for all reasonable costs, including overhead and
administrative expenses, incurred by it and its affiliates in connection with
the performance of its responsibilities as operator. In addition, we have agreed
to indemnify the operator against any claims and liabilities arising out of the
good faith performance by the operator of its responsibilities under our
partnership agreement, to the extent the operator is acting within the scope of
its authority and in the course of our business. For the year ended December 31,
2004, the aggregate amount charged by Northern Plains and its current and former
affiliates, for its services as operator, was approximately $18.3 million. While
Northern Plains continues to perform its obligations, certain of the services
are provided through CrossCountry and Enron through the Northern Border
Transition Agreement and through ONEOK. This transition services agreement
provides for the continued use by Northern Plains of certain services, data
applications, systems and infrastructure relied on by Northern Plains and to
perform under the Operating Agreement with us. The term of the transition
services agreement is until May 16, 2005; the parties may agree to extend any
transition service beyond the term. The cost of the transition services is
estimated to be approximately $2 million for the full term of the agreement.
42
ONEOK holds contracts for firm transportation on Northern Border Pipeline
with expiration dates from December 31, 2004 to March 31, 2009. Revenues from
ONEOK for the period from the date of affiliation to December 31, 2004, were
$1.1 million. Also, ONEOK has entered into a precedent agreement for capacity on
our Chicago III Expansion Project.
See Item 7. "Management's Discussion and Analysis of Financial Condition
and Results of Operations - The Impact of Enron's Chapter 11 Filing On Our
Business."
Our interests could conflict with the interests of our general partners or
their affiliates, and in such case the members of our management committee will
generally have a fiduciary duty to resolve such conflicts in a manner that is in
our best interest.
Unless otherwise provided for in a partnership agreement, the laws of
Texas generally require a general partner of a partnership to adhere to
fiduciary duty standards under which it owes its partners the highest duties of
good faith, fairness and loyalty. These rules apply to our management committee.
Because of the competing interests identified above, the Northern Border
Pipeline Company Partnership Agreement contains provisions that modify certain
of these fiduciary duties. For example:
- Our partnership agreement provides that we indemnify the members of
our management committee and Northern Plains, as the operator,
against all actions if such actions were in good faith and within
the scope of their authority in the course of our business. It also
provides that such persons will not be liable for any liabilities
incurred by us as a result of such acts.
- Our partnership agreement states that our general partners will not
be liable to third persons for our losses, deficits, liabilities or
obligations (unless our assets have been exhausted).
- Our partnership agreement requires that any contract entered into on
our behalf must contain a provision limiting the claims of persons
to our assets and expressly waiving any rights of such persons to
proceed against our general partners individually.
- Our partnership agreement relieves Northern Border Partners and TC
PipeLines, their affiliates and their transferees from any duty to
offer business opportunities to us, except that neither our general
partners or their affiliates may pursue any opportunity relating to
expansion or improvements of our pipeline system as it existed on
January 15, 1999.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The following sets forth fees billed for the audit and other services provided
by KPMG LLP, our principal accountant, for the fiscal years ended December 31,
2004 and December 31, 2003:
Year Ended December 31,
2004 2003
Audit fees (1) $412,790 $111,810
Audit-related fees $ -- $ --
Tax fees $ -- $ --
43
All other fees $ -- $ --
-------- --------
Total $412,790 $111,810
(1) Includes fees for the audit of annual financial statements and audit
of internal control over financial reporting related to Northern
Border Partners' audit, reviews of the related quarterly financial
statements and reviews and related consents and comfort letters for
documents filed with the Securities and Exchange Commission. The
fees related to the audit of internal control were pre-approved by
the audit committee of Northern Border Partners. The remaining fees
were approved as discussed below.
Before our independent principal accountant is engaged each year for
the annual audit and other audit and any non-audit services, these
services and fees are reviewed and approved by our audit committee
and recommended to our Management Committee for approval.
44
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
(a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Financial Statements" set forth on page F-1.
(a) (3) EXHIBITS
* 3.1 Northern Border Pipeline Company General Partnership Agreement
between Northern Plains Natural Gas Company, Northwest Border
Pipeline Company, Pan Border Gas Company, TransCanada Border
Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978,
as amended (incorporated by reference to Exhibit 10.2 to Northern
Border Partners, L.P.'s Form S-1, SEC File No. 33-66158 ("Form
S-1")).
* 3.2 Seventh Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (incorporated by reference to Exhibit 10.15 to
Form S-1).
* 3.3 Eighth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (incorporated by reference to Exhibit 10.15 to
Northern Border Pipeline Company's Form S-4 Registration Statement,
filed on October 7, 1999, Registration No. 333-88577 ("Form S-4").
* 3.4 Ninth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (incorporated by reference to Exhibit 10.37 to
Northern Border Pipeline Company's Registration Statement on Form
S-4, filed on November 13, 2001, Registration No. 333-73282 ("2001
Form S-4").
3.5 Tenth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement dated March 3, 2005.
* 4.1 Indenture, dated as of August 17, 1999, between Northern Border
Pipeline Company and Bank One Trust Company, NA, successor to The
First National Bank of Chicago, as trustee (incorporated by
reference to Exhibit 4.1 to Form S-4).
* 4.2 Indenture, dated as of September 17, 2001, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (incorporated by
reference to Exhibit 4.2 to 2001 Form S-4).
* 4.3 Indenture, dated as of April 29, 2002, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (incorporated by
reference to Exhibit 4.1 to Northern Border Pipeline Company's Form
10-Q for the quarter ended March 31, 2002) (Filed No. 333-88577).
* 10.1 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).
* 10.2 Revolving Credit Agreement, dated as of May 16, 2002, among Northern
Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank of
Montreal, SunTrust Bank, Wachovia Bank, National Association, Banc
One Capital Markets, Inc, and Lenders (as defined therein)
(incorporated by reference to Exhibit 10.1 to Northern Border
Partners, L.P.'s Current Report on Form 8-K dated June 26, 2002
(File No. 1-12202)).
* 10.3 First Amendment to the Revolving Credit Agreement dated as of April
9, 2004 between Northern Border Pipeline Company, Bank
45
One, NA and the lenders named therein. (incorporated by reference to
Exhibit No. 10.1 to Northern Border Pipeline Company Quarterly
Report on Form 10-Q for the quarterly period ended March 31, 2004
(File No. 333-88577)).
