-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, AUe+NkfVA6SursU46LQ8AgQS90I13v9BxLZB0WWlZJn3gAqLxkXPsVvjuomPk4hI NAe4UiMhkbguAw0POdQhRg== 0000909281-00-000002.txt : 20000329 0000909281-00-000002.hdr.sgml : 20000329 ACCESSION NUMBER: 0000909281-00-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN BORDER PARTNERS LP CENTRAL INDEX KEY: 0000909281 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 931120873 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-12202 FILM NUMBER: 581417 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST STREET 2: C/O ENRON BLDG CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138536161 MAIL ADDRESS: STREET 1: 1400 SMITH ST STREET 2: ENRON BUILDING RM 4524 CITY: HOUSTON STATE: TX ZIP: 77002 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _______________________ F O R M 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 Commission file number: 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 93-1120873 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 1400 Smith Street, Houston, Texas 77002-7369 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: 713-853-6161 ___________________ Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Units New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ____ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to be the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Aggregate market value of the Common Units held by non- affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on March 1, 2000, was approximately $715,540,843. NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS Page No. Part I Item 1. Business 1 Item 2. Properties 13 Item 3. Legal Proceedings 14 Item 4. Submission of Matters to a Vote of Security Holders 14 Part II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 15 Item 6. Selected Financial Data 16 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 17 Item 7a. Quantitative and Qualitative Disclosures About Market Risk 22 Item 8. Financial Statements and Supplementary Data 23 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 23 Part III Item 10. Partnership Management 24 Item 11. Executive Compensation 27 Item 12. Security Ownership of Certain Beneficial Owners and Management 31 Item 13. Certain Relationships and Related Transactions 31 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 34 PART I Item 1. Business General Northern Border Partners, L.P. through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, collectively referred to herein as "Partnership", owns a 70% general partner interest in Northern Border Pipeline Company, a Texas general partnership ("Northern Border Pipeline"). Our general partners and the general partners of the intermediate 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 remaining 30% general partner interest in Northern Border Pipeline is owned by TC PipeLines Intermediate Limited Partnership, a subsidiary limited partnership of TC PipeLines, LP, a publicly traded partnership. The general partner of TC PipeLines and its subsidiary limited partnership is TC PipeLines GP, Inc., which is a subsidiary of TransCanada PipeLines Limited. Our general partners hold an aggregate 2% general partner interest in the Partnership. The general partners or their affiliates also own Common Units representing an aggregate 14.5% limited partner interest. The combined general and limited partner interests in the Partnership of Enron and Williams are 12.4% and 4.1%, respectively (See Item 13. "Certain Relationships and Related Transactions"). The Partnership is managed by or under the direction of the Partnership Policy Committee consisting of three members, each of whom has been appointed by one of the general partners (See Item 10. "Partnership Management"). Our 70% interest in Northern Border Pipeline represents substantially all of our assets. Northern Border Pipeline owns a 1,214-mile United States 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, which provides shippers with access to the various natural gas markets served by those pipelines. The pipeline system was initially constructed in 1982 and was expanded and/or extended in 1991, 1992 and 1998. The most recent expansion and extension, called The Chicago Project, was completed in late 1998, and increased the pipeline system's ability to receive natural gas by 42% to its current capacity of 2,373 million cubic feet per day. In the year ended December 31, 1999, we estimate that Northern Border Pipeline transported approximately 23% of the total amount of natural gas imported from Canada to the United States. Over the same period, approximately 91% of the natural gas transported was produced in the western Canadian sedimentary basin located in the provinces of Alberta, British Columbia and Saskatchewan. Northern Border Pipeline transports 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 risk of loss from decreases in market prices for gas transported on the pipeline system. Management of Northern Border Pipeline is overseen by the Northern Border Management Committee, which is comprised of three representatives from the Partnership (one designated by each general partner) and one representative from TransCanada. 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 our three representatives on the management committee is allocated as follows: 35% to the representative designated by Northern Plains, 22.75% to the representative designated by Pan Border and 12.25% to the representative designated by Northwest Border. Therefore, Enron controls 57.75% of the voting power of the management committee and has the right to select two of the members of the management committee. For a discussion of specific relationships with affiliates, refer to Item 13. "Certain Relationships and Related Transactions." The pipeline system is operated by Northern Plains pursuant to an operating agreement. Northern Plains employs approximately 190 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. We also own Black Mesa Pipeline Holdings, Inc. ("Black Mesa"). Black Mesa, through a wholly-owned subsidiary, owns a 273-mile, 18-inch diameter coal slurry pipeline which originates at a coal mine in Kayenta, Arizona. The coal slurry pipeline transports crushed coal suspended in water. It traverses westward through northern Arizona to the 1,500 megawatt Mohave Power Station located in Laughlin, Nevada. The coal slurry pipeline is the sole source of fuel for the Mohave Power Station, which consumes an average of 4.8 million tons of coal annually. The capacity of the pipeline is fully contracted to the coal supplier for the Mohave Power Station through the year 2005. The pipeline is operated by Black Mesa Pipeline Operations, LLC, a wholly-owned subsidiary of the Partnership. Approximately 59 people are employed in the operations of Black Mesa, of which 26 are represented by a labor union, the United Mine Workers. The cash flow from the coal slurry pipeline represents only about 2% of the Partnership's total cash flow. In addition, during 1999 through our subsidiary, NBP Energy Pipelines, L.L.C., we purchased from CMS Field Services, Inc. 39% of all issued and outstanding common membership interests in Bighorn Gas Gathering, L.L.C. ("Bighorn") for $31.9 million and agreed to purchase 80% of all issued and outstanding Preferred A Units of Bighorn in 2000 for $20.8 million. CMS Field Services, Inc. and Enron, through one of its subsidiaries, hold the remaining ownership interests in Bighorn. The gathering system is managed through a management committee consisting of representatives of the owners. CMS Field Services, Inc. is the current project manager. Located in northeastern Wyoming, Bighorn is capable of gathering more that 250 million cubic feet per day of coal bed methane gas for delivery to the Fort Union Gathering system. Fort Union, in turn, offers interconnects to the interstate gas pipeline grid serving gas markets