Item 1. Business
General
Northern Border Pipeline Company is a general partnership formed in 1978. The general partners are Northern Border Partners, L.P. and TC PipeLines, LP, both of which are publicly traded partnerships. Each of Northern Border Partners and TC PipeLines holds its interest in us, 70% and 30% of voting power, respectively, through a subsidiary limited partnership. The general partners of Northern Border Partners and its subsidiary limited partnership are Northern Plains Natural Gas Company and Pan Border Gas Company, both subsidiaries of Enron Corp., and Northwest Border Pipeline Company, a subsidiary of The Williams Companies, Inc. The general partner of TC PipeLines and its subsidiary limited partnership is TC PipeLines GP, Inc., a subsidiary of TransCanada PipeLines Limited.
We own an interstate pipeline system that transports natural gas from the Montana-Saskatchewan border to natural gas markets in the midwestern United States. This pipeline system connects with multiple pipelines that provide shippers with access to the various natural gas markets served by those pipelines. In the year ended December 31, 2000, 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 90% 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 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. Northern Border Pipeline does not own the gas that it transports, and therefore it does not assume the related natural gas commodity risk.
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; one representative is designated by TC PipeLines. Voting power on the management committee is presently allocated among Northern Border Partners' three representatives in proportion to their general partner interests in Northern Border Partners. As a result, the 70% voting power of Northern Border Partners' three representatives on the management committee is allocated as follows: 35% to the representative designated by Northern Plains, 22.75% to the representative designated by Pan Border and 12.25% to the representative designated by Northwest Border. Northern Plains and Pan Border are subsidiaries of Enron Corp. Therefore, Enron controls 57.75% of the voting power of the management committee and has the right to select two of the members of the management committee. For a discussion of specific relationships with affiliates, refer to Item 13. "Certain Relationships and Related Transactions."
Our pipeline system is operated by Northern Plains pursuant to an operating agreement. As of December 31, 2000, Northern Plains employed approximately 200 individuals located at the operating headquarters in Omaha, Nebraska, and at various locations along the pipeline route. 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 1,214-mile United States interstate pipeline system that transports natural gas from the Montana- Saskatchewan border near Port of Morgan, Montana, to interconnecting pipelines in the upper Midwest of the United States. Construction of the pipeline was initially completed in 1982. The pipeline system was expanded and/or extended in 1991, 1992 and 1998.
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, as well as the Williston Basin in the United States. Our pipeline system also has access to synthetic gas produced at the Dakota Gasification plant in North Dakota. For the year ended December 31, 2000, of the natural gas transported on the system, approximately 90% was produced in Canada, approximately 5% was produced by the Dakota Gasification plant, and approximately 5% was produced in the Williston Basin.
Our pipeline system consists of 822 miles of 42-inch diameter pipe designed to transport 2,373 million cubic feet per day ("mmcfd") from the Canadian border to Ventura, Iowa; 30-inch diameter pipe and 36-inch diameter pipe, each approximately 147 miles in length, designed to transport 1,300 mmcfd in total from Ventura, Iowa to Harper, Iowa; and 226 miles of 36-inch diameter pipe and 19 miles of 30-inch diameter pipe designed to transport 645 mmcfd from Harper, Iowa to a terminus near Manhattan, Illinois (Chicago area). Along the pipeline there are 15 compressor stations with total rated horsepower of 476,500 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 51 tower sites.
At its northern end, our pipeline system is connected to TransCanada's majority-owned Foothills Pipe Lines (Sask.) Ltd. system in Canada, which is connected to TransCanada's Alberta system and the pipeline system owned by Transgas Limited in Saskatchewan. The Alberta system gathers and transports approximately 18% of the total North American natural gas production and approximately 74% of the natural gas produced in the western Canadian sedimentary basin. The pipeline system also connects with facilities of Williston Basin Interstate Pipeline at Glen Ullin and Buford, North Dakota, facilities of Amerada Hess Corporation at Watford City, North Dakota and facilities of Dakota Gasification Company at Hebron, North Dakota in the northern portion of the pipeline system.
Interconnects
Our pipeline system connects with multiple pipelines that provide our shippers with access to the various natural gas markets served by those pipelines. The pipeline system interconnects with pipeline facilities of:
* Northern Natural Gas Company, an Enron subsidiary, at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa;
* Natural Gas Pipeline Company of America at Harper, Iowa;
* MidAmerican Energy Company at Iowa City and Davenport, Iowa and Cordova, Illinois;
* Alliant Power Company at Prophetstown, Illinois;
* Northern Illinois Gas Company at Troy Grove and Minooka, Illinois;
* Midwestern Gas Transmission Company near Channahon, Illinois;
* ANR Pipeline Company near Manhattan, Illinois; and
* The Peoples Gas Light and Coke Company near Manhattan, Illinois at the terminus of the pipeline system.
The Ventura, Iowa interconnect with Northern Natural Gas Company functions as a large market center, where natural gas transported on the pipeline system is sold, traded and received for transport to significant consuming markets in the Midwest and to interconnecting pipeline facilities destined for other markets.
Shippers
Our pipeline system serves more than 50 firm transportation shippers with diverse operating and financial profiles. Based upon shippers' contractual obligations, as of December 31, 2000, 92% of the firm capacity is contracted by producers and marketers. The remaining firm capacity is contracted to local distribution companies (5%), interstate pipelines (2%) and end-users (1%). As of December 31, 2000, the termination dates of these contracts ranged from October 31, 2001 to December 21, 2013 and the weighted average contract life, based upon annual contractual obligations, was approximately six years with just under 99% of capacity contracted through mid-September 2003.
Based on their proportionate shares of capacity, as of December 31, 2000, the five largest shippers are: Pan- Alberta Gas (U.S.) Inc. (25.5%), TransCanada Energy Marketing USA, Inc. (11.4%), PanCanadian Energy Services Inc (7.3%), Enron North America Corp. (6.3%) and Engage Energy US, LP. (5.4%). The 20 largest shippers, in total, are responsible for approximately 93% of total revenues.
As of December 31, 2000, our largest shipper, Pan- Alberta, holds firm capacity of 690 mmcfd under three contracts with terms to October 31, 2003. An affiliate of Enron provides guaranties for 300 mmcfd of Pan-Alberta's contractual obligations through October 31, 2001. In addition, Pan-Alberta's remaining capacity is supported by various credit support arrangements, including, among others, a letter of credit, a guaranty from an interstate pipeline company through October 31, 2001 for 132 mmcfd, an escrow account and an upstream capacity transfer agreement. Mirant Americas Energy Marketing, LP., formerly Southern Company Energy Marketing L.P. manages the assets of Pan- Alberta Gas, Ltd., which include Pan-Alberta's contracts with us.
Some of our shippers are affiliated with the general partners of Northern Border Partners and TC PipeLines. TransCanada Energy Marketing USA, Inc., a subsidiary of TransCanada, holds firm contracts representing 11.4% of capacity. Enron North America Corp., a subsidiary of Enron, holds firm contracts representing 6.3% of capacity. Transcontinental Gas Pipe Line Corporation, a subsidiary of Williams, holds a contract representing 0.8% of capacity. See Item 13. "Certain Relationships and Related Transactions."
Demand For Transportation Capacity
Our long-term financial condition is dependent on the continued availability of economic western Canadian natural gas for import into the United States. Natural gas reserves may require significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with the pipeline system. Low prices for natural gas, 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. Additional pipeline export capacity also could accelerate depletion of these reserves.
Our business depends in part on the level of demand for western Canadian 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 western Canadian natural gas and use of our pipeline system. Demand for western Canadian 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 our pipeline serves.
A variety of factors could affect the demand for natural gas in the markets that our pipeline system serves. These factors include:
* economic conditions;
* fuel conservation measures;
* alternative energy requirements and prices;
* climatic conditions;
* government regulation; and
* technological advances in fuel economy and energy generation devices.
We cannot predict whether these or other factors will have an adverse effect on demand for use of our pipeline system or how significant that adverse effect could be.