* 10.4 Form of Conveyance, Contribution and Assumption Agreement among
Northern Plains Natural Gas Company, Northwest Border Pipeline
Company, Pan Border Gas Company, Northern Border Partners, L.P., and
Northern Border Intermediate Limited Partnership (incorporated by
reference to Exhibit 10.16 to Form S-1).
* 10.5 Form of Contribution, Conveyance and Assumption Agreement among TC
PipeLines, LP and certain other parties. (incorporated by reference
to Exhibit 10.2 to TC PipeLines, LP's Form S-1, SEC File No.
333-69947 ("TC Form S-1")).
+*10.6 Form of Termination Agreement with ONEOK dated as of January 5,
2005. (incorporated by reference to Exhibit 99.1 to Northern Border
Partners, L.P. Form 8-K filed on January 11, 2005 (File No.
1-12201)).
+*10.7 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan.
(incorporated by reference to Exhibit 99.1 to Northern Border
Partners, L.P. Form 8-K filed on January 11, 2005 (File No.
1-12201)).
+*10.8 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from
Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31,
2001 (File No. 1-13643)).
+*10.9 ONEOK, Inc. Form of Restricted Stock Incentive Award (incorporated
by reference from Exhibit 10.4 to ONEOK's Form 10-Q for the
quarterly period ended September 30, 2004 (File No. 1-13643)).
+*10.10 ONEOK, Inc. Form of Performance Shares Award (incorporated by
reference from Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly
period ended September 30, 2004 (File No. 1-13643)).
+*10.11 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as
amended, dated February 2001 (incorporated by reference from Exhibit
10(g) to ONEOK's Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
+*10.12 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference
from Exhibit 10(f) to Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
*10.13 Northern Border Pipeline Company Agreement among Northern Plains
Natural Gas Company, Pan Border Gas Company, Northwest Border
Pipeline Company, TransCanada Border PipeLine Ltd., TransCan
Northern Ltd., Northern Border Intermediate Limited Partnership,
Northern Border Partners, L.P., and the Management Committee of
Northern Border Pipeline, dated as of March 17, 1999 (incorporated
by reference to Exhibit 10.21 to Northern Border Partners, L.P.'s
Form 10-K/A for the year ended December 31, 1998 File No. 1-12202
("1998 10-K")).
*10.14 Northern Border Transition Services Agreement dated November 17,
2004, by and between ONEOK, Inc. and CCE Holdings, LLC.
(incorporated by reference to Exhibit 10.24 to Northern Border
Partners, L.P.'s Form 10-K for the year ended December 31, 2004
(File No. 1-122022)).
12.1 Statement re computation of ratios.
46
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 Northern Border Partners, L.P.'s
Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern
Border Partners, L.P.'s Registration No. 333-72696).
*Indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith.
+ Management contract, compensatory plan or arrangement.
47
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 11 day of
March, 2005.
NORTHERN BORDER PIPELINE COMPANY
(A Texas General partnership)
BY: Northern Plains Natural Gas Company,
As Operator
By:/s/ Jerry L. Peters
---------------------
Jerry L. Peters
Vice President, Finance and
Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
Signature Title Date
--------- ----- ----
/s/ William R. Cordes President, Northern Plains Natural March 11, 2005
- --------------------- Gas Company
William R. Cordes (functional equivalent to the
registrant's principal executive officer)
and Management Committee Member
/s/ Jerry L. Peters Vice President, Finance and March 11, 2005
- --------------------- Treasurer,
Jerry L. Peters Northern Plains Natural Gas Company
(functional equivalent to the
registrant's principal financial and
accounting officer)
/s/ David L. Kyle Management Committee Member March 11, 2005
- ---------------------
David L. Kyle
/s/ Max Feldman Management Committee Member March 11, 2005
- ---------------------
Max Feldman
/s/ Paul E. Miller Management Committee Member March 11, 2005
- ---------------------
Paul E. Miller
48
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT
No annual report to security holders covering our last fiscal year has
been sent to our security holders and no proxy statement, form of proxy or other
proxy soliciting material has been sent to more than ten of our security
holder's with respect to any annual or other meeting of security holders. No
such report or proxy material is expected to be furnished to security holders
subsequent to the filing of this Annual Report on Form 10-K.
49
NORTHERN BORDER PIPELINE COMPANY
INDEX TO FINANCIAL STATEMENTS
PAGE NO.
-----------
Financial Statements
Report of Independent Registered Public Accounting Firm F-2
Balance Sheet - December 31, 2004 and 2003 F-3
Statement of Income - Years Ended F-4
December 31, 2004, 2003 and 2002
Statement of Comprehensive Income - Years Ended F-4
December 31, 2004, 2003 and 2002
Statement of Cash Flows - Years Ended F-5
December 31, 2004, 2003 and 2002
Statement of Changes in Partners' Equity - F-6
Years Ended December 31, 2004, 2003 and 2002
Notes to Financial Statements F-7 through
F-18
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 Pipeline Company:
We have audited the accompanying balance sheets of Northern Border Pipeline
Company as of December 31, 2004 and 2003, and the related statements of income,
comprehensive income, cash flows, and changes in partners' equity for each of
the years in the three-year period ended December 31, 2004. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with 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 financial statements referred to above present fairly, in
all material respects, the financial position of Northern Border Pipeline
Company as of December 31, 2004 and 2003, and the results of its operations and
its cash flows for each of the years in the three-year period ended December 31,
2004, in conformity with accounting principles generally accepted in the United
States of America.