in the Rocky Mountains, the Midwest and California. The gathering system consists of more than 60 miles of large diameter gathering pipeline and went into service in late December 1999. Approximately 40 additional miles of gathering pipeline is currently under construction and is expected to be completed by the end of 2000. Bighorn has long-term agreements with CMS Oil and Gas Company and Pennaco Energy Inc. to gather coal bed methane gas. The Pipeline System With the completion of The Chicago Project in December 1998, Northern Border Pipeline owns 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. The pipeline system has pipeline access to natural gas reserves in the western Canadian sedimentary basin in the provinces of Alberta, British Columbia and Saskatchewan in Canada, as well as the Williston Basin in the United States. The pipeline system also has access to synthetic gas produced at the Dakota Gasification plant in North Dakota. For the year ended December 31, 1999, of the natural gas transported on the system, approximately 91% was produced in Canada, approximately 5% was produced by the Dakota Gasification plant, and approximately 4% was produced in the Williston Basin. The pipeline system consists of 822 miles of 42-inch diameter pipe designed to transport 2,373 million cubic feet per day 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 million cubic feet per day 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 million cubic feet per day 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, the pipeline system is connected to TransCanada's majority-owned Foothills Pipe Lines (Sask.) Ltd. system in Canada, which is connected to the Alberta system, owned by TransCanada, and the pipeline system owned by Transgas Limited in Saskatchewan. The Alberta system gathers and transports approximately 19% of the total North American natural gas production and approximately 77% 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 The pipeline system connects with multiple pipelines which provides its 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; * 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 The pipeline system serves more than 40 shippers with diverse operating and financial profiles. Based upon shippers' cost of service obligations, as of December 31, 1999, 93% of the firm capacity is contracted by producers and marketers. The remaining firm capacity is contracted to local distribution companies (5%) and interstate pipelines (2%). As of December 31, 1999, the termination dates of these contracts ranged from October 31, 2001 to December 21, 2013 and the weighted average contract life, based upon annual cost of service obligations was slightly under seven years with at least 97% of capacity contracted through mid- September 2003. Based on their proportionate shares of the cost of service, as of December 31, 1999, the five largest shippers are: Pan-Alberta Gas (U.S.) Inc. (25.7%), TransCanada PipeLines Limited (10.8%), PanCanadian Energy Services Inc (7.0%), Enron North America Corp. (formerly Enron Capital & Trade Resources Corp.) (5.7%) and PetroCanada Hydrocarbons Inc. (4.9%). The 20 largest shippers, in total, are responsible for an estimated 88.4% of the cost of service. As of December 31, 1999, the largest shipper, Pan- Alberta holds firm capacity of 690 million cubic feet per day under three contracts with terms to October 31, 2003. An affiliate of Enron provides guaranties for 300 million cubic feet per day 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 million cubic feet per day, an escrow account and an upstream capacity transfer agreement. In January 2000, it was announced that Southern Company Energy Marketing has agreed in principle to manage the assets of Pan-Alberta Gas, Ltd., which would include Pan-Alberta's contracts with Northern Border Pipeline. Subject to the necessary approvals, this arrangement is expected to go into effect in the second quarter of 2000. Some of the shippers are affiliated with the general partners of Northern Border Pipeline. TransCanada holds contracts representing 10.8% of the cost of service. Enron North America Corp., a subsidiary of Enron, holds contracts representing 5.3% of the cost of service, which was 5.7% at 1999 year end. Transcontinental Gas Pipe Line Corporation, a subsidiary of Williams, holds a contract representing 0.8% of the cost of service. See Item 13. "Certain Relationships and Related Transactions." Demand For Transportation Capacity Northern Border Pipeline's 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 and import and export of natural gas supplies. Additional pipeline export capacity also could accelerate depletion of these reserves. Northern Border Pipeline's 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 the pipeline system. Demand for western Canadian natural gas to serve other markets also influences the ability and willingness of shippers to use the 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 the 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 the pipeline system or how significant that adverse effect could be. Future Demand and Competition In October 1998, Northern Border Pipeline applied to the FERC for approval of Project 2000 to expand and extend the pipeline system into Indiana. If constructed, Project 2000 will strategically position Northern Border Pipeline to move natural gas east of Chicago and will place it in direct contact with major industrial natural gas consumers. Project 2000 would afford shippers on the expanded/extended pipeline system access to the northern Indiana industrial zone. The proposed pipeline extension will interconnect with Northern Indiana Public Service Company, a major midwest local distribution company with a large industrial load requirement, at the terminus near North Hayden, Indiana. Permanent reassignments of contracted transportation capacity, or "capacity releases", were negotiated between several existing and project shippers originally included in the October 1998 application. On March 25, 1999, Northern Border Pipeline amended the application to the FERC to reflect these changes. Numerous parties filed to intervene in this proceeding. Several parties protested this application asking that the FERC deny Northern Border Pipeline's request for rolled-in rate treatment for the new facilities and that Northern Border Pipeline be required to solicit indications of interest from existing shippers for capacity releases that would possibly eliminate the construction of certain new facilities. "Rolled-in rate treatment," is the combining of the cost of service of the existing system with the cost of service related to the new facilities for purposes of calculating a system-wide transportation charge. On September 15, 1999, the FERC issued a policy statement on certification and pricing of new construction projects. The policy statement indicated a preference for establishing the transportation charge for newly constructed facilities on a separate, stand-alone basis, also known as "incremental pricing." This reversed the existing presumption in favor of rolled-in pricing when the impact of the new capacity is not more than a 5% increase to existing rates and results in system-wide benefits. As set forth above, the amended application to construct facilities to expand the system was filed based upon rolled-in rate treatment. On December 17, 1999, Northern Border Pipeline filed an amendment to the March 25, 1999 certificate application to support rolled-in rate treatment in light of FERC's new policy statement and to modify the proposed facilities. Several parties renewed their protests of the application. 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 and finding that the project meets the requirements of the new policy statement. The FERC approved Northern Border Pipeline's request for rolled-in rate treatment based upon the proposed project costs. Upon acceptance of the certificate and completion of acquisition of necessary right-of-way, permits and equipment, construction will proceed. The revised capital expenditures for Project 2000 are estimated to be approximately $94 million. 