Future Demand and Competition
On March 16, 2000, the FERC issued an order granting our application for a certificate to construct and operate our proposed Project 2000 facilities. Project 2000 will expand and extend the pipeline system into Indiana. Project 2000 will afford shippers on our extended pipeline system access to industrial gas consumers in northern Indiana through an interconnect with Northern Indiana Public Service Company, a major midwest local distribution company, at the terminus near North Hayden, Indiana.
The capital expenditures for Project 2000 are estimated to be approximately $94 million with a planned in-service of November 2001. Proposed facilities include approximately 34.4 miles of 30-inch pipeline, new equipment and modifications at three compressor stations resulting in a net increase of 22,500 compressor horsepower, and one meter station.
As a result of the Project 2000 expansion, our pipeline system will have the ability to transport 1,484 mmcfd from Ventura to Harper, Iowa, 844 mmcfd from Harper to Manhattan, Illinois, and 544 mmcfd on the new extension from Manhattan to North Hayden, Indiana. Five shippers have contracted for all the additional capacity under long-term transportation agreements.
The Project 2000 shippers are: Bethlehem Steel Corporation, El Paso Energy Marketing Company, Northern Indiana Public Service Company, Peoples Energy Services Corporation and The Peoples Gas Light and Coke Company.
We compete with other pipeline companies that transport natural gas from the western Canadian sedimentary basin or that transport natural gas to markets in the midwestern United States. The competitors for the supply of natural gas include six pipelines and the Canadian domestic users in the western Canadian sedimentary basin region. Our competitive position is affected by the availability of Canadian natural gas for export, the prices of natural gas in alternative markets, the cost of producing natural gas in Canada, and demand for natural gas in the United States.
Alliance Pipeline, which commenced transporting natural gas from the western Canadian sedimentary basin to the midwestern United States in December 2000, delivers its volumes into the Chicago market and other interstate pipelines. Alliance Pipeline transports for its shippers gas containing high-energy liquid hydrocarbons. Additional facilities to extract the natural gas liquids were constructed near Alliance Pipeline's terminus in Chicago to permit Alliance to transport natural gas with the liquids- rich element.
As a consequence of Alliance Pipeline, there has been an increase in natural gas moving from the western Canadian sedimentary basin to Chicago. Vector Pipeline L.P. interconnects with Alliance and transports gas eastward to a terminus in eastern Canada. There are several additional projects proposed to transport natural gas from the Chicago area that would provide access to additional markets for the shippers. The proposed projects currently being pursued by third parties are targeting markets in northern Illinois, Wisconsin and the northeast United States. These proposed projects are in various stages of regulatory approval.
Williams has a minority interest (14.6%) in Alliance Pipeline. TransCanada and other unaffiliated companies own and operate pipeline systems that transport natural gas from the same natural gas reserves in western Canada that supply our customers.
Natural gas is also produced in the United States and transported by competing pipeline systems to the same destinations as the pipeline system.
FERC Regulation
General
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 the 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 the facilities, activities and services. Under Section 8 of the Natural Gas Act, the FERC has the power to prescribe the accounting treatment for items for regulatory purposes. Our books and records are periodically audited under Section 8.
The FERC regulates the rates and charges for transportation in interstate commerce. Natural gas companies may not charge rates exceeding rates judged just and reasonable by the FERC. 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.
Rate Case Proceeding
In May 1999, we filed a rate case wherein we proposed, among other things, to increase the allowed equity rate of return to 15.25%. The total annual cost of service increase due to the proposed changes was approximately $30 million. A number of the shippers and competing pipelines filed interventions and protests. In June 1999, the FERC issued an order in which the proposed changes were suspended until December 1, 1999, after which they were implemented with subsequent billings subject to refund. The order set for hearing not only the proposed changes but also several issues raised by intervenors including the appropriateness of the cost of service form of tariff and the depreciation schedule. Upon a request for clarification, the FERC issued an order in August 1999 that provided that the manner in which the costs of the recently completed expansion and extension project ("The Chicago Project") could be recovered from shippers may be examined in this proceeding and that, while we had not proposed to change the depreciation rates approved in the last rate case, we had the burden of proving that the depreciation rates are just and reasonable.
On September 26, 2000, we filed a stipulation and agreement in our 1999 rate case proceeding that documented a settlement. On December 13, 2000, the FERC issued its order approving the terms of the settlement. One of the important elements of the settlement is the conversion of our form of tariff from cost of service to stated rates based on a straight-fixed variable rate design. Under the former cost of service tariff, the firm transportation shippers contracted to pay for a proportionate share of our pipeline system's cost of service. During any given month, each of these shippers paid a uniform mileage-based charge for the amount of capacity contracted, and calculated under a cost of service tariff. The shippers were obligated to pay their proportionate share of the cost of service regardless of the amount of natural gas they actually transported. Under the cost of service form of tariff, we could not charge or collect more than the cost of service. Under our new form of tariff, shippers pay us on the basis of stated transportation rates. Under the terms of the settlement, and in accordance with straight-fixed variable rate design principles, approximately 98% of the agreed upon revenue level is attributed to demand charges. The firm shippers are obligated to pay a monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. The remaining 2% of the agreed upon revenue level is attributed to the commodity charge based on the volumes of gas actually transported. From December 1, 1999, through and including December 31, 2000, the rates were based upon an annual revenue level of $307 million. For periods after December 31, 2000, the rates are based upon an annual revenue level of $305 million. On a per unit of transportation basis, the rates under the new tariff are approximately equal to the cost of service on a per unit basis charged prior to December 1, 1999. The settlement also provides that neither we nor our existing shippers can seek rate changes until November 1, 2005, at which time we must file a new rate case. Prior to the new rate case, we will not be permitted to increase rates if our costs increase, nor will we be required to reduce rates based on cost savings. Our earnings and cash flow will depend on our future costs, contracted capacity, the volumes of gas transported and our ability to recontract capacity at acceptable rates.
Under our previous cost of service form of tariff, the amount of revenue that we collected from customers generally declined as the rate base was recovered. Under our new tariff, we are entitled to collect revenue based on stated rates established in our 1999 rate case until our next rate case, which will be filed November 1, 2005. We will, however, continue to depreciate our rate base at an annual depreciation rate on transmission plant in service of 2.25% and our rate base in 2005 will be a factor in determining what we can charge when we file a new rate case at that time. In order to avoid a decline in revenue we can collect from our customers, we must maintain or increase our rate base by acquiring or constructing assets that replace or add to existing pipeline facilities or by adding new facilities and maintain our level of contracted capacity at the stated rates.
It was agreed in the settlement of the 1999 rate case, that there would be no project cost containment mechanism adjustment for The Chicago Project and that all costs as of November 30, 1999 incurred in the construction and commissioning of The Chicago Project be included in rate base. The project cost containment mechanism was created in the settlement of the 1995 rate case. The purpose of the project cost containment mechanism was to limit our ability to include cost overruns for The Chicago Project in rate base and to provide incentives for cost underruns.
The settlement of our 1995 rate case provided that for at least seven years from the date The Chicago Project was completed, we could continue to calculate the allowance for income taxes in the manner we had historically used. In addition, a settlement adjustment mechanism of $31 million was implemented, which effectively reduces the return on rate base. These provisions of the 1995 rate case were maintained in the settlement of our 1999 rate case.
We also provide interruptible transportation service. Interruptible transportation service is transportation in circumstances when surplus capacity is available after satisfying firm service requests. The maximum rate that may be charged to interruptible shippers is calculated as the sum of the firm transportation Rate Schedule T-1 maximum reservation charge and commodity rate. Under our previous cost of service form of tariff, all interruptible transportation service revenue generated was credited to the benefit of the firm shippers. Under our new tariff, we share net interruptible transportation service revenue and any new services revenue on an equal basis with our firm shippers through October 31, 2003. In addition, we are permitted to retain revenue from interruptible transportation service to offset any decontracted firm capacity.