/s/ KPMG LLP
Omaha, Nebraska
March 2, 2005
F-2
NORTHERN BORDER PIPELINE COMPANY
BALANCE SHEET
(IN THOUSANDS)
DECEMBER 31,
---------------------------
2004 2003
----------- -----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 20,355 $ 28,732
Accounts receivable (net of allowance for
doubtful accounts of $4,208 in 2004) 32,559 33,292
Related party receivables (net of allowance
for doubtful accounts of $4,815
in 2003) 1,311 395
Materials and supplies, at cost 3,409 4,818
Prepaid expenses and other 1,688 2,267
----------- -----------
Total current assets 59,322 69,504
----------- -----------
NATURAL GAS TRANSMISSION PLANT
In service 2,444,729 2,434,369
Construction work in progress 2,768 4,447
----------- -----------
Total property, plant and equipment 2,447,497 2,438,816
Less: Accumulated provision for
depreciation and amortization 903,664 847,061
----------- -----------
Property, plant and equipment, net 1,543,833 1,591,755
----------- -----------
OTHER ASSETS
Derivative financial instruments -- 16,648
Unamortized debt expense 3,837 5,206
Regulatory asset 11,807 8,196
Other 4,549 --
----------- -----------
Total other assets 20,193 30,050
----------- -----------
Total assets $ 1,623,348 $ 1,691,309
=========== ===========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 4,058 $ 7,055
Related party payables 5,286 15,582
Accrued taxes other than income 27,113 28,947
Accrued interest 11,365 10,717
----------- -----------
Total current liabilities 47,822 62,301
----------- -----------
LONG-TERM DEBT 603,860 821,498
----------- -----------
RESERVES AND DEFERRED CREDITS 4,526 5,072
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 7)
PARTNERS' EQUITY
Partners' capital 963,378 797,236
Accumulated other comprehensive income 3,762 5,202
----------- -----------
Total partners' equity 967,140 802,438
----------- -----------
Total liabilities and partners' equity $ 1,623,348 $ 1,691,309
=========== ===========
The accompanying notes are an integral part of these financial statements.
F-3
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF INCOME
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
------------------------------------------
2004 2003 2002
---------- ---------- ----------
OPERATING REVENUES $ 329,115 $ 324,185 $ 321,050
---------- ---------- ----------
OPERATING EXPENSES
Operations and maintenance 33,763 43,791 41,442
Depreciation and amortization 58,375 57,779 58,714
Taxes other than income 29,368 29,634 28,436
---------- ---------- ----------
Operating expenses 121,506 131,204 128,592
---------- ---------- ----------
OPERATING INCOME 207,609 192,981 192,458
---------- ---------- ----------
INTEREST EXPENSE
Interest expense 41,374 44,903 51,550
Interest expense capitalized (18) (46) (25)
---------- ---------- ----------
Interest expense, net 41,356 44,857 51,525
---------- ---------- ----------
OTHER INCOME (EXPENSE)
Allowance for equity funds used
during construction 31 53 26
Other income 2,552 1,373 2,476
Other expense (2,059) (1,350) (716)
---------- ---------- ----------
Other income (expense), net 524 76 1,786
---------- ---------- ----------
NET INCOME TO PARTNERS $ 166,777 $ 148,200 $ 142,719
========== ========== ==========
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF COMPREHENSIVE INCOME
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
------------------------------------------
2004 2003 2002
---------- ---------- ----------
Net income to partners $ 166,777 $ 148,200 $ 142,719
Other comprehensive income:
Change associated with current
period hedging transactions (1,440) (1,556) (2,415)
---------- ----------- ----------
Total comprehensive income $ 165,337 $ 146,644 $ 140,304
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
F-4
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
------------------------------------------
2004 2003 2002
---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 166,777 $ 148,200 $ 142,719
---------- ---------- ----------
Adjustments to reconcile net income to
partners to net cash provided by
operating activities:
Depreciation and amortization 58,740 58,144 59,079
Provision for regulatory refunds -- 261 10,000
Regulatory refunds paid -- (10,261) --
Allowance for equity funds used
during construction (31) (53) (26)
Reserves and deferred credits (546) 1,001 (237)
Changes in components of working capital (12,611) (3,551) 13,268
Other (6,180) (471) (447)
---------- ---------- ----------
Total adjustments 39,372 45,070 81,637
---------- ---------- ----------
Net cash provided by operating activities 206,149 193,270 224,356
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (10,569) (12,918) (9,243)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Equity contributions from partners 205,000 -- --
Distributions to partners (205,635) (153,978) (164,126)
Issuance of long-term debt 107,000 142,000 431,894
Retirement of long-term debt (313,000) (165,000) (468,000)
Proceeds upon termination of derivatives 7,575 -- 2,351
Debt reacquisition costs (4,897) -- --
Long-term debt financing costs -- -- (2,877)
---------- ---------- ----------
Net cash used in financing activities (203,957) (176,978) (200,758)
---------- ---------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS (8,377) 3,374 14,355
Cash and cash equivalents-beginning of year 28,732 25,358 11,003
---------- ---------- ----------
Cash and cash equivalents-end of year $ 20,355 $ 28,732 $ 25,358
========== ========== ==========
Changes in components of working capital:
Accounts receivable $ (2,969) $ (4,908) $ 5,369
Materials and supplies 697 (97) 152
Prepaid expenses and other 578 (422) (113)
Accounts payable (9,731) 3,758 10,006
Accrued taxes other than income (1,834) 573 1,207
Accrued interest 648 (2,455) (3,353)
---------- ---------- ----------
Total $ (12,611) $ (3,551) $ 13,268
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
F-5
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CHANGES IN PARTNERS' EQUITY
(IN THOUSANDS)
TC NORTHERN
PIPELINES BORDER ACCUMULATED
INTERMEDIATE INTERMEDIATE OTHER TOTAL
LIMITED LIMITED COMPREHENSIVE PARTNERS'
PARTNERSHIP PARTNERSHIP INCOME EQUITY
------------ ------------ ------------- ---------
Partners' Equity at
December 31, 2001 $247,326 $ 577,095 $ 9,173 $ 833,594
Net income to
partners 42,816 99,903 -- 142,719
Change associated
with current period
hedging transactions -- -- (2,415) (2,415)
Distributions paid (49,238) (114,888) -- (164,126)
-------- --------- -------- ---------
Partners' Equity at
December 31, 2002 240,904 562,110 6,758 809,772
Net income to partners 44,460 103,740 -- 148,200
Change associated
with current period
hedging transactions -- -- (1,556) (1,556)
Distributions paid (46,193) (107,785) -- (153,978)
-------- --------- -------- ---------
Partners' Equity at
December 31, 2003 239,171 558,065 5,202 802,438
Net income to
partners 50,033 116,744 -- 166,777
Change associated
with current period
hedging transactions -- -- (1,440) (1,440)
Equity contributions received 61,500 143,500 -- 205,000
Distributions paid (61,690) (143,945) -- (205,635)
-------- --------- -------- ---------
Partners' Equity at
December 31, 2004 $289,014 $ 674,364 $ 3,762 $ 967,140
======== ========= ======== =========
The accompanying notes are an integral part of these financial
statements.