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 proposed Project 2000 expansion, the pipeline system will have the ability to transport 1,484 million cubic feet per day from Ventura to Harper, Iowa, 844 million cubic feet per day from Harper to Manhattan, Illinois, and 544 million cubic feet per day on the new extension from Manhattan to North Hayden, Indiana. Under precedent agreements, five project shippers have agreed to take all of the transportation capacity, subject to the satisfaction of specific conditions. With the issuance of the certificate, Northern Border Pipeline and the project shippers are negotiating to resolve those conditions and execute transportation contracts. 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. Northern Border Pipeline competes 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, one of which is under construction and is described below, and the Canadian domestic users in the western Canadian sedimentary basin region. Northern Border Pipeline's 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. The Alliance Pipeline, which will transport natural gas from the western Canadian sedimentary basin to the midwestern United States, has received Canadian and United States regulatory approvals and is under construction. Its sponsors have announced their plans for the Alliance Pipeline to be in service by late 2000. Upon its completion, Northern Border Pipeline will compete directly with the Alliance Pipeline. We expect that the Alliance Pipeline would transport for its shippers gas containing high-energy liquid hydrocarbons. Additional facilities to extract the natural gas liquids are being constructed near the Alliance Pipeline's terminus in Chicago to permit Alliance to transport natural gas with the liquids-rich element. As a consequence of the Alliance Pipeline, there may be a large increase in natural gas moving from the western Canadian sedimentary basin to Chicago. There are several additional projects proposed to transport natural gas from the Chicago area to growing eastern markets that would provide access to additional markets for the shippers. The proposed projects currently being pursued by third parties and TransCanada are targeting markets in eastern Canada and the northeast United States. These proposed projects are in various stages of regulatory approval. One such project, Vector Pipeline L.P., has commenced construction. Williams has a minority interest (14.6%) in the Alliance Pipeline. TransCanada and other unaffiliated companies own and operate pipeline systems which transport natural gas from the same natural gas reserves in western Canada that supply Northern Border Pipeline's 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 Northern Border Pipeline is 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, Northern Border Pipeline holds 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. Northern Border Pipeline's 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. Cost of service tariff The firm transportation shippers contract to pay for a proportionate share of the pipeline system's cost of service. During any given month, each of these shippers pays a uniform mileage-based charge for the amount of capacity contracted, calculated under a cost of service tariff. The shippers are obligated to pay their proportionate share of the cost of service regardless of the amount of natural gas they actually transport. The cost of service tariff is regulated by the FERC and provides an opportunity to recover operations and maintenance costs of the pipeline system, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a return on equity approved by the FERC. Northern Border Pipeline may not charge or collect more than the cost of service under the tariff on file with the FERC. The investment in the pipeline system is reflected in various accounts referred to collectively as the regulated "rate base." The cost of service includes a return, with related income taxes, on the rate base. Over time, the rate base declines as a result of, among other things, monthly depreciation and amortization. The rate base currently includes, as an additional amount, a one-time ratemaking adjustment to reflect the receipt of a financial incentive on the original construction of the pipeline. Since inception, the rate base adjustment, called an incentive rate of return, has been amortized through monthly additions to the cost of service. The amortization continues until November 2001 when the incentive rate of return will be fully amortized. Northern Border Pipeline bills the cost of service on an estimated basis for a six month cycle. Any net excess or deficiency between the cost of service determined for that period according to the FERC tariff and the estimated billing is accumulated, including carrying charges. This amount is then either billed to or credited back to the shippers' accounts. Northern Border Pipeline also provides interruptible transportation service. Interruptible transportation service is transportation in circumstances when surplus capacity is available after satisfying firm service requests. The maximum rate charged to interruptible shippers is calculated from cost of service estimates on the basis of contracted capacity. Except for certain limited situations, all revenue from the interruptible transportation service is credited to the cost of service for the benefit of the firm shippers. In the 1995 rate case, Northern Border Pipeline reached a settlement that was filed in a stipulation and agreement. Although it was contested, the settlement was approved by the FERC on August 1, 1997. In the settlement, the depreciation rate was established at 2.5% from January 1, 1997 through the in-service date of The Chicago Project and, at that time, it was reduced to 2.0%. Starting in the year 2000, the depreciation rate is scheduled to increase gradually on an annual basis until it reaches 3.2% in 2002. The settlement also determined several other cost of service parameters. In accordance with the effective tariff, the allowed equity rate of return is 12.0%. For at least seven years from the date The Chicago Project was completed, under the terms of the settlement, Northern Border Pipeline may continue to calculate the allowance for income taxes as a part of the cost of service in the manner it had historically used. In addition, a settlement adjustment mechanism of $31 million was implemented, which effectively reduces the allowed return on rate base. Also as agreed to in the settlement, Northern Border Pipeline implemented a project cost containment mechanism for The Chicago Project. The purpose of the project cost containment mechanism was to limit Northern Border Pipeline's ability to include cost overruns for The Chicago Project in rate base and to provide incentives for cost underruns. The settlement agreement required the budgeted cost for The Chicago Project, which had been initially filed with the FERC for approximately $839 million, to be adjusted for the effects of inflation and for costs attributable to changes in project scope, as defined in the settlement agreement. In the determination of The Chicago Project cost containment mechanism, the actual cost of the project is compared to the budgeted cost. If there is a cost overrun of $6 million or less, the shippers will bear the actual cost of the project through its inclusion in our rate base. If there is a cost savings of $6 million or less, the full budgeted cost will be included in the rate base. If there is a cost overrun or cost savings of more than $6 million but less than 5% of the budgeted cost, the $6 million plus 50% of the excess will be included in our