After October 31, 2003, all revenues from interruptible transportation service and other new services will no longer be subject to sharing and thus will be retained by us. In addition, the settlement of the 1999 rate case also provided for an equal sharing with our firm shippers of revenue generated from a certain telecommunications contract for the term of that contract. We intend to develop new services and seek the FERC's authorization to implement such services. While the receipt of those approvals and the future impact of the revenue sharing provisions of the settlement on our earnings cannot be determined at this time, revenues from these sources are expected to be minimal through at least October 31, 2003.
Open access regulation
Beginning on April 8, 1992, the FERC issued a series of orders, known as Order 636, which required pipeline companies to unbundle their services and offer sales, transportation, storage, gathering and other services separately, to provide all transportation services on a basis that is equal in quality for all shippers and to implement a program to allow firm holders of pipeline capacity to resell or release their capacity to other shippers. Capacity release provisions were adopted that allowed shippers to release all or part of their capacity either permanently or temporarily. Shippers on our pipeline system have temporarily released capacity as well as permanently released capacity to other shippers who have agreed to comply with the underlying contractual and regulatory obligations associated with that capacity.
Beginning in 1996, the FERC issued a series of orders, referred to together as Order 587, amending its open access regulations to standardize business practices and procedures governing transactions between interstate natural gas pipelines, their customers, and others doing business with the pipelines. The intent of Order 587 was to assist shippers that deal with more than one pipeline by establishing standardized business practices and procedures. These business standards, developed by the Gas Industry Standards Board, govern important business practices including shipper supplied service nominations, allocation of available capacity, accounting and invoicing of transportation service, standardized internet business transactions and capacity release. We have implemented the necessary changes to our tariff and internal systems.
In 1998, the FERC initiated a number of proceedings to further amend its open access regulations. In the resulting order, Order 637 issued February 9, 2000, the FERC revised the short-term transportation regulations by 1) waiving the maximum rate ceiling in its capacity release regulations until September 30, 2002 for short-term releases of capacity of less than one year; 2) permitting value-oriented peak/off- peak rates to better allocate revenue responsibility between short-term and long-term markets; 3) permitting term- differentiated rates to better allocate risks between shippers and the pipelines; 4) revising the regulations related to scheduling procedures, capacity segmentation, imbalance management and penalties; 5) retaining the right of first refusal and the five-year matching cap but limiting the right to customers with maximum rate contracts for 12 or more consecutive months of service; and 6) adopting new reporting requirements to take effect September 1, 2000 that include reporting daily transactional data on all firm and interruptible contracts, daily reporting of scheduled quantities at points or segments, and the posting of corporate and pipeline organizational charts, names and functions. As required by Order No. 637, we filed pro forma tariff sheets in compliance to address the issues identified in 4) above. This filing is pending at the FERC. All other related compliance filings and reporting requirements have been completed and implemented.
We do not believe that these regulatory initiatives will have a material adverse impact to our operations.
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, and the Pipeline Safety Act of 1992.
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 increasingly strict environmental and safety laws, regulations and enforcement policies thereunder, 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.
Item 2. Properties
We hold the right, title and interest in our pipeline system. With respect to real property, our pipeline system falls into two basic categories: (a) parcels which we own in fee, such as certain of the compressor stations, meter stations, pipeline field office sites, and microwave tower sites; and (b) parcels where our 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 our pipeline system. The right to construct and operate our pipeline across certain property was obtained by us through exercise of the power of eminent domain. We continue to have the power of eminent domain in each of the states in which it operates our pipeline system, although we may not have the power of eminent domain with respect to Native American tribal lands.
Approximately 90 miles of our pipeline is located on fee, allotted and tribal lands within the exterior boundaries of the Fort Peck Indian Reservation in Montana. Tribal lands are lands owned in trust by the United States for the Fort Peck Tribes and allotted lands are lands owned in trust by the United States for an individual Indian or Indians. We do have the right of eminent domain with respect to allotted lands.
In 1980, we entered into a pipeline right-of-way lease with the Fort Peck Tribal Executive Board, for and on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation. 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 lease expires in 2011.
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. This right-of-way on allotted lands is either a perpetual easement or for a term of years. Most of the allotted lands are subject to a perpetual easement either granted, by the Bureau of Indian Affairs 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.
Item 3.
Item 3. Legal Proceedings
We are not currently parties to any legal proceedings that, individually or in the aggregate, would reasonably be expected to have a material adverse impact on our results of operations or financial position.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during 2000.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
The general partnership interests of Northern Border Pipeline Company are not traded in an established public market. See Item 12. "Security Ownership of Certain Beneficial Owners and Management".
The payment of distributions to our general partners is restricted under the terms of the 1997 Pipeline Credit Agreement and the 1992 Senior Notes. See Note 5, "Credit Facilities and Long-Term Debt", in the Notes to Financial Statements referred to in Item 8. "Financial Statements and Supplementary Data". Under the most restrictive covenants, approximately $136 million of partners' capital could be distributed as of December 31, 2000.
Item 6.
Item 6. Selected Financial Data (in thousands, except other financial and operating data)
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
Year Ended December 31, 2000 Compared With the Year Ended December 31, 1999
Operating revenues, net for the year ended December 31, 2000 were $311.0 million as compared to $298.3 million for the same period in 1999, an increase of $12.7 million (4%). Our net operating revenues for 2000 reflect the significant terms of the rate case settlement discussed in Item 1. "Business - Rate Case Proceeding". Operating revenues for 1999 were determined under Northern Border Pipeline's cost of service tariff.
Operations and maintenance expense increased $2.8 million (7%) for the year ended December 31, 2000, from the same period in 1999, due primarily to increased employee payroll and benefit expenses and costs to operate our two electric-powered compressor units.
Depreciation and amortization expense increased $5.4 million (10%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to an increase in the depreciation rate applied to transmission plant. As a result of the rate case settlement, we used a depreciation rate for transmission plant of 2.25% for 2000. We had used a depreciation rate of 2.0% for 1999.
Taxes other than income decreased $2.3 million (8%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to adjustments to previous estimates of ad valorem taxes.
Interest expense, net increased $4.9 million (8%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to an increase in average interest rates between 1999 and 2000. The impact of the increase in interest rates was partially offset by a decrease in average debt outstanding.
Other income increased $6.7 million (491%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to a reduction in reserves previously established for regulatory issues as the result of the settlement of our rate case.
Year Ended December 31, 1999 Compared With the Year Ended December 31, 1998
Operating revenues, net increased $101.7 million (52%) for the year ended December 31, 1999, as compared to the same period in 1998, due primarily to additional revenue from the operation of The Chicago Project facilities. Additional receipt capacity of 700 mmcfd, a 42% increase, and new firm transportation agreements with 27 shippers resulted from The Chicago Project. Our cost of service tariff provided an opportunity to recover operations and maintenance costs of the pipeline, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated return on equity. We were generally allowed an opportunity to collect from our shippers a return on unrecovered rate base as well as recover that rate base through depreciation and amortization. The Chicago Project increased our rate base, which increased return for the year ended December 31, 1999. Also reflected in the increase in 1999 revenues are recoveries of increased pipeline operating expenses due to the new facilities.
Operations and maintenance expense increased $9.3 million (31%) for the year ended December 31, 1999, from the same period in 1998, due primarily to operations and maintenance expenses for The Chicago Project facilities and increased employee payroll and benefit expenses.
Depreciation and amortization expense increased $10.9 million (27%) for the year ended December 31, 1999, as compared to the same period in 1998, due primarily to The Chicago Project facilities placed into service. The impact of the additional facilities on depreciation and amortization expense was partially offset by a decrease in the depreciation rate applied to transmission plant from 2.5% to 2.0%. We agreed to reduce the depreciation rate at the time The Chicago Project was placed into service as part of a previous rate case settlement.
Taxes other than income increased $8.9 million (42%) for the year ended December 31, 1999, as compared to the same period in 1998, due primarily to ad valorem taxes attributable to the facilities placed into service for The Chicago Project.