F-6
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Pipeline Company (Northern Border Pipeline) is a Texas
general partnership formed in 1978. The ownership percentages of the
partners in Northern Border Pipeline (Partners) at December 31, 2004 and
2003 are as follows:
Ownership
Partner Percentage
- ------------------------------------------------ ----------
Northern Border Intermediate Limited Partnership 70
TC PipeLines Intermediate Limited Partnership 30
Northern Border Pipeline owns a 1,249-mile natural gas transmission
pipeline system extending from the United States-Canadian border near Port
of Morgan, Montana, to a terminus near North Hayden, Indiana.
Northern Border Pipeline is managed by a Management Committee that
includes three representatives from Northern Border Intermediate Limited
Partnership (Partnership) and one representative from TC PipeLines
Intermediate Limited Partnership (TC PipeLines). The Partnership's
representatives selected by its general partners, Northern Plains Natural
Gas Company, 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, a
wholly-owned subsidiary of TransCanada PipeLines Limited, which is a
subsidiary of TransCanada Corporation, and affiliate of TC PipeLines, have
35%, 22.75% and 12.25%, respectively, of the voting interest on the
Management Committee. The representative designated by TC PipeLines votes
the remaining 30% interest.
In November 2004, ONEOK purchased Northern Plains and Pan Border from CCE
Holdings, LLC (CCE Holdings). CCE Holdings, a joint venture between
Southern Union Company and GE Commercial Finance Energy Financial
purchased Northern Plains and Pan Border as part of its acquisition of
CrossCountry Energy, LLC (CrossCountry).
On March 31, 2004, Enron Corp. (Enron) transferred its ownership interest
in Northern Plains and Pan Border 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 Northern
Border Pipeline through Northern Plains.
The day-to-day management of Northern Border Pipeline's affairs is the
responsibility of Northern Plains, as defined by an operating agreement
between Northern Border Pipeline and Northern Plains. Northern Border
Pipeline is charged for the salaries, benefits and expenses of Northern
Plains. As part of the closing, 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.
For the years ended December 31, 2004, 2003, and 2002, Northern Border
Pipeline's charges from Northern Plains and its current and former
affiliates totaled approximately $18.3 million, $25.6 million and
F-7
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT (continued)
$22.8 million, respectively. See Note 11 for a discussion of Northern
Border Pipeline's previous relationships with Enron and developments
involving Enron.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Use of Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those
estimates.
(B) Government Regulation
Northern Border Pipeline is subject to regulation by the Federal
Energy Regulatory Commission (FERC). Northern Border Pipeline's
accounting policies conform to Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation." Accordingly, certain assets that result from
the regulated ratemaking process are recorded that would not be
recorded under accounting principles generally accepted in the
United States of America for nonregulated entities.
At December 31, 2004 and 2003, Northern Border Pipeline has
reflected regulatory assets, which are currently being recovered or
are expected to be recovered from its shippers, of approximately
$11.8 million and $8.2 million, respectively, on the balance sheet.
Northern Border Pipeline is recovering these regulatory assets from
its shippers over varying time periods, which range from 5 to 44
years.
Northern Border Pipeline continually assesses whether the recovery
of the regulatory assets is probable by considering such factors as
regulatory changes and the impact of competition. Northern Border
Pipeline believes the recovery of the existing regulatory assets is
probable. If future recovery ceases to be probable, Northern Border
Pipeline would be required to write off the regulatory assets at
that time.
(C) Revenue Recognition
Northern Border Pipeline transports gas for shippers under a tariff
regulated by the FERC. The tariff specifies the calculation of
amounts to be paid by shippers and the general terms and conditions
of transportation service on the pipeline system. Northern Border
Pipeline's revenues are derived from agreements for the receipt and
delivery of gas at points along the pipeline system as specified in
each shipper's individual transportation contract. Revenues for
Northern Border Pipeline are recognized based upon contracted
capacity and actual volumes transported under transportation service
agreements. An allowance for doubtful accounts is recorded in
situations where collectibility is not reasonably assured.
F-8
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(C) Revenue Recognition (continued)
Northern Border Pipeline does not own the gas that it transports,
and therefore it does not assume the related natural gas commodity
risk.
(D) Income Taxes
Income taxes are the responsibility of the Partners and are not
reflected in these financial statements. However, the Northern
Border Pipeline FERC tariff establishes the method of accounting for
and calculating income taxes and requires Northern Border Pipeline
to reflect in its rates the income taxes, which would have been paid
or accrued if Northern Border Pipeline were organized during the
period as a corporation. As a result, for purposes of determining
transportation rates in calculating the return allowed by the FERC,
Partners' capital and rate base are reduced by the amount equivalent
to the net accumulated deferred income taxes. Such amounts were
approximately $355 million and $350 million at December 31, 2004 and
2003, respectively, and are primarily related to accelerated
depreciation and other plant-related differences.
(E) Cash and Cash Equivalents
Cash equivalents consist of highly liquid investments with original
maturities of three months or less. The carrying amount of cash and
cash equivalents approximates fair value because of the short
maturity of these investments.
(F) Property, Plant and Equipment and Related Depreciation and
Amortization
Property, plant and equipment is stated at original cost. During
periods of construction, Northern Border Pipeline is permitted to
capitalize an allowance for funds used during construction, which
represents the estimated costs of funds used for construction
purposes. The original cost of property retired is charged to
accumulated depreciation and amortization, net of salvage and cost
of removal. No retirement gain or loss is included in income except
in the case of retirements or sales of entire regulated operating
units.
Maintenance and repairs are charged to operations in the period
incurred. The provision for depreciation and amortization of the
transmission line is an integral part of Northern Border Pipeline's
FERC tariff. The effective depreciation rate applied to Northern
Border Pipeline's transmission plant is 2.25%. Composite rates are
applied to all other functional groups of property having similar
economic characteristics.
(G) Risk Management
Financial instruments are used by Northern Border Pipeline in the
management of its interest rate exposure. A control environment has
been established which includes policies and procedures for risk
assessment and the approval, reporting and monitoring of financial
instrument activities. Northern Border Pipeline does not use these
instruments for trading purposes. SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS
F-9
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(G) Risk Management (continued)
No. 137 and SFAS No. 138, requires that every derivative instrument
(including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or
liability measured at its fair value. The statement requires that
changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income
statement, and requires that a company formally document, designate
and assess the effectiveness of transactions that receive hedge
accounting. See Note 6 for a discussion of Northern Border
Pipeline's derivative instruments and hedging activities.