rate base. All cost overruns exceeding 5% of the budgeted cost are excluded from the rate base. Northern Border Pipeline has determined the budgeted cost of The Chicago Project, as adjusted for the effects of inflation and project scope changes, to be $897 million, with the final construction cost estimated to be $894 million. Northern Border Pipeline's notification to the FERC and its shippers in June 1999 in its final report reflects the conclusion that there will be a $3 million addition to rate base related to the project cost containment mechanism. The stipulation required the calculation of the project cost containment mechanism to be reviewed by an independent national accounting firm. The independent accountants completed their examination of Northern Border Pipeline's calculation of the project cost containment mechanism in October 1999. The independent accountants concluded Northern Border Pipeline had complied in all material respects with the requirements of the stipulation related to the project cost containment mechanism. Although we believe that the computations in the final report have been properly completed under the terms of the stipulation, we are unable to predict at this time whether any adjustments will be required. Later developments in the pending rate case, discussed below, may prevent recovery of amounts originally calculated under the project cost containment mechanism, which may result in a non-cash charge to write down our balance sheet transmission plant line item, and that charge could be material to our operating results. In May 1999, Northern Border Pipeline filed a rate case wherein it 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 is approximately $30 million. A number of the shippers and competing pipelines have 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 tariff, the depreciation schedule and the creditworthiness standards. Several parties, including Northern Border Pipeline, asked for clarification or rehearing of various aspects of the June order. On August 31, 1999, the FERC issued an order that provided that the issue of rolled-in rate treatment of The Chicago Project may be examined in this proceeding. Also, since the amount of The Chicago Project costs to be included in rate base is governed by the settlement in the previous rate case, the FERC consolidated that proceeding with this case and directed that the presiding Administrative Law Judge conduct any further proceedings that may be appropriate. Under the order issued August 31, 1999, Northern Border Pipeline filed the June 1999 final report and the independent accountants' report on the calculation of the project cost containment mechanism. While Northern Border Pipeline had not proposed in this case to change the depreciation rates approved in the last rate case, the order also provided that it had the burden of proving that the depreciation rates are just and reasonable. Testimony filed by FERC staff and intervenors has advocated positions on among other things, rate of return on equity ranging from 9.85% to 11.5%, a depreciation straight line rate ranging from 2.34% to 2.5%, a reduction in rate base under the project cost containment mechanism ranging from $31.8 million to $43.1 million, and modification of the cost of service form of tariff to adoption of a stated rate form of tariff with various rate designs. A procedural schedule has been established which calls for the hearing to commence in July 2000. At this time, we can give no assurance as to the outcome on any of these issues. 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. Since Northern Border Pipeline has been a transportation only pipeline since inception, implementation was easily met. Capacity release provisions were adopted which allowed shippers to release all or part of their capacity either permanently or temporarily. If a shipper temporarily releases part or all of its firm capacity to a third party, then that releasing shipper receives credit against amounts due under its firm transportation contract for revenues received by Northern Border Pipeline as a result of the temporary release. The releasing shipper is not relieved of its obligations under its contract. Shippers on the 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. Order 636 adopted "right of first refusal" procedures, imposed by the FERC as a condition to the pipeline's right to abandon long-term transportation service, to govern a shipper's continuing rights to transportation services when its contract with the pipeline expires. The FERC's rules require existing shippers to match any bid of up to five years in order to renew those contracts. As discussed below, the FERC has narrowed the scope of this right. In the future, the right of first refusal will apply only to maximum rate contracts for 12 or more consecutive months of service. 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. Northern Border Pipeline has implemented the necessary changes to the tariff and internal systems so we can fully comply with the business standards as required by these orders. In 1998, the FERC initiated a number of proceedings to further amend its open access regulations. In a Notice of Proposed Rulemaking issued on July 29, 1998, the FERC proposed changes to its regulations governing short-term transportation services. 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. On September 15, 1999, the FERC issued a policy statement on certification and pricing of new construction projects. The policy statement announces a preference for pricing new construction incrementally. This reverses the existing presumption in favor of rolled-in pricing when the impact of the new capacity is not more than a 5% increase to existing rates and results in system-wide benefits. Also, in examining new projects, the FERC will evaluate the efforts by the applicant to minimize adverse impact to its existing customers, to competitor pipelines and their captive customers, and to landowners and communities affected by the proposed route of the pipeline. If the public benefits outweigh any residual adverse effects, the FERC will proceed with the environmental analysis of the project. This policy is to be applied on a case-by-case basis. In an order issued February 9, 2000, the FERC addressed requests for rehearing of the policy statement and generally affirmed the policy statement with a few changes and clarifications. We do not believe that these regulatory initiatives will have a material adverse impact to Northern Border Pipeline's 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. Black Mesa Pipeline, Inc., our subsidiary, has received a Findings of Violation by the United States Environmental Protection Agency ("EPA"), citing violations of the Clean Water Act and Notice of Violation from the Arizona Department of Environmental Quality citing violations of state laws due to discharges of coal slurry on Black Mesa's pipeline from December 1997 through July 1999. Black Mesa Pipeline has agreed to pay an amount of $128,000 in penalties for all alleged violations. The EPA has determined that a Consent Decree will be required and we are negotiating the terms of that decree which will include certain preventative measures, reporting requirements and associated penalties for failure to comply. 