For the year ended December 31, 1998, we recorded a regulatory credit of $8.9 million. During the construction of The Chicago Project, we placed new facilities into service in advance of the December 1998 project in-service date to maintain gas flow at firm contracted capacity while existing facilities were being modified. The regulatory credit deferred the cost of service of these new facilities, which we began to recover from our shippers commencing with the in-service date of The Chicago Project.
Interest expense, net increased $34.7 million (136%) for the year ended December 31, 1999, as compared to the same period in 1998, due to an increase in interest expense of $15.8 million and a decrease in interest expense capitalized of $18.9 million. Interest expense increased due primarily to an increase in average debt outstanding, reflecting amounts borrowed to finance a portion of the capital expenditures for The Chicago Project. The impact of the increased borrowings on interest expense was partially offset by a decrease in average interest rates between 1998 and 1999. The decrease in interest expense capitalized is due to the completion of construction of The Chicago Project in December 1998.
Other income decreased $10.7 million (89%) for the year ended December 31, 1999, as compared to the same period in 1998, primarily due to a decrease in the allowance for equity funds used during construction. The decrease in the allowance for equity funds used during construction is due to the completion of construction of The Chicago Project in December 1998.
Liquidity and Capital Resources
General
In August 1999, we completed a private offering of $200 million of 7.75% Senior Notes due 2009, which notes were subsequently exchanged in a registered offering for notes with substantially identical terms ("Senior Notes"). The indenture under which the Senior Notes were issued does not limit the amount of unsecured debt we may incur, but does contain material financial covenants, including restrictions on incurrence of secured indebtedness. The proceeds from the Senior Notes were used to reduce indebtedness under a June 1997 credit agreement.
In June 1997, we entered into a credit agreement ("Pipeline Credit Agreement") with certain financial institutions to borrow up to an aggregate principal amount of $750 million. The Pipeline Credit Agreement is comprised of a $200 million five- year revolving credit facility maturing in June 2002 to be used for the retirement of our prior credit facilities and for general business purposes, and a $550 million three-year revolving credit facility to be used for the construction of The Chicago Project. Effective March 31, 1999, the three-year revolving credit facility converted to a term loan maturing in June 2002. At December 31, 2000, $424 million was outstanding under the term loan and $45 million was outstanding under the five-year revolving credit facility.
At December 31, 2000, we also had outstanding $184 million of senior notes issued in a $250 million private placement under a July 1992 note purchase agreement. The note purchase agreement provides for four series of notes, Series A through D, maturing between August 2000 and August 2003. The Series A Notes with a principal amount of $66 million were repaid in August 2000. The Series B Notes with a principal amount of $41 million mature in August 2001. We anticipate borrowing on the Pipeline Credit Agreement to repay the Series B Notes.
Short-term liquidity needs will be met by internal sources and through the Pipeline Credit Agreement discussed above. Long- term capital needs may be met through the ability to issue long- term indebtedness.
Cash Flows From Operating Activities
Cash flows provided by operating activities increased $4.5 million to $176.0 million for the year ended December 31, 2000, as compared to the same period in 1999, primarily due to increased earnings. During 2000, we realized net cash inflows of approximately $2.4 million related to our rate case, which included approximately $25.1 million of amounts collected subject to refund less estimated refunds issued in late December 2000 totaling approximately $22.7 million. Cash flows provided by operating activities increased $67.7 million to $171.5 million for the year ended December 31, 1999, as compared to the same period in 1998, primarily attributed to The Chicago Project facilities placed into service in late December 1998.
Cash Flows From Investing Activities
Capital expenditures of $15.5 million for the year ended December 31, 2000 included $7.4 million for Project 2000 (see Item 1. "Business - Future Demand and Competition"). For the same period in 1999, capital expenditures were $101.7 million and included $85.5 million for The Chicago Project and $2.5 million for Project 2000. The remaining capital expenditures for 2000 and 1999 are primarily related to renewals and replacements of existing facilities.
Total capital expenditures for 2001 are estimated to be $97 million, including $81 million for Project 2000. The remaining capital expenditures planned for 2001 are for renewals and replacements of existing facilities. We currently anticipate funding our 2001 capital expenditures primarily by borrowing on our Pipeline Credit Agreement and using internal sources.
Cash Flows From Financing Activities
Cash flows used in financing activities increased $58.8 million to $148.7 million for the year ended December 31, 2000, as compared to same period in 1999. Distributions paid to the general partners increased $7.7 million to $134.9 million for the year ended December 31, 2000 as compared to the same period of 1999 primarily due to an increase in our net income. For the year ended December 31, 2000, advances under the Pipeline Credit Agreement, which were primarily used to repay $66 million of Series A Notes, were $75 million as compared to advances of $90 million for the same period in 1999, which were primarily used to finance a portion of the capital expenditures for The Chicago Project. Financing activities for the year ended December 31, 1999 included $197.4 million from the issuance of the Senior Notes, net of associated debt discounts and issuance costs, and $12.9 million from the termination of interest rate forward agreements. Payments on the Pipeline Credit Agreement were $45 million for the year ended December 31, 2000, as compared to $263 million for the same period 1999. At December 31, 2000, we reflected a cash overdraft of approximately $22.4 million primarily due to refund checks outstanding. The goal of our cash management program is to maximize the amount of our cash and cash equivalents balance in highly liquid, interest-bearing investments. Those investments are converted to cash when needed to replenish our bank accounts for check clearing requirements.
Cash flows used in financing activities were $89.9 million for the year ended December 31, 1999, as compared to cash flows provided by financing activities of $564.8 million for the same period in 1998. During the year ended December 31, 1998, our general partners contributed $223.0 million to finance a portion of the capital expenditures for The Chicago Project. Distributions paid to the general partners increased $66.0 million to $127.2 million for the year ended December 31, 1999 as compared to the same period of 1998. The distributions for 1999 were impacted by increased earnings and included distributions for 13 months activity, rather than 12 months, resulting from a change in the timing of distribution payments. The distributions for 1998 were impacted by a rate case refund during the fourth quarter of 1997 and by the change in the timing of distribution payments. Advances under the Pipeline Credit Agreement, which were primarily used to finance a portion of the capital expenditures for The Chicago Project, were $90 million for the year ended December 31, 1999 as compared to advances of $403 million for the same period in 1998.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." In June 1999, the FASB issued SFAS No. 137, which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which amended certain guidance within SFAS No. 133. See Note 8 to the Financial Statements.
Information Regarding Forward Looking Statements
Statements in this Annual Report that are not historical information are forward looking statements. Such forward looking statements include:
* the discussions under Item 1. "Business - Future Demand and Competition" and elsewhere regarding our efforts to pursue opportunities to further increase the capacity of our pipeline system;
* the discussion under Item 1. "Business - Rate Case Proceeding" regarding the settlement of our rate case;
* the discussion in Item 1. "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 can give no assurance that our goals will be achieved or that our expectations regarding future developments will be realized. Important factors that could cause actual results to differ materially from those in the forward looking statements include:
* future demand for natural gas;
* availability of economic western Canadian natural gas;
* industry conditions;
* natural gas, political and regulatory developments that impact FERC proceedings;
* our success in sustaining our positions in such proceedings, or the success of intervenors in opposing our positions;
* our ability to replace our rate base as it is depreciated and amortized;
* competitive developments by Canadian and U.S. natural gas transmission companies;
* political and regulatory developments in the U.S. and Canada; and
* conditions of the capital markets and equity markets.
Item 7a.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
Our interest rate exposure results from variable rate borrowings from commercial banks. To mitigate potential fluctuations in interest rates, we attempt to maintain a significant portion of our debt portfolio in fixed rate debt. We also use interest rate swap agreements to increase the portion of fixed rate debt. As of December 31, 2000, approximately 50% of our debt portfolio, after considering the effect of interest rate swap agreements, is in fixed rate debt.
If average interest rates change by one percentage point compared to rates in effect as of December 31, 2000, annual interest expense would change by approximately $4.3 million. This amount has been determined by considering the impact of the hypothetical interest rates on variable rate borrowings outstanding as of December 31, 2000.