(H) Reclassifications
Certain reclassifications have been made to the financial statements
for prior years to conform with the current year presentation.
3. RATES AND REGULATORY ISSUES
The FERC regulates the rates and charges for transportation in interstate
commerce. Natural gas companies may not charge rates that have been
determined not to be just and reasonable by the FERC. Generally, rates for
interstate pipelines are based on the cost of service including recovery
of and a return on the pipeline's actual prudent historical cost
investment. The rates and 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. Under the terms of settlement in Northern Border Pipeline's 1999
rate case, neither Northern Border Pipeline nor its existing shippers can
seek rate changes to the settlement base rates until November 1, 2005, at
which time Northern Border Pipeline must file a new rate case.
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 Border Pipeline's proposed tariff sheet
revision and requiring refunds with interest within 90 days of the order.
Northern Border Pipeline made refunds to its shippers of $10.3 million in
May 2003.
4. TRANSPORTATION SERVICE AGREEMENTS
Operating revenues are collected pursuant to the FERC tariff through firm
transportation service agreements. The firm service agreements extend for
various terms with termination dates that range from December 2004 to
December 2013. Northern Border Pipeline also has interruptible
transportation service agreements and other transportation service
agreements with numerous shippers.
F-10
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
4. TRANSPORTATION SERVICE AGREEMENTS (continued)
Under the capacity release provisions of Northern Border Pipeline's FERC
tariff, shippers are allowed to release all or part of their capacity
either permanently for the full term of the contract or temporarily. A
temporary capacity release does not relieve the original contract shipper
from its payment obligations if the replacement shipper fails to pay for
the capacity temporarily released to it.
At December 31, 2004, Northern Border Pipeline's largest shippers, Nexen
Marketing, U.S.A. Inc (Nexen), BP Canada Energy Marketing Corp. (BP
Canada), EnCana Marketing U.S.A. Inc. (EnCana) and Cargill Incorporated
(Cargill), were obligated for approximately 18%, 14%, 13% and 12% of the
summer design capacity, respectively. The Nexen, BP Canada, EnCana and
Cargill firm service agreements extend for various terms with termination
dates from March 2005 to December 2013, December 2004 to February 2012,
October 2005 to June 2009 and March 2005 to December 2008, respectively.
For the year ending 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. (Pan Alberta) with operating
revenues of $54.7 million, $32.9 million and $45.5 million, respectively.
For the year ended December 31, 2002, Northern Border Pipeline's largest
shippers were Pan-Alberta and Mirant Americas Energy Marketing, LP with
combined operating revenues of $105.5 million.
At December 31, 2004, Northern Border Pipeline had contracted firm
capacity held by one shipper affiliated with its general partners. ONEOK
Energy Services Company L.P. (ONEOK Energy Services), a subsidiary of
ONEOK, holds firm service agreements representing 3% of summer design
capacity. The firm service agreements with ONEOK Energy Services extend
for various terms with termination dates that range from December 2004 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. Revenues from ONEOK Energy Services for the period from
the date of affiliation to December 31, 2004, were $1.1 million. At
December 31, 2004, Northern Border Pipeline had an outstanding receivable
from ONEOK Energy Services of $0.8 million. In 2003, there were no
operating revenues from affiliates. In 2002, one of Northern Border
Pipeline's shippers was affiliated with its general partners. Operating
revenues from affiliates were $1.4 million for the year ended December 31,
2002.
F-11
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
5. CREDIT FACILITIES AND LONG-TERM DEBT
Detailed information on long-term debt is as follows:
December 31,
-----------------------
(Thousands of dollars) 2004 2003
- -------------------------------------------- -------- --------
2002 Pipeline Credit Agreement - average
1.95% at December 31, 2003, due 2005 $ -- $131,000
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 150,000 225,000
Fair value adjustment for interest rate
swaps (Note 6) -- 16,648
Unamortized debt premium (discount) 3,860 (1,150)
-------- --------
Long-term debt $603,860 $821,498
======== ========
Northern Border Pipeline has entered into revolving credit facilities,
which are used for capital expenditures, acquisitions and general business
purposes and for refinancing existing indebtedness. Northern Border
Pipeline entered into a $175 million three-year credit agreement (2002
Pipeline Credit Agreement) with certain financial institutions in May
2002. The 2002 Pipeline Credit Agreement permits Northern Border Pipeline
to choose among various interest rate options, to specify the portion of
the borrowings to be covered by specific interest rate options and to
specify the interest rate period. Northern Border Pipeline is required to
pay a fee on the principal commitment amount of $175 million. The 2002
Pipeline Credit Agreement will mature in 2005, and is expected to be
replaced with a similar credit facility.
In April 2002, Northern Border Pipeline completed a private offering of
$225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior Notes).
The 2002 Pipeline Senior Notes were subsequently exchanged in registered
offerings for notes with substantially identical terms. The proceeds from
the senior notes were used to reduce indebtedness outstanding.
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, incurred a
$0.4 million loss related to the unamortized debt costs and discount
associated with the debt and received $2.5 million from the termination of
interest rate swaps associated with the debt (see Note 6). The net loss
from the redemption 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, 2004, the net unamortized loss on reacquired debt
was $2.6 million, which is recorded in regulatory assets on the balance
sheet.
Interest paid, net of amounts capitalized, during the years ended December
31, 2004, 2003 and 2002 was $41.1 million, $47.8 million and $55.3
million, respectively.
Aggregate required repayments of long-term debt for the next five years
are $150 million in 2007 and $200 million in 2009. Aggregate required
repayments of long-term debt thereafter total $250 million. There are no
required repayment obligations for 2005, 2006 or 2008.
F-12
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
5. CREDIT FACILITIES AND LONG-TERM DEBT (continued)
Certain of Northern Border Pipeline's long-term debt and credit
arrangements contain requirements as to the maintenance of minimum
partners' capital and debt to capitalization ratios, leverage ratios and
interest coverage ratios that restrict the incurrence of other
indebtedness by Northern Border Pipeline and also place certain
restrictions on distributions to the partners of Northern Border Pipeline.