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 the Partnership's operations, could result in substantial costs and liabilities to the Partnership. If we are unable to recover such resulting costs, cash distributions could be adversely affected. Item 2. Properties Northern Border Pipeline holds the right, title and interest in its pipeline system. With respect to real property, the pipeline system falls into two basic categories: (a) parcels which Northern Border Pipeline owns in fee, such as certain of the compressor stations, meter stations, pipeline field office sites, and microwave tower sites; and (b) parcels where the interest of Northern Border Pipeline derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction and operation of the pipeline system. The right to construct and operate the pipeline across certain property was obtained by Northern Border Pipeline through exercise of the power of eminent domain. Northern Border Pipeline continues to have the power of eminent domain in each of the states in which it operates the pipeline system, although it may not have the power of eminent domain with respect to Native American tribal lands. Approximately 90 miles of the 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. Northern Border Pipeline does have the right of eminent domain with respect to allotted lands. In 1980, Northern Border Pipeline entered into a pipeline right-of-way lease with the Fort Peck Tribal Executive Board, for and on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation. This pipeline right-of-way lease, which was approved by the Department of the Interior in 1981, granted to Northern Border Pipeline the right and privilege to construct and operate its pipeline on certain tribal lands, for a term of 15 years, renewable for an additional 15 year term at the option of Northern Border Pipeline without additional rental. Northern Border Pipeline continues to operate on this portion of the pipeline located on tribal lands in accordance with its renewal rights. In conjunction with obtaining a pipeline right-of-way lease across tribal lands located within the exterior boundaries of the Fort Peck Indian Reservation, Northern Border Pipeline also obtained a right-of-way across allotted lands located within the reservation boundaries. This right- of-way, granted by the Bureau of Indian Affairs ("BIA") on March 25, 1981, for and on behalf of individual Indian owners, expired on March 31, 1996. Before the termination date, Northern Border Pipeline undertook efforts to obtain voluntary consents from individual Indian owners for a new right-of-way, and Northern Border Pipeline filed applications with the BIA for new right-of-way grants across those tracts of allotted lands where a sufficient number of consents from the Indian owners had been obtained. During 1999, the BIA issued formal right-of-way grants for those tracts for which sufficient landowners consents were obtained. Also, a condemnation action was filed in Federal Court in the District of Montana concerning those remaining tracts of allotted land for which a majority of consents were not timely received. An order was entered on March 18, 1999 condemning permanent easements in favor of Northern Border Pipeline on the tracts in question. 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. Also, see Item 1. "Business - Environmental and Safety Matters." Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during 1999. PART II Item 5. Market for the Registrant's Common Units and Related Security Holder Matters The following table sets forth, for the periods indicated, the high and low sale prices per Common Unit, as reported on the New York Stock Exchange Composite Tape, and the amount of cash distributions per Common Unit declared for each quarter:
Price Range Cash High Low Distributions 1999 First Quarter $35.50 $30.375 $0.61 Second Quarter 33.5625 30.1875 0.61 Third Quarter 31.875 28.00 0.61 Fourth Quarter 29.50 21.625 0.65 1998 First Quarter $34.3125 $32.50 $0.575 Second Quarter 35.00 31.8125 0.575 Third Quarter 34.75 31.125 0.575 Fourth Quarter 36.125 32.50 0.61
As of March 1, 2000, there were approximately 2,100 record holders of Common Units and approximately 37,900 beneficial owners of the Common Units, including Common Units held in street name. We currently have 29,347,313 Common Units outstanding, representing a 98% limited partner interest. The Common Units are the only outstanding limited partner interests. Thus, our equity consists of general partner interests representing in the aggregate a 2% interest and Common Units representing in the aggregate a 98% limited partner interest. In general, the general partners are entitled to 2% of all cash distributions, and the holders of Common Units are entitled to the remaining 98% of all cash distributions, except that the general partners are entitled to incentive distributions if the amount distributed with respect to any quarter exceeds $0.605 per Common Unit ($2.42 annualized). Under the incentive distribution provisions, the general partners are entitled to 15% of amounts distributed in excess of $0.605 per Common Unit, 25% of amounts distributed in excess of $0.715 per Common Unit ($2.86 annualized) and 50% of amounts distributed in excess of $0.935 per Common Unit ($3.74 annualized). The amounts that trigger incentive distributions at various levels are subject to adjustment in certain events, as described in the Partnership Agreement. On January 18, 2000, we declared an increase in the distribution to $0.65 per Unit ($2.60 per Unit on an annualized basis), payable February 14, 2000 to the general partners and Unitholders of record at January 31, 2000. On January 19, 1999, the 6,420,000 Subordinated Units outstanding were converted into 6,420,000 Common Units in accordance with their terms in a transaction that was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933. Item 6. Selected Financial Data (in thousands, except per Unit and operating data)
Year Ended December 31, 1999 1998 1997 1996 1995 INCOME DATA: Operating revenues, net $ 318,963 $ 217,592 $ 198,574 $ 201,943 $ 206,497 Operations and maintenance 53,451 44,770 37,418 28,366 26,730 Depreciation and amortization 54,493 43,536 40,172 46,979 47,081 Taxes other than income 30,952 22,012 22,836 24,390 23,886 Regulatory credit -- (8,878) -- -- -- Operating income 180,067 116,152 98,148 102,208 108,800 Interest expense, net 67,709 30,922 30,860 32,670 35,106 Other income 4,213 12,859 7,989 2,900 469 Minority interests in net income 35,568 30,069 22,253 22,153 22,360 Net income to partners $ 81,003 $ 68,020 $ 53,024 $ 50,285 $ 51,803 Net income per Unit $ 2.70 $ 2.27 $ 1.97 $ 1.88 $ 1.94 Number of units used in computation 29,347 29,345 26,392 26,200 26,200 CASH FLOW DATA: Net cash provided by operating activities $ 173,368 $ 103,849 $ 119,621 $ 137,534 $ 127,078 Capital expenditures 102,270 652,194 152,658 18,597 8,411 Distribution per Unit 2.44 2.30 2.20 2.20 2.20 BALANCE SHEET DATA (AT END OF PERIOD): Property, plant and equipment, net $1,745,356 $1,730,476 $1,118,364 $ 937,859 $ 957,587 Total assets 1,863,437 1,825,766 1,266,917 1,016,484 1,041,339 Long-term debt, including current maturities 1,031,986 976,832 481,355 377,500 410,000 Minority interests in partners' capital 250,450 253,031 174,424 158,089 166,789 Partners' capital 515,269 507,426 500,728 410,586 419,117 OPERATING DATA (unaudited): Northern Border Pipeline: Million cubic feet of gas delivered 834,833 608,187 621,262 630,148 614,617 Average daily throughput (MMcfd) 2,353 1,706 1,735 1,755 1,717