Item 8.
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.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10.
Item 10. Partnership Management
Northern Border Pipeline Company is overseen by the management committee, which is composed of the following individuals:
William R. Cordes, Chairman(1)
Stanley C. Horton(1)
Dennis J. McConaghy(2)
Cuba Wadlington, Jr.(1)
__________
(1) Designated by Northern Border Partners.
(2) Designated by TC PipeLines.
William R. Cordes (52) has been a member and Chairman of our management committee since October 1, 2000. Mr. Cordes was named Chief Executive Officer of Northern Border Partners in October 2000. Since October 2000, Mr. Cordes has been the President and a director of Northern Plains, an Enron subsidiary and our operator.
Stanley C. Horton (50) has been a member of our management committee since December 1998. Mr. Horton is the Chairman and Chief Executive Officer of Enron Transportation Services Company, formerly the Enron Gas Pipeline Group and has held that position since January 1997. Prior to that, Mr. Horton served as Co- Chairman and Chief Executive Officer of Enron Operations Corp. (1996-1997) and President and Chief Operating Officer of Enron Operations Corp. (1993-1996). He is a Director, Chairman of the Board and Chief Executive Officer of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P.
Dennis J. McConaghy (49) has been a member of our management committee since December 2000. He was appointed a director of TC PipeLines GP, Inc. (the general partner of TC PipeLines LP) in December 2000. His principal occupation is Senior Vice-President Business Development for TransCanada, a position he has held since October 2000. Prior to that time and since June 2000, Mr. McConaghy was Senior Vice-President, Midstream/Divestments, TransCanada. Prior to that time and since July 1998, Mr. McConaghy was Vice-President, Strategy and Planning, TransCanada. Prior to that time and since May 1996, Mr. McConaghy was Vice- President, Corporate Development, NOVA Corporation. Prior to that time and since November 1995, Mr. McConaghy was Senior Vice- President and Chief Financial Officer, NOVA Chemicals Ltd.
Cuba Wadlington, Jr. (57) has been a member of our management committee since December 1, 1999. On January 4, 2000, Mr. Wadlington was named President and Chief Executive Officer of Williams Gas Pipeline. Previously, he had served as Executive Vice President and Chief Operating Officer of Williams Gas Pipeline since July 1999. Mr. Wadlington joined Transco in 1995 when Williams acquired Transco Energy Company. From 1995 to 1999, he served as Senior Vice President and General Manager of Williams Gas Pipeline-Transco. From 1988 to 1995, he served as Senior Vice President and General Manager of Williams Western Pipeline Company, Executive Vice President of Kern River Gas Transmission Company, and director of Northwest Pipeline Corporation and Williams Western Pipeline, all affiliates or subsidiaries of Williams. Mr. Wadlington serves on the Board of Directors of Williams Communication Group Inc. and Sterling Bancshares Inc., public companies subject to the reporting requirements of the Securities Exchange Act of 1934.
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 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.
There is also an audit and compensation committee composed of members appointed by the management committee. The audit and compensation committee, consisting of Mr. Wadlington and Mr. Paul F. MacGregor, Vice President, TransCanada, oversees the annual audit process and confers with Arthur Andersen LLP, our independent public accountants. The committee is also responsible for setting up guidelines for compensation to be paid to the executive officers of Northern Plains, each of whom spends at least a portion of his or her time on our operations, for which Northern Plains is reimbursed as indicated above. Currently, there is one vacancy on the committee.
Item 11.
Item 11. Executive Compensation
Executive Disclosure
Jerry L. Peters (43) has served as Treasurer of Northern Plains since October 1998, Vice President of Finance for Northern Plains since July 1994 and director of Northern Plains since August 1994. He has also been named Vice President, Finance for Enron Transportation Services Company. He has been associated with Northern Plains since 1985.
The following table summarizes information regarding compensation paid or accrued during each of the last three fiscal years to Larry L. DeRoin, Jerry L. Peters and the last fiscal year to William R. Cordes (the "Named Officers") by Northern Plains, our operator. Messrs. Cordes and Peters are both employees of Northern Plains, but contribute services to our operations, for which we reimburse Northern Plains. Mr. DeRoin was an employee of Northern Plains until his retirement on September 30, 2000. Northern Plains is an affiliate of Enron.
Stock Option Grants During 2000
The following table sets forth information with respect to 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 2000.
Aggregated Stock Option/SAR Exercises During 2000 and Stock Option/SAR Values as of December 31, 2000
The following table sets forth information with respect to the Named Officers concerning the exercise of Enron SARs and options during the last fiscal year and unexercised Enron options and SARs held as of the end of the fiscal year:
Retirement and Supplemental Benefit Plans
Enron maintains the Enron Corp. Cash Balance Plan (the "Cash Balance Plan") which is a noncontributory defined benefit pension plan to provide retirement income for employees of Enron and its subsidiaries. Through December 31, 1994, participants in the Cash Balance Plan with five years or more of service were entitled to retirement benefits in the form of an annuity based on a formula that uses a percentage of final average pay and years of service. In 1995, Enron's Board of Directors adopted an amendment to and restatement of the Cash Balance Plan changing the plan's name from the Enron Corp. Retirement Plan to the Enron Corp. Cash Balance Plan. In connection with a change to the retirement benefit formula, all employees became fully vested in retirement benefits earned through December 31, 1994. The formula in place prior to January 1, 1995 was suspended and replaced with a benefit accrual in the form of a cash balance of 5% of annual base pay beginning January 1, 1996. Under the Cash Balance Plan, each employee's accrued benefit will be credited with interest based on ten-year Treasury Bond yields.
Enron also maintains a noncontributory employee stock ownership plan ("ESOP") which covers 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.
In addition, Enron has a Supplemental Retirement Plan that is designed to assure payments to certain employees of that retirement income that would be provided under the Cash Balance Plan except for the dollar limitation on accrued benefits imposed by the Internal Revenue Code of 1986, as amended, and a Pension Program for Deferral Plan Participants that provides supplemental retirement benefits equal to any reduction in benefits due to deferral of salary into Enron's Deferral Plan.
The following table sets forth the estimated annual benefits payable under normal retirement at age 65, assuming current remuneration levels without any salary or bonus projections and participation until normal retirement at age 65, with respect to the Named Officers under the provisions of the foregoing retirement plans.
Mr. DeRoin participates in the Executive Supplemental Survivor Benefit Plan. In the event of death after retirement, the Plan provides an annual benefit to the participant's beneficiary equal to 50 percent of the participant's annual base salary at retirement, paid for 10 years. The Plan also provides that in the event of death before retirement, the participant's beneficiary receives an annual benefit equal to 30% of the participant's annual base salary at death, paid for the life of the participant's spouse (but for no more than 20 years in some cases).
Severance Plans
Enron's Severance Pay Plan, as amended, provides 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 economic factors. The amount of benefits payable for performance related terminations is based on length of service and may not exceed six weeks' pay. For those terminated as the result of reorganization or economic circumstances, the benefit is based on length of service and amount of pay up to a maximum payment of 26 weeks of base pay. If the employee signs a Waiver and Release of Claims Agreement, the severance pay benefits are doubled. Under no circumstances will the total severance pay benefit exceed 52 weeks of pay. Under the Enron Corp. Change of Control Severance Plan, in the event of an unapproved change of control of Enron, any employee who is involuntarily terminated within two years following the change of control will be eligible for severance benefits equal to two weeks of base pay multiplied by the number of full or partial years of service, plus one month of base pay for each $10,000 (or portion of $10,000) included in the employee's annual base pay, plus one month of base pay for each five percent of annual incentive award opportunity under any approved plan. The maximum an employee can receive is 2.99 times the employee's average W-2 earnings over the past five years.
Item 12.
Item 12. Beneficial Ownership Of Partnership Interests
The following table sets forth the beneficial ownership of general partnership interests of Northern Border Pipeline Company. There are no limited partnership interests.