The 2002 Pipeline Credit Agreement requires the maintenance of a ratio of
EBITDA (net income plus interest expense, income taxes and depreciation
and amortization) to interest expense of greater than 3 to 1. The 2002
Pipeline Credit Agreement also requires the maintenance of the ratio of
indebtedness to EBITDA of no more than 4.5 to 1. At December 31, 2004,
Northern Border Pipeline was in compliance with its financial covenants.
The following estimated fair values of financial instruments represent the
amount at which each instrument could be exchanged in a current
transaction between willing parties. Based on quoted market prices for
similar issues with similar terms and remaining maturities, the estimated
fair value of the aggregate of the 1999 Pipeline Senior Notes, 2001
Pipeline Senior Notes and 2002 Pipeline Senior Notes was approximately
$652 million and $739 million at December 31, 2004 and 2003, respectively.
Northern Border Pipeline presently intends to maintain the current
schedule of maturities for the 1999 Pipeline Senior Notes, the 2001
Pipeline Senior Notes and the 2002 Pipeline Senior Notes, which will
result in no gains or losses on their respective repayments. The fair
value of Northern Border Pipeline's variable rate debt approximates the
carrying value since the interest rates are periodically adjusted to
reflect current market conditions.
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Prior to the anticipated issuance of fixed rate debt, Northern Border
Pipeline entered into forward starting interest rate swap agreements. The
interest rate swap agreements were 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 did not exceed the
expected principal amount of fixed rate debt to be issued. Upon issuance
of the fixed rate debt, the swap agreements 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 debt. For the year ended December
31, 2002, Northern Border Pipeline received $2.4 million from terminated
interest rate swap agreements.
During the years ended December 31, 2004, 2003, and 2002, respectively,
Northern Border Pipeline amortized approximately $1.4 million, $1.6
million, and $1.4 million related to the terminated interest rate swap
agreements as a reduction to interest expense from accumulated other
comprehensive income. Northern Border Pipeline expects to amortize
approximately $1.5 million as a reduction to interest expense in 2005.
Northern Border Pipeline entered into interest rate swap agreements with
notional amounts totaling $225 million in May 2002. Under the interest
rate swap agreements, Northern Border Pipeline makes payments to
counterparties at variable rates based on the London Interbank Offered
Rate and in return receives payments based on a 6.25% fixed rate.
F-13
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)
In November 2004, Northern Border Pipeline terminated its interest rate
swap agreements with notional amounts of $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 5). The remaining
$5.0 million is recorded in long-term debt with such amount amortized to
interest expense over the remaining life of the interest rate swap
agreements. During the year ended December 31, 2004, Northern Border
Pipeline amortized approximately $0.2 million as a reduction to interest
expense. Northern Border Pipeline expects to amortize approximately $2.2
million as a reduction of interest expense in 2005 for these agreements.
At December 31, 2003, the average effective interest rate on Northern
Border Pipeline's interest rate swap agreements was 2.31%. Northern Border
Pipeline's interest rate swap agreements were designated as fair value
hedges as they were entered into to hedge the fluctuations in the market
value of the 2002 Pipeline Senior Notes. The accompanying balance sheet at
December 31, 2003, reflects an unrealized gain of approximately $16.6
million in derivative financial assets with a corresponding increase in
long-term debt.
7. COMMITMENTS AND CONTINGENCIES
Operating Leases
Future minimum lease payments under non-cancelable operating leases on
office space and rights-of-way are as follows (in thousands):
Year ending December 31,
- ------------------------
2005 $ 2,392
2006 2,392
2007 2,392
2008 2,392
2009 2,392
Thereafter 66,385
-------
$78,345
=======
Expenses incurred related to these lease obligations for the years ended
December 31, 2004, 2003 and 2002, were $0.6 million, $0.7 million, and
$0.1 million, respectively.
Cash Balance Plan
As further discussed in Note 11, on December 31, 2003, Enron filed a
motion seeking approval of the Bankruptcy Court to provide additional
funding to, and for authority to terminate the Enron Corp. Cash Balance
Plan and certain other defined benefit plans. Northern Border Pipeline
recorded estimated charges associated with the termination of the cash
balance plan of $3.1 million in 2003. In 2004, Northern Border Pipeline
reduced its expense by $3.1 million, since it determined it is no longer
liable for termination costs of the Cash Balance Plan (see Note 11).
F-14
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
7. COMMITMENTS AND CONTINGENCIES (continued)
Capital Expenditures
Total capital expenditures for 2005 are estimated to be $40 million. Funds
required to meet the capital expenditures for 2005 are anticipated to be
provided primarily by borrowings under the 2002 Pipeline Credit Agreement
or similar facilities and operating cash flows.
Environmental Matters
Northern Border Pipeline is not aware of any material contingent
liabilities with respect to compliance with applicable environmental laws
and regulations.
Other
On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian
Reservation (Tribes) filed a lawsuit in Tribal Court against Northern
Border Pipeline to collect more than $3 million in back taxes, together
with interest and penalties. The lawsuit 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 (Agreement) executed in August
2004. Through the terms of the Agreement, 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 intends to
seek regulatory recovery from the settlement in its upcoming rate case.
Various legal actions that have arisen in the ordinary course of business
are pending. Northern Border Pipeline believes that the resolution of
these issues will not have a material adverse impact on Northern Border
Pipeline's results of operations or financial position.
8. 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
F-15
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENT
8. CASH DISTRIBUTION POLICY (Continued)
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. Effective January 1, 2008, the cash distribution
policy will be adjusted to maintain a consistent capital structure. 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 fron $90 million to $15 million.
9. QUARTERLY FINANCIAL DATA (Unaudited)
Operating Operating Net Income
(In thousands) Revenues Income to Partners
- -------------------- --------- --------- -----------
2004
First Quarter $ 83,307 $ 51,819 $ 41,757
Second Quarter 81,532 50,836 41,297
Third Quarter 81,609 47,894 37,580
Fourth Quarter 82,667 57,060 46,143
2003
First Quarter $ 79,892 $ 48,639 $ 36,734
Second Quarter 80,659 48,915 37,617
Third Quarter 81,192 48,050 37,195
Fourth Quarter 82,442 47,377 36,654
10. OTHER INCOME (EXPENSE)
Other income (expense) on the statement of income includes such items as
investment income, nonoperating revenues and expenses, and nonrecurring
other income and expense items. For the years ended December 31, 2004,
2003 and 2002, other income included income from interconnections
constructed of $0.7 million, $0.1 million and $0.1 million, respectively.