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Year Ended December 31, 1999 Compared With the Year Ended December 31, 1998 Operating revenues, net increased $101.4 million (47%) for the year ended December 31, 1999, as compared to the same period in 1998, due primarily to additional revenue from Northern Border Pipeline's operation of The Chicago Project facilities. Additional receipt capacity of 700 million cubic feet per day, a 42% increase, and new firm transportation agreements with 27 shippers resulted from The Chicago Project. Northern Border Pipeline's FERC tariff provides 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. Northern Border Pipeline is generally allowed an opportunity to collect from its shippers a return on unrecovered rate base as well as recover that rate base through depreciation and amortization. The return amount Northern Border Pipeline collects from its shippers declines as the rate base is recovered. The Chicago Project increased Northern Border Pipeline's 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 $8.7 million (19%) 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 $11.0 million (25%) 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%. Northern Border Pipeline 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 (41%) 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, Northern Border Pipeline recorded a regulatory credit of $8.9 million. During the construction of The Chicago Project, Northern Border Pipeline 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. Northern Border Pipeline is allowed to recover from its shippers the regulatory asset that resulted from the cost of service deferral over a ten-year period commencing with the in-service date of The Chicago Project. Interest expense, net increased $36.8 million (119%) for the year ended December 31, 1999, as compared to the same period in 1998, due to an increase in interest expense of $17.9 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 $8.6 million (67%) 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. Minority interests in net income increased $5.5 million (18%) for the year ended December 31, 1999, as compared to the same period in 1998, due to increased net income for Northern Border Pipeline. Year Ended December 31, 1998 Compared With the Year Ended December 31, 1997 Operating revenues, net increased $19.0 million (10%) for the year ended December 31, 1998, as compared to the results for the comparable period in 1997. Operating revenues attributable to Northern Border Pipeline increased $10.5 million due primarily to returns on higher levels of invested equity. Operating revenues for Black Mesa were $21.0 million in 1998 as compared to $12.5 million in 1997, which represented seven months of revenue. On May 31, 1997, the Partnership increased its ownership interest of Black Mesa and began to reflect its operating results on a consolidated basis. Prior to that time, Black Mesa was accounted for on the equity method and included in other income. Operations and maintenance expense increased $7.4 million (20%) for the year ended December 31, 1998, from the comparable period in 1997. Operations and maintenance expense for Black Mesa was $13.8 million in 1998 as compared to $7.7 million in 1997, which represented seven months of expense. Depreciation and amortization expense increased $3.4 million (8%) for the year ended December 31, 1998, as compared to the same period in 1997. Depreciation and amortization expense attributable to Northern Border Pipeline increased $2.3 million primarily due to facilities that were placed in service in 1998. Depreciation and amortization expense for Black Mesa was $2.6 million in 1998 as compared to $1.5 million in 1997, which represented seven months of expense. For the year ended December 31, 1998, Northern Border Pipeline recorded a regulatory credit of approximately $8.9 million. During the construction of The Chicago Project, Northern Border Pipeline placed certain 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 results in deferral of the cost of service of these new facilities. Northern Border Pipeline is allowed to recover from its shippers the regulatory asset that resulted from the cost of service deferral over a ten-year period commencing with the in-service date of The Chicago Project. Interest expense, net increased slightly for the year ended December 31, 1998, as compared to the results for the same period in 1997, due to an increase in interest expense of $15.4 million offset by an increase in the amount of interest expense capitalized of $15.3 million. Interest expense attributable to Northern Border Pipeline and the Partnership increased $14.6 million 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 remainder of the increase in interest expense is from Black Mesa, which was $2.3 million for 1998 as compared to $1.5 million for seven months in 1997. The increase in interest expense capitalized primarily relates to Northern Border Pipeline's expenditures for The Chicago Project. Other income increased $4.9 million (61%) for the year ended December 31, 1998, as compared to the same period in 1997. The increase was primarily due to an $8.8 million increase in the allowance for equity funds used during construction. The increase in the allowance for equity funds used during construction primarily relates to Northern Border Pipeline's expenditures for The Chicago Project. Other income for 1997 included $4.8 million received by Northern Border Pipeline for vacating certain microwave frequency bands. The amount received was a one-time occurrence and Northern Border Pipeline does not expect to receive any material payments for vacating microwave frequency bands in the future. Minority interests in net income increased $7.8 million (35%) for the year ended December 31, 1998, as compared to the same period in 1997, due to increased net income for Northern Border Pipeline. Liquidity and Capital Resources General 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 ("Senior Notes"). The indenture under which the Senior Notes were issued does not limit the amount of unsecured debt Northern Border Pipeline 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, 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 Northern Border Pipeline's 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 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 2002. At December 31, 1999, $439.0 million was outstanding under the term loan. No funds were outstanding under the five-year revolving credit facility. At December 31, 1999, Northern Border Pipeline also had outstanding $250 million of senior notes issued in a 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 mature in August 2000. Northern Border Pipeline anticipates borrowing on the Pipeline Credit Agreement to repay the Series A Notes. In November 1997, the Partnership entered into a credit agreement ("Partnership Credit Agreement") with certain financial institutions to borrow up to an aggregate principal amount of $175 million under a revolving credit facility. The Partnership Credit Agreement is to be used for interim funding of the Partnership's required capital contributions to Northern Border Pipeline for construction of The Chicago Project. The amount available under the Partnership Credit Agreement is reduced to the extent the Partnership issues additional limited partner interests to fund the Partnership's capital contributions for The Chicago Project in excess of $25 million. Public offerings of Common Units in December 1997 and January 1998 reduced the amount available under the Partnership Credit Agreement to $104 million. With the conversion of Northern Border Pipeline's three-year revolving credit facility to a term loan, the maturity date of the Partnership Credit Agreement is November 2000. At December 31, 1999, $90 million had been borrowed on the Partnership Credit Agreement. In December 1999, the Partnership entered into a one-year credit agreement ("1999 Credit Agreement") with a single financial institution to borrow up to an aggregate principal amount of $25 million under a revolving line of credit. The 1999 Credit Agreement is to be used for capital contributions to Northern Border Pipeline or for acquisitions by the Partnership. If the Partnership Credit Agreement is terminated, the 1999 Credit Agreement automatically terminates. At December 31, 1999, $24.5 million had been borrowed on the 1999 Credit Agreement. As indicated above, both of the Partnership's credit facilities mature in the year 2000. The Partnership plans to refinance these facilities with long-term credit facilities at a level that could also be used to finance additional capital contributions to Northern Border Pipeline and other acquisitions by the Partnership. In February 1999, the Partnership filed two registration statements with the Securities