Item 13.
Item 13. Certain Relationships And Related Transactions
We have extensive ongoing relationships with our general partners and certain of their affiliates. Since 1980, Northern Plains, an affiliate of Enron, has acted and will continue to act as the operator of our pipeline system pursuant to the terms of the operating agreement with Northern Plains. The initial term of the operating agreement expires in 2007. The operating agreement will continue in effect thereafter on a year-to-year basis unless terminated by us or Northern Plains upon six months written notice by either party. The operator is entitled to reimbursement for all reasonable costs, including overhead and administrative expenses, incurred by it and its affiliates in connection with the performance of its responsibilities as operator. In addition, we have agreed to indemnify the operator against any claims and liabilities arising out of the good faith performance by the operator of its responsibilities under our partnership agreement, to the extent the operator is acting within the scope of its authority and in the course of our business. For the year ended December 31, 2000, the aggregate amount paid and reimbursed to Northern Plains, for its services as operator, was approximately $31.7 million.
In addition, as of February 1, 2001:
* Enron North America Corp., an affiliate of Enron, is one of Northern Border Pipeline's firm shippers, and is obligated to pay for 6.3% of the capacity;
* TransCanada Energy Marketing USA, Inc., an affiliate of TransCanada PipeLines Limited, is one of Northern Border Pipeline's firm shippers and is currently obligated to pay for 11.4% of the capacity;
* Transcontinental Gas Pipe Line Corporation, an affiliate of Williams, is one of Northern Border Pipeline's firm shippers and is currently obligated to pay for 0.8% of the capacity; and
* Northern Natural Gas Company, an affiliate of Enron, provides a financial guaranty for a portion of the transportation capacity held by Pan-Alberta Gas, which currently represents 10.5% of the capacity.
The terms of all such related transactions are no less favorable to us than those we would expect to negotiate with unrelated third parties on an arm's length basis.
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:
* The 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.
* The 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).
* The 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.
* The 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 Project 2000 or any other opportunity relating to expansion or improvements of our pipeline system as it existed on January 15, 1999.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) (1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page.
(a) (3) Exhibits * 3.1 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (Exhibit 10.2 to Northern Border Partners, L.P.'s Form S-1, SEC File No. 33-66158 ("Form S-1")). * 4.1 Indenture, dated as of August 17, 1999, between the registrant and Bank One Trust Company, NA, successor to The First National Bank of Chicago, as trustee. (Exhibit 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement, Registration No. 333-88577 ("Form S-4")). *10.1 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.2 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.3 Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to Northern Border Partners L.P.'s Form 10-K for the year ended December 31, 1995, SEC File No. 1-12202 ("1995 10-K")). *10.4 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *10.5 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., dated June 22, 1990 (Exhibit 10.10 to Form S-1). *10.6 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc. (Exhibit 10.10.1 to Northern Border Partners L.P.'s Form 10-K for the year ended December 31, 1993, SEC File No. 1-12202 ("1993 10-K")). *10.7 Amended Exhibit A to Northern Border Pipeline U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., effective November 1, 1994 (Exhibit 10.10.2 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 1994, SEC File No. 1-12202 ("1994 10-K")). *10.8 Amended Exhibit A's to Northern Border Pipeline Company U.S. Shipper Service Agreement effective, August 1, 1995 and November 1, 1995 (Exhibit 10.10.3 to 1995 10-K). *10.9 Amended Exhibit A to Northern Border Pipeline Company U.S. Shipper Service Agreement effective April l, 1998 (Exhibit 10.10.4 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 1997, SEC File No. 1-12202 ("1997 10-K")). *10.10 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.11 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K) *10.12 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Western Gas Marketing Limited, as agent for TransCanada PipeLines Limited, dated December 15, 1980 (Exhibit 10.13 to Form S-1). *10.13 Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.14 Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.15 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement. (Exhibit 10.15 of Form S-4). *10.16 Form of Conveyance, Contribution and Assumption Agreement among Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, Northern Border Partners, L.P., and Northern Border Intermediate Limited Partnership (Exhibit 10.16 to Form S-1). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Transcontinental Gas Pipe Line Corporation, dated July 14, 1983, with Amended Exhibit A effective February 11, 1994 (Exhibit 10.17 to 1995 10-K). *10.18 Form of Credit Agreement among Northern Border Pipeline Company, The First National Bank of Chicago, as Administrative Agent, The First National Bank of Chicago, Royal Bank of Canada, and Bank of America National Trust and Savings Association, as Syndication Agents, First Chicago Capital Markets, Inc., Royal Bank of Canada, and BancAmerica Securities, Inc, as Joint Arrangers and Lenders (as defined therein) dated as of June 16, 1997 (Exhibit 10(c) to Amendment No. 1 to Northern Border Partners, L.P. Form S-3, SEC File No 333-40601 ("Form S-3")). *10.19 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.21 to 1997 10-K). *10.20 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.22 to 1997 10-K). *10.21 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 with Amendment dated September 25, 1997 (Exhibit 10.25 to 1997 10-K). *10.22 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 (Exhibit 10.26 to 1997 10-K). *10.23 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.27 to 1997 10-K). *10.24 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.28 to 1997 10-K). *10.25 Northern Border Pipeline Company Agreement among Northern Plains Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border Intermediate Limited Partnership, Northern Border Partners, L.P., and the Management Committee of Northern Border Pipeline, dated as of March 17, 1999. (Exhibit No. 10.21 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 1998, SEC File No. 1-12202 ("1998 10-K")). *10.26 Form of Contribution, Conveyance and Assumption Agreement among TC PipeLines, LP and certain other parties. (Exhibit 10.2 to TC PipeLines, LP's Form S-1, SEC File No. 333-69947 ("TC Form S-1")). *10.27 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Western Gas Marketing extending the term effective April 2, 1999 (Exhibit 10.11.1 to TC Form S-1). *10.28 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. effective November 1, 1998 (Exhibit 10.15.1 to TC Form S-1). *10.29 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. effective April 2, 1999 (Exhibit 10.16.1 to TC Form S-1). *10.30 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc. as agent for TransCanada PipeLines Limited, dated October 10, 1996, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.19 to TC Form S-1). *10.31 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc. as agent for TransCanada PipeLines Limited, dated October 5, 1998, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.20 to TC Form S-1). *10.32 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc. as agent for TransCanada PipeLines Limited, dated October 5, 1998, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.21 to TC Form S-1). *10.33 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc. as agent for TransCanada PipeLines Limited, dated October 5, 1998, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.22 to TC Form S-1). *10.34 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc. as agent for TransCanada PipeLines Limited, dated October 5, 1998, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.23 to TC Form S-1). *10.35 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc. as agent for TransCanada PipeLines Limited, dated December 18, 1998 (Exhibit 10.24 to TC Form S-1). *10.36 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan- Alberta Gas (U.S.) Inc., dated October 1, 1993, with Amended exhibit A effective June 22, 1998 (Exhibit 10.25 to TC Form S-1). *10.37 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan- Alberta Gas (U.S.) Inc. (successor to Natgas U.S. Inc.), dated October 6, 1989, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.26 to TC Form S-1). *10.38 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan- Alberta Gas (U.S.) Inc., dated October 1, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.27 to TC Form S-1). *10.39 Project Management Agreement by and between Northern Plains Natural Gas Company and Enron Engineering & Construction Company, dated March 1, 1996 (Exhibit No. 10.39 to Form S-4). *99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to Northern Border Partners, L.P.'s Amendment No. 1 to Form S-8, Registration No. 333-66949).
*Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.
(b) Reports No reports on Form 8-K were filed by the Partnership during the last quarter of 2000.
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 29th day of March, 2001.