Other income for 2004 also included an adjustment to reserves previously
established of $0.4 million. Other expense for the year ended December 31,
2004, included approximately $0.6 million due to reserves established for
costs associated with a potential future project and $0.5 million of bad
debt expense. For the year ended December 31, 2003, other expense included
$0.6 million for a repayment of amounts previously received for vacated
microwave frequency bands. For the year ended December 31, 2002, other
income included $0.6 million for amounts received for previously vacated
microwave frequency bands.
11. RELATIONSHIPS WITH ENRON
In December 2001, Enron and certain of its subsidiaries filed voluntary
petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court.
Until November 17, 2004, Northern Plains and Pan Border were subsidiaries
of Enron. Northern Plains and Pan Border were not among the Enron
companies filing for Chapter 11 protection.
Enron North America (ENA), a wholly owned subsidiary of Enron that is in
bankruptcy, was a party to transportation contracts which obligated ENA to
pay for 3.5% of Northern Border Pipeline's capacity. Through the
bankruptcy proceeding in 2002, ENA rejected and terminated all of its firm
transportation contracts on Northern Border Pipeline. Northern Border
Pipeline had previously fully reserved for amounts invoiced to ENA. Since
Enron guaranteed the obligations of ENA under those contracts, Northern
Border
F-16
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENT
11. RELATIONSHIPS WITH ENRON (continued)
Pipeline filed claims against both ENA and Enron for damages in the
bankruptcy proceedings. As a result of a settlement agreement between ENA,
Enron and Northern Border Pipeline, each of ENA and Enron have agreed to
allow Northern Border Pipeline's claim of approximately $20.6 million. The
settlement agreement is expected to be presented to the Bankruptcy Court
for approval in March 2005. Based upon this settlement between the
parties, at December 31, 2004, Northern Border Pipeline adjusted its
allowance for doubtful accounts to reflect an estimated recovery of $1.1
million for these claims.
Northern Border Pipeline estimates that it could recognize, through future
operating results, additional recoveries of $6 million to $9 million for
the claims in the Enron bankruptcy proceedings. However, there can be no
assurances on the amounts actually recovered or timing of distributions
under the Chapter 11 Plan.
On December 31, 2003, Enron filed a motion seeking approval of the
Bankruptcy Court to provide additional funding to, and for authority to
terminate the Enron Corp. Cash Balance Plan (Plan) and certain other
defined benefit plans of Enron's affiliates in `standard terminations'
within the meaning of Section 4041 of the Employee Retirement Income
Security Act of 1974, as amended (ERISA). Such standard terminations would
satisfy all of the obligations of Enron and its affiliates with respect to
funding liabilities under the Plan. In addition, a standard termination
would eliminate the contingent claims of Pension Benefit Guaranty
Corporation (PBGC) against Enron and its affiliates with respect to
funding liabilities under the Plan. On January 30, 2004, the Bankruptcy
Court entered an order authorizing termination, additional funding and
other actions necessary to effect the relief requested. Pursuant to the
Bankruptcy Court order, any contributions to the Plan are subject to the
prior receipt of a favorable determination by the Internal Revenue Service
that the Plan is tax-qualified as of the date of termination.
On July 19, 2004, Enron was served with a complaint filed by the PBGC in
the District Court for the Southern District of Texas against Enron as the
sponsor and/or administrator of the Plans (the Action). By filing the
Action, the PBGC is seeking an order (i) terminating the Plans; (ii)
appointing the PBGC the statutory trustee of the Plans; (iii) requiring
transfer to the PBGC of all records, assets or other property of the Plans
required to determine the benefits payable to the Plans' participants; and
(iv) establishing June 3, 2004 as the termination date of the Plans. In
the Bankruptcy Court September 10 Order, Enron was authorized to enter
into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron
deposited the amount of $321.8 million to an escrow account, which is
intended to ensure that none of CCE Holdings or its affiliates are exposed
to liability to the PBGC under Title IV of the Employee Retirement Income
Security Act of 1974, as amended, for which CCE Holdings may otherwise be
indemnified pursuant to the CCE Holdings Agreement. In addition, the form
of escrow agreement approved pursuant to the September 10 Order provides
that, under certain circumstances and upon approval by or notice to the
parties to the escrow agreement, some or all of the funds placed in escrow
may be paid directly in respect of the Cash Balance Plan or to the PBGC.
However, the September 10 Order also provides that PBGC retains any rights
or claims it may have against the Transfer Group Companies.
F-17
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENT
11. RELATIONSHIPS WITH ENRON (continued)
Enron management previously informed Northern Plains that Enron would seek
funding contributions from each member of its ERISA controlled group of
corporations that employs, or employed, individuals who are, or were,
covered under the Cash Balance Plan. Northern Plains is considered a
member of Enron's ERISA controlled group of corporations. As of December
31, 2003, approximately $3.1 million was estimated for Northern Border
Pipeline's proportionate allocation of Northern Plains' 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, these costs could be the Northern Border
Pipeline's responsibility, $3.1 million was accrued 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 advised Northern
Border Pipeline that no claim of reimbursement of the termination costs
will be made, resulting in an adjustment in reserves during 2004 of $3.1
million for the termination costs. Under the ONEOK Agreement, neither
Northern Plains nor Northern Border Pipeline will be required to
contribute to or otherwise be liable for any contributions to Enron in
connection with the Cash Balance Plan. The purchase price under the
agreements will be deemed to include all contributions which otherwise
would have been allocable to Northern Plains.
Northern Border Pipeline continues to monitor developments at Enron, to
assess the impact on Northern Border Pipeline of its existing agreements
and relationships with Enron, and to take appropriate action to protect
Northern Border Pipeline's interests.
12. SUBSEQUENT EVENTS
Northern Border Pipeline makes distributions to it general partners
approximately one month following the end of the quarter. The distribution
for the fourth quarter of 2004 of approximately $54.1 million was declared
in January 2005 was paid in February 2005.
F-18
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE
Northern Border Pipeline Company:
We have audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the financial statements of Northern
Border Pipeline Company as of December 31, 2004 and 2003 and for each of the
years in the three-year period ended December 31, 2004 included in this Form
10-K, and have issued our report thereon dated March 2, 2005.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule of Northern Border Pipeline
Company listed in Item 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.