and Exchange Commission ("SEC"). One registration statement was for a proposed offering of $200 million in Common Units and debt securities to be used by the Partnership for general business purposes including repayment of debt, future acquisitions, capital expenditures and working capital. The other registration statement was for a proposed offering of 3,210,000 Common Units that are presently owned by Northwest Border, a General Partner, and PEC Midwest, L.L.C., of which the Partnership will not receive any proceeds. Short-term liquidity needs will be met by internal sources and through the lines of credit discussed above. Long-term capital needs may be met through the ability to issue long-term indebtedness as well as additional limited partner interests of the Partnership either through the registration statements previously discussed or separate registrations. Cash Flows From Operating Activities Cash flows provided by operating activities increased $69.5 million to $173.4 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 provided by operating activities decreased $15.8 million to $103.8 million for the year ended December 31, 1998 as compared to the same period in 1997 primarily related to a $36.3 million reduction for changes in components of working capital partially offset by the effect of the refund activity in 1997 discussed below. For the year ended December 31, 1998, the changes in components of working capital reflected a decrease in accounts payable of $11.8 million as compared to an increase of $14.6 million in 1997, exclusive of accruals for The Chicago Project. In addition, the changes in components of working capital for 1998 reflected a decrease in over recovered cost of service of $4.6 million and an increase in under recovered cost of service of $2.8 million. The over/under recovered cost of service is the difference between Northern Border Pipeline's estimated billings to its shippers, which are determined on a six- month cycle, and the actual cost of service determined in accordance with the FERC tariff. The difference is either billed to or credited back to the shippers accounts. Cash flows provided by operating activities for the year ended December 31, 1997 reflected a $52.6 million refund in October 1997 in accordance with the stipulation approved by the FERC to settle the November 1995 rate case. During 1997, Northern Border Pipeline collected $40.4 million subject to refund as a result of the rate case. Cash Flows From Investing Activities Capital expenditures of $102.3 million for the year ended December 31, 1999 include $85.5 million for The Chicago Project and $2.5 million for Project 2000. The remaining capital expenditures for this period are primarily related to renewals and replacements of existing facilities. For the same period in 1998, capital expenditures were $652.2 million, which included $638.7 million for The Chicago Project and $11.7 million for linepack gas purchased from Northern Border Pipeline's shippers. Linepack gas is the natural gas required to fill the pipeline system. The cost of the linepack gas is included in Northern Border Pipeline's rate base. The remaining capital expenditures for 1998 are primarily related to renewals and replacements of existing facilities. Total capital expenditures for 2000 are estimated to be $25 million, including $10 million for Project 2000. The remaining capital expenditures planned for 2000 are primarily for renewals and replacements of the existing facilities. Northern Border Pipeline currently anticipates funding its 2000 capital expenditures primarily by using internal sources. Cash flows used for acquisition and consolidation of businesses of $31.9 million for the year ended December 31, 1999, are related to the Partnership's acquisition of Bighorn in December 1999. The Partnership has agreed to acquire additional ownership in Bighorn in 2000 for $20.8 million and to make capital contributions to Bighorn for construction of gas gathering facilities. The Partnership's capital contributions to Bighorn are estimated to be approximately $10 million in 2000. The Partnership anticipates financing its obligations using the credit facilities referred to previously. Cash Flows From Financing Activities Cash flows used in financing activities were $57.3 million for the year ended December 31, 1999, as compared to cash flows provided by financing activities of $482.6 million for the year ended December 31, 1998. Cash distributions to the unitholders and the general partners increased $4.3 million reflecting an increase in the quarterly distribution from $0.575 per Unit to $0.61 per Unit. Distributions paid to minority interest holders were $38.1 million for the year ended December 31, 1999, as compared to net cash contributions received from minority interest holders of $48.5 million for the year ended December 31, 1998, which included amounts needed to finance a portion of the capital expenditures for The Chicago Project. Financing activities for the year ended December 31, 1998 reflect $7.6 million in net proceeds from the issuance of 225,000 Common Units and related capital contributions by the Partnership's general partners in January 1998. 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 the interest rate forward agreements. Advances under the Pipeline Credit Agreement, which were primarily used to finance a portion of the capital expenditures for The Chicago Project, were $90.0 million for the year ended December 31, 1999. Advances under the 1999 Credit Agreement, which were used for the acquisition of Bighorn, were $24.5 million for the year ended December 31, 1999. For the same period in 1998, advances under the Pipeline Credit Agreement and Partnership Credit Agreement totaled $498.0 million. During the year ended December 31, 1999, $263.0 million and $5.0 million was repaid on the Pipeline Credit Agreement and Partnership Credit Agreement, respectively. Year 2000 Similar to most businesses, we rely heavily on information systems technology to operate in an efficient and effective manner. Much of this technology takes the form of computers and associated hardware for data processing and analysis. In addition, a great deal of information processing technology is embedded in microelectronic devices. A Year 2000 problem was anticipated which could result from the use in computer hardware and software of two digits rather than four digits to define the applicable year. As a result, computer programs that have date- sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. Before January 1, 2000, we identified, inventoried and assessed computer software, hardware, embedded chips and third-party interfaces. Where necessary, remediation and replacements were identified and implemented. All of our mission-critical and non- mission-critical systems have operated to date, with no interruption in business operations. The Year 2000 problem has resulted in no material costs. We will remain vigilant for Year 2000 related problems that may yet occur, due to hidden defects in our computer hardware or software or at mission-critical external entities. We anticipate that the Year 2000 problem will not create material disruptions to our mission-critical facilities or operations, and will not result in material costs. 