NORTHERN BORDER PIPELINE COMPANY (A Texas General partnership)
BY: Northern Plains Natural Gas Company, As Operator
By: 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
WILLIAM R. CORDES President, Northern Plains Natural March 29, 2001 William R. Cordes Company (functional equivalent to the registrant's principal executive officer) and Management Committee Member
JERRY L. PETERS Vice President, Finance and Treausrer, March 29, 2001 Northern Plains Natural Gas Company (functional equivalent to the registrant's principal financial and accounting officer)
STANLEY C. HORTON Management Committee Member March 29, 2001 Stanley C. Horton
DENNIS J. MCCONAGHY Management Committee Member March 29, 2001 Dennis J. McConaghy
CUBA WADLINGTON, JR. Management Committee Member March 29, 2001 Cuba Wadlington, Jr.
NORTHERN BORDER PIPELINE COMPANY
Page No.
Financial Statements
Report of Independent Public Accountants Balance Sheet - December 31, 2000 and 1999 Statement of Income - Years Ended December 31, 2000, 1999 and 1998 Statement of Cash Flows - Years Ended December 31, 2000, 1999 and 1998 Statement of Changes in Partners' Capital - Years Ended December 31, 2000, 1999 and 1998 Notes to Financial Statements through
Financial Statements Schedule
Report of Independent Public Accountants on Schedule S-1 Schedule II - Valuation and Qualifying Accounts S-2
Report of Independent Public Accountants
To Northern Border Pipeline Company:
We have audited the accompanying balance sheet of Northern Border Pipeline Company (a Texas partnership) as of December 31, 2000 and 1999, and the related statements of income, cash flows and changes in partners' capital for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. 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, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Omaha, Nebraska, January 22, 2001
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Pipeline Company (Northern Border Pipeline) is a general partnership, formed in 1978, pursuant to the Texas Uniform Partnership Act. The ownership percentages of the partners in Northern Border Pipeline (Partners) at December 31, 2000 and 1999, are as follows:
Ownership Partner Percentage
Northern Border Intermediate Limited Partnership 70 TC PipeLines Intermediate Limited Partnership 30
Net income and distributions are allocated to the Partners based on ownership percentage. Effective May 28, 1999, TransCanada Border PipeLine Ltd. and TransCan Northern Ltd. transferred their combined 30% ownership interest in Northern Border Pipeline to TC PipeLines Intermediate Limited Partnership (TC PipeLines) in connection with an initial public offering of limited partner interests in TC PipeLines, LP. In accordance with the partnership agreement, net income and distributions were prorated at the effective date of the ownership transfer.
Northern Border Pipeline owns a 1,214-mile natural gas transmission pipeline system extending from the United States-Canadian border near Port of Morgan, Montana, to a terminus near Manhattan, Illinois.
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. The Partnership's representatives selected by its general partners, Northern Plains Natural Gas Company (Northern Plains), a wholly-owned subsidiary of Enron Corp. (Enron), Pan Border Gas Company (Pan Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border Pipeline Company, a wholly- owned subsidiary of The Williams Companies, Inc., 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 December 1998, Northern Plains acquired Pan Border from a subsidiary of Duke Energy Corporation. At the closing of the acquisition, Pan Border's sole asset consisted of its general partner interest in the Partnership. The day-to-day management of Northern Border Pipeline's affairs is the responsibility of Northern Plains (the Operator), as defined by the operating agreement between Northern Border Pipeline and Northern Plains. Northern Border Pipeline is charged for the salaries, benefits and expenses of the Operator. For the years ended December 31, 2000, 1999, and 1998, Northern Border Pipeline reimbursed the Operator approximately $31.7 million, $29.7 million and $30.0 million, respectively. Additionally, Northern Border Pipeline utilizes Enron affiliates for management on pipeline expansion and extension projects.
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 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 generally accepted accounting principles for nonregulated entities. At December 31, 2000 and 1999, Northern Border Pipeline has reflected regulatory assets of approximately $12.4 million and $12.1 million, respectively, in Other Assets on the balance sheet. Northern Border Pipeline is recovering the regulatory assets from its shippers over varying time periods, which range from four to 43 years.
(C) Revenue Recognition
Northern Border Pipeline transports gas for shippers under a tariff regulated by the FERC. The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system. Northern Border Pipeline's revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper's individual transportation contract. Northern Border Pipeline does not own the gas that it transports, and therefore it does not assume the related natural gas commodity risk. See Notes 3 and 4 for a further discussion of Northern Border Pipeline's tariff and transportation agreements.
(D) 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.
(E) 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 $326 million and $316 million at December 31, 2000 and 1999, respectively, and are primarily related to accelerated depreciation and other plant-related differences.
(F) Property, Plant and Equipment and Related Depreciation and Amortization
Property, plant and equipment is stated at original cost. 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 extraordinary retirements or sales.
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 rates applied to Northern Border Pipeline's transmission plant in 2000, 1999 and 1998 were 2.25%, 2.0% and 2.5%, respectively. Based upon the rate case settlement discussed in Note 3, Northern Border Pipeline will continue to use a 2.25% depreciation rate. Composite rates are applied to all other functional groups of property having similar economic characteristics.
(G) Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC) represents the estimated costs, during the period of construction, of funds used for construction purposes. For regulated activities, Northern Border Pipeline is permitted to earn a return on and recover AFUDC through its inclusion in rate base and the provision for depreciation.
(H) 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. As a result, Northern Border Pipeline has entered into various interest rate swap agreements with major financial institutions which hedge interest rate risk by effectively converting certain of its floating rate debt to fixed rate debt. Northern Border Pipeline does not use these instruments for trading purposes. The cost or benefit of the interest rate swap agreements is recognized currently as a component of interest expense.
3. RATES AND REGULATORY ISSUES
Rate Case
Northern Border Pipeline's revenue is derived from agreements with various shippers for the transportation of natural gas. It transports gas under a FERC regulated tariff. Northern Border Pipeline had used a cost of service form of tariff since its inception but agreed to convert to a stated rate form of tariff as part of the settlement of its current rate case discussed below.
Under the cost of service tariff, Northern Border Pipeline was provided an opportunity to recover all of the operations and maintenance costs of the pipeline, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated return on equity. Northern Border Pipeline was generally allowed to collect from its shippers a return on regulated rate base as well as recover that rate base through depreciation and amortization. Billings for the firm transportation agreements were based on contracted volumes to determine the allocable share of the cost of service and were not dependent upon the percentage of available capacity actually used. Under the cost of service tariff, Northern Border Pipeline billed on an estimated basis for a six-month cycle. Any net excess or deficiency resulting from the comparison of the actual cost of service determined for the period in accordance with the FERC tariff to the estimated billing was accumulated, including carrying charges thereon, and was either billed to or credited back to the shippers. Revenues reflected actual cost of service. An amount equal to differences between billing estimates and the actual cost of service, including carrying charges, was reflected in current assets or current liabilities.
Northern Border Pipeline filed a rate proceeding with the FERC in May 1999 for, among other things, a redetermination of its allowed equity rate of return. The total annual cost of service increase due to Northern Border Pipeline's proposed changes was approximately $30 million. In June 1999, the FERC issued an order in which the proposed changes were suspended until December 1, 1999, after which the proposed changes were implemented with subsequent billings subject to refund.
In September 2000, Northern Border Pipeline filed a stipulation and agreement with the FERC that documented the proposed settlement of its pending rate case. The settlement was approved by the FERC in December 2000. Under the approved settlement, effective December 1, 1999, shippers will pay stated transportation rates based on a straight fixed variable rate design. Under the straight fixed variable rate design, approximately 98% of the agreed upon revenue level is attributed to demand charges, based upon contracted firm capacity, and the remaining 2% is attributed to commodity charges, based on the volumes of gas actually transported on the system. From December 1, 1999, through and including December 31, 2000, the rates were based upon an annual revenue level of $307 million. For periods after December 31, 2000, the rates are based upon an annual revenue level of $305 million. The settlement further provides for the incorporation into Northern Border Pipeline's rate base all of the construction costs of The Chicago Project, which was Northern Border Pipeline's expansion and extension of its pipeline from near Harper, Iowa to a point near Manhattan, Illinois. Northern Border Pipeline had placed into service the facilities for The Chicago Project in December 1998. Under the settlement, both Northern Border Pipeline and its existing shippers will not be able to seek rate changes until November 1, 2005, at which time Northern Border Pipeline must file a new rate case.