/s/ KPMG LLP
Omaha, Nebraska
March 2, 2005
S-1
SCHEDULE II
NORTHERN BORDER PIPELINE COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(IN THOUSANDS)
Column A Column B Column C Column D Column E
- ----------------------------------------------------------------------------------------
Additions
--------------------- Deductions
Balance at Charged to Charged For Purpose For
Beginning Costs and to Other Which Reserves Balance at
Description of Year Expenses Accounts Were Created End of Year
- ------------------- ---------- ---------- -------- --------------- -----------
Reserve for
regulatory issues
2004 $ 6,315 $ 640 $ -- $ 5,000 $ 1,955
2003 $12,294 $4,282 $ -- $10,261 $ 6,315
2002 $ 2,531 $9,763 $ -- $ -- $12,294
Allowance for
doubtful accounts
2004 $ 4,815 $ 523 $ -- $ 1,130 $ 4,208
2003 $ 4,805 $ 10 $ -- $ -- $ 4,815
2002 $ 3,176 $3,452 $ -- $ 1,823 $ 4,805
S-2
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
- ----------- -----------
* 3.1 Northern Border Pipeline Company General Partnership Agreement
between Northern Plains Natural Gas Company, Northwest Border
Pipeline Company, Pan Border Gas Company, TransCanada Border
Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978,
as amended (incorporated by reference to Exhibit 10.2 to Northern
Border Partners, L.P.'s Form S-1, SEC File No. 33-66158 ("Form
S-1")).
* 3.2 Seventh Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (incorporated by reference to Exhibit 10.15 to
Form S-1).
* 3.3 Eighth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (incorporated by reference to Exhibit 10.15 to
Northern Border Pipeline Company's Form s-4 Registration Statement,
filed on October 7, 1999, Registration No. 333-88577 ("Form S-4").
* 3.4 Ninth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (incorporated by reference to Exhibit 10.37 to
Northern Border Pipeline Company's Registration Statement on Form
S-4, filed on November 13, 2001, Registration No. 333-73282 ("2001
Form S-4").
3.5 Tenth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement dated March 3, 2005.
* 4.1 Indenture, dated as of August 17, 1999, between Northern Border
Pipeline Company and Bank One Trust Company, NA, successor to The
First National Bank of Chicago, as trustee (incorporated by
reference to Exhibit 4.1 to Form S-4).
* 4.2 Indenture, dated as of September 17, 2001, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (incorporated by
reference to Exhibit 4.2 to 2001 Form S-4).
* 4.3 Indenture, dated as of April 29, 2002, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (incorporated by
reference to Exhibit 4.1 to Northern Border Pipeline Company's Form
10-Q for the quarter ended March 31, 2002) (Filed No. 333-88577).
* 10.1 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).
* 10.2 Revolving Credit Agreement, dated as of May 16, 2002, among Northern
Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank of
Montreal, SunTrust Bank, Wachovia Bank, National Association, Banc
One Capital Markets, Inc, and Lenders (as defined therein)
(incorporated by reference to Exhibit 10.1 to Northern Border
Partners, L.P.'s Current Report on Form 8-K dated June 26, 2002
(File No. 1-12202)).
* 10.3 First Amendment to the Revolving Credit Agreement dated as of April
9, 2004 between Northern Border Pipeline Company, Bank
One, NA and the lenders named therein. (incorporated by reference to
Exhibit No. 10.1 to Northern Border Pipeline Company Quarterly
Report on Form 10-Q for the quarterly period ended March 31, 2004
(File No. 333-88577)).
* 10.4 Form of Conveyance, Contribution and Assumption Agreement among
Northern Plains Natural Gas Company, Northwest Border Pipeline
Company, Pan Border Gas Company, Northern Border Partners, L.P., and
Northern Border Intermediate Limited Partnership (incorporated by
reference to Exhibit 10.16 to Form S-1).
* 10.5 Form of Contribution, Conveyance and Assumption Agreement among TC
PipeLines, LP and certain other parties. (incorporated by reference
to Exhibit 10.2 to TC PipeLines, LP's Form S-1, SEC File No.
333-69947 ("TC Form S-1")).
+*10.6 Form of Termination Agreement with ONEOK dated as of January 5,
2005. (incorporated by reference to Exhibit 99.1 to Northern Border
Partners, L.P. Form 8-K filed on January 11, 2005 (File No.
1-12201)).
+*10.7 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan.
(incorporated by reference to Exhibit 99.1 to Northern Border
Partners, L.P. Form 8-K filed on January 11, 2005 (File No.
1-12201)).
+*10.8 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from
Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31,
2001 (File No. 1-13643)).
+*10.9 ONEOK, Inc. Form of Restricted Stock Incentive Award (incorporated
by reference from Exhibit 10.4 to ONEOK's Form 10-Q for the
quarterly period ended September 30, 2004 (File No. 1-13643)).
+*10.10 ONEOK, Inc. Form of Performance Shares Award (incorporated by
reference from Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly
period ended September 30, 2004 (File No. 1-13643)).
+*10.11 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as
amended, dated February 2001 (incorporated by reference from Exhibit
10(g) to ONEOK's Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
+*10.12 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference
from Exhibit 10(f) to Form 10-K for the year ended December 31, 2001
(File No. 1-13643)).
*10.13 Northern Border Pipeline Company Agreement among Northern Plains
Natural Gas Company, Pan Border Gas Company, Northwest Border
Pipeline Company, TransCanada Border PipeLine Ltd., TransCan
Northern Ltd., Northern Border Intermediate Limited Partnership,
Northern Border Partners, L.P., and the Management Committee of
Northern Border Pipeline, dated as of March 17, 1999 (incorporated
by reference to Exhibit 10.21 to Northern Border Partners, L.P.'s
Form 10-K/A for the year ended December 31, 1998 File No. 1-12202
("1998 10-K")).
*10.14 Northern Border Transition Services Agreement dated November 17,
2004, by and between ONEOK, Inc. and CCE Holdings, LLC.
(incorporated by reference to Exhibit 10.24 to Northern Border
Partners, L.P.'s Form 10-K for the year ended December 31, 2004
(File No. 1-122022)).
12. Statement re computation of ratios.
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 Northern Border Partners, L.P.'s
Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern
Border Partners, L.P.'s Registration No. 333-72696).
*Indicates exhibits incorporated by reference as indicated; all other exhibits
are filed herewith.
+ Management contract, compensatory plan or arrangement.