After the FERC approved the rate case settlement and prior to the end of 2000, Northern Border Pipeline made estimated refund payments to its shippers totaling approximately $22.7 million, primarily related to the period from December 1999 to November 2000. At December 31, 2000, Northern Border Pipeline had estimated its remaining refund obligation through the end of 2000 to be approximately $4.7 million, which is expected to be paid in the first quarter of 2001. Northern Border Pipeline's operating revenues for 2000 reflect the significant terms of the approved settlement.
Certificate application
In October 1998, Northern Border Pipeline filed a certificate application with the FERC to seek approval to expand and extend its pipeline system into Indiana (Project 2000). When completed, Project 2000 will afford shippers on the expanded and extended pipeline system access to industrial gas consumers in northern Indiana. The certificate application was subsequently amended by Northern Border Pipeline in March and December 1999. On March 16, 2000, the FERC issued an order granting Northern Border Pipeline's application for a certificate to construct and operate the proposed facilities. The FERC approved Northern Border Pipeline's request for rolled-in rate treatment based upon the proposed project costs. The project has a targeted in-service date of November 2001. The capital expenditures for the project are estimated to be approximately $94 million, of which $10.8 million had been incurred through December 31, 2000.
Operating revenues are collected pursuant to the FERC tariff through firm transportation service agreements (firm service agreements). The firm service agreements extend for various terms with termination dates that range from October 2001 to December 2013. Northern Border Pipeline also has interruptible service agreements with numerous other shippers as a result of its self-implementing blanket transportation authority. Under the approved settlement of the rate case discussed in Note 3, in certain situations, Northern Border Pipeline will reduce the billings for the firm service agreements by one half of the revenues received from the interruptible service agreements through October 31, 2003. After October 31, 2003, all revenues from interruptible transportation service will be retained by Northern Border Pipeline.
Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.) Inc. (PAGUS), is presently obligated for approximately 25.5% of the contracted firm capacity through three firm service agreements which expire in October 2003. Financial guarantees exist through October 2001 for approximately 16.3% of the contracted firm capacity of PAGUS, including 10.5% guaranteed by Northern Natural Gas Company, a wholly-owned subsidiary of Enron. The remaining obligation of PAGUS is supported by various credit support arrangements, including among others, a letter of credit, an escrow account and an upstream capacity transfer agreement. Operating revenues from the PAGUS firm service agreements and interruptible service agreements for the years ended December 31, 2000, 1999 and 1998 were $65.0 million, $76.6 million and $87.3 million, respectively.
TransCanada Energy Marketing USA, Inc. (TransCanada Energy), an affiliate of TC PipeLines, has firm service agreements representing approximately 11.4% of contracted capacity. The firm service agreements for TransCanada Energy extend for various terms with termination dates that range from October 2003 to December 2008. Other shippers affiliated with the Partners of Northern Border Pipeline have firm service agreements representing approximately 7.1% of contracted capacity. These firm service agreements extend for various terms with termination dates that range from January 2002 to May 2009. Operating revenues from the affiliated firm service agreements and interruptible service agreements for the years ended December 31, 2000, 1999, and 1998 were $58.5 million, $52.5 million and $22.4 million, respectively.
5. CREDIT FACILITIES AND LONG-TERM DEBT
Detailed information on long-term debt is as follows:
In August 1999, Northern Border Pipeline completed a private offering of $200 million of 7.75% Senior Notes due 2009, which notes were subsequently exchanged in a registered offering for notes with substantially identical terms (1999 Senior Notes). Also in August 1999, Northern Border Pipeline received approximately $12.9 million from the termination of interest rate forward agreements, which is included in long-term debt on the balance sheet and is being amortized against interest expense over the life of the 1999 Senior Notes. The interest rate forward agreements, which had an aggregate notional amount of $150 million, had been executed in September 1998 to hedge the interest rate on a planned issuance of fixed rate debt in 1999. The proceeds from the private offering, net of debt discounts and issuance costs, and the termination of the interest rate forward agreements were used to reduce existing indebtedness under a June 1997 credit agreement.
In June 1997, Northern Border Pipeline entered into a credit agreement (Pipeline Credit Agreement) with certain financial institutions to borrow up to an aggregate principal amount of $750 million. The Pipeline Credit Agreement is comprised of a $200 million five-year revolving credit facility to be used for the retirement of a previously existing bank loan agreement and for general business purposes, and a $550 million three-year revolving credit facility to be used for the construction of The Chicago Project. Effective March 1999, in accordance with the provisions of the Pipeline Credit Agreement, Northern Border Pipeline converted the three-year revolving credit facility to a term loan maturing in June 2002. The 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, subject to certain parameters. Northern Border Pipeline is required to pay a facility fee on the remaining aggregate principal commitment amount of $624 million.
At December 31, 2000 and 1999, Northern Border Pipeline had an outstanding interest rate swap agreement with a notional amount of $40 million, which will terminate in November 2001. Under the agreement, Northern Border Pipeline makes payments to counterparties at fixed rates and in return receives payments at variable rates based on the London Interbank Offered Rate. At December 31, 2000 and 1999, Northern Border Pipeline was in a payable position relative to its counterparties. The average effective interest rate of Northern Border Pipeline's variable rate debt, taking into consideration the interest rate swap agreement, was 7.06% and 6.73% at December 31, 2000 and 1999, respectively.
Interest paid, net of amounts capitalized, during the years ended December 31, 2000, 1999 and 1998 was $68.0 million, $55.5 million and $23.8 million, respectively.
Aggregate required repayments of long-term debt are as follows: $41 million, $547 million and $65 million for 2001, 2002 and 2003, respectively. There are no required repayment obligations for either 2004 or 2005.
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 which restrict the incurrence of other indebtedness by Northern Border Pipeline and also place certain restrictions on distributions to the partners of Northern Border Pipeline. Under the most restrictive of the covenants, as of December 31, 2000 and 1999, respectively, $136 million and $132 million of partners' capital of Northern Border Pipeline could be distributed.
The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the 1992 Senior Notes was approximately $191 million and $273 million at December 31, 2000 and 1999, respectively. The estimated fair value of the 1999 Senior Notes was approximately $213 million and $201 million at December 31, 2000 and 1999, respectively. At December 31, 2000 and 1999, the estimated fair value which would be payable to terminate the interest rate swap agreement, taking into account current interest rates, was approximately $1 million. Northern Border Pipeline presently intends to maintain the current schedule of maturities for the 1992 Senior Notes, 1999 Senior Notes and the interest rate swap agreement which will result in no gains or losses on their respective repayment. 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. COMMITMENTS AND CONTINGENCIES
Capital expenditures
Total capital expenditures for 2001 are estimated to be $97 million. This includes approximately $81 million for Project 2000 (see Note 3) and approximately $16 million for renewals and replacements of the existing facilities. Funds required to meet the capital expenditures for 2001 are anticipated to be provided primarily from debt borrowings and internal sources.
Environmental Matters
Northern Border Pipeline is not aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations.
Other
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.
7. QUARTERLY FINANCIAL DATA (Unaudited)
8. ACCOUNTING PRONOUNCEMENTS
In 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring 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.
In June 1999, the FASB issued SFAS No. 137, which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which amended certain guidance within SFAS No. 133. Northern Border Pipeline will adopt SFAS No. 133 beginning January 1, 2001. The adoption of SFAS No. 133, as amended, will not have a material impact on Northern Border Pipeline's financial position or results of operations.
9. 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 2000 of approximately $31.4 million is payable February 2, 2001.
Report of Independent Public Accountants on Schedule
To Northern Border Pipeline Company:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Northern Border Pipeline Company included in this Form 10-K and have issued our report thereon dated January 22, 2001. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Pipeline Company listed in Item 14 of Part IV of this Form 10-K is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Omaha, Nebraska, January 22, 2001