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. See Note 10 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 "Business - Future Demand and Competition" and elsewhere regarding Northern Border Pipeline's efforts to pursue opportunities to further increase the capacity of its pipeline system; * the discussion under "Business - Shippers" regarding potential contract extensions; * the discussion under "Business - FERC Regulation - Cost of service tariff" regarding a project cost containment mechanism related to The Chicago Project; and * the discussion in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." Although we believe that our expectations regarding future events are based on reasonable assumptions within the bounds of our knowledge of our business, we 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; * Northern Border Pipeline's success in sustaining its positions in such proceedings, or the success of intervenors in opposing Northern Border Pipeline's positions; * Northern Border Pipeline's ability to replace its 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; * conditions of the capital markets and equity markets; and * our ability to successfully implement our plan for addressing Year 2000 issues during the periods covered by the forward looking statements. 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 consolidated 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, 1999, approximately 50% of our debt portfolio, after considering the effect of the interest rate swap agreements, is in fixed rate debt. If interest rates average one percentage point more than rates in effect as of December 31, 1999, consolidated annual interest expense would increase by approximately $5.1 million. This amount has been determined by considering the impact of the hypothetical interest rates on our variable rate borrowings and interest rate swap agreements outstanding as of December 31, 1999. Approximately $4.0 million of this increase would result from applying the hypothetical interest rates to Northern Border Pipeline's outstanding debt portfolio. Northern Border Pipeline's tariff provides the pipeline an opportunity to recover, among other items, interest expense. Therefore, the Partnership believes that under Northern Border Pipeline's current tariff, Northern Border Pipeline would be allowed to recover the increase in its interest expense, if it were to occur. Thus, the estimated impact on our annual earnings and cash flow from a hypothetical one percentage point increase in interest rates would be a reduction of approximately $1.1 million related to interest expense on borrowings other than by Northern Border Pipeline. Item 8. Financial Statements and Supplementary Data The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. Item 10. Partnership Management We are managed by or under the direction of the Partnership Policy Committee consisting of three members, each of which has been appointed by one of the general partners. The members appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and 17.5%, respectively of the voting power. The Partnership Policy Committee has appointed two individuals who are neither officers nor employees of any general partner or any affiliate of a general partner, to serve as a committee of the Partnership (the "Audit Committee") with authority and responsibility for selecting our independent public accountants, reviewing our annual audit and resolving accounting policy questions. The Audit Committee also has the authority to review, at the request of a general partner, specific matters as to which a general partner believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the Partnership Policy Committee is fair and reasonable to us. As is commonly the case with publicly-traded partnerships, we do not directly employ any of the persons responsible for managing or operating the Partnership or for providing it with services relating to its day-to-day business affairs. We have entered into an Administrative Services Agreement with NBP Services Corporation, a wholly-owned subsidiary of Enron, pursuant to which NBP Services provides tax, accounting, legal, cash management, investor relations and other services for the Partnership. NBP Services uses the employees of Enron or its affiliates who have duties and responsibilities other than those relating to the Administrative Services Agreement. In consideration for its services under the Administrative Services Agreement, NBP Services is reimbursed for its direct and indirect costs and expenses, including an allocated portion of employee time and Enron's overhead costs. Set forth below is certain information concerning the members of the Partnership Policy Committee, our representatives on the Northern Border Management Committee and the persons designated by the Partnership Policy Committee as our executive officers and as Audit Committee members. All members of the Partnership Policy Committee and our representatives on the Northern Border Management Committee serve at the discretion of the general partner that appointed them. The persons designated as executive officers serve in that capacity at the discretion of the Partnership Policy Committee. Effective December 1, 1999, Cuba Wadlington, Jr. replaced Brian E. O'Neill as a member of the Partnership Policy Committee and the representative on the Northern Border Management Committee designated by Northwest Border. The members of the Partnership Policy Committee receive no management fee or other remuneration for serving on this Committee. The Audit Committee members are elected, and may be removed, by the Partnership Policy Committee. Each Audit Committee member receives an annual fee of $15,000 and is paid $1,000 for each meeting attended. Name Age Positions Executive Officers: Larry L. DeRoin 58 Chief Executive Officer Jerry L. Peters 42 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: Larry L. DeRoin 58 Chairman Stanley C. Horton 50 Member Cuba Wadlington, Jr. 56 Member Members of Audit Committee: Daniel P. Whitty 68 Chairman Gerald B. Smith 49 Member Larry L. DeRoin was named Chief Executive Officer of the Partnership and Chairman of the Partnership Policy Committee in July 1993. Mr. DeRoin is the President of Northern Plains, an Enron subsidiary, having held that position since January 1985, and is a director of Northern Plains. He started his career with another Enron Company, Northern Natural, in 1967 and has worked in several management positions, including President of Peoples Natural Gas Company, a former retail natural gas subsidiary of Enron. Mr. DeRoin has been a member of the Northern Border Management Committee since 1985 and has been Chairman since late 1988. Stanley C. Horton was appointed to the Partnership Policy Committee and to the Northern Border Management Committee in December 1998. Mr. Horton is the Chairman and Chief Executive Officer of Enron Gas Pipeline Group and has held that position since January 1997. From February 1996 to January 1997, he was Co-Chairman and Chief Executive Officer of Enron Operations Corp. From June 1993 to February 1996, he was President and Chief Operating Officer of Enron Operations Corp. He is a director of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P. Cuba Wadlington, Jr. was named to the Partnership Policy Committee and to the Northern Border Management Committee on 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. Jerry L. Peters was named Chief Financial and Accounting Officer in July 1994. Mr. Peters has held several management positions with Northern Plains since 1985 and was elected Treasurer for Northern Plains in October 1998, Vice President of Finance for Northern Plains in July 1994, and director of Northern Plains in August 1994. Prior to joining Northern Plains in 1985, Mr. Peters was employed as a Certified Public Accountant by KPMG Peat Marwick, LLP. Daniel P. Whitty was appointed to the Audit Committee in December 1993. Mr. Whitty is an independent financial consultant. He is a director of Enron Equity Corp. and of EOTT Energy Corp., both subsidiaries of Enron, and the latter of which is the general partner of EOTT Energy Partners, L.P. He has served as a member of the Board of Directors of Methodist Retirement Communities Inc., and a Trustee of the Methodist Retirement Trust. Mr. Whitty was a partner at Arthur Andersen & Co. until his retirement on January 31, 1988. Gerald B. Smith was appointed to the Audit Committee in April 1994. He is Chief Executive Officer and co-founder of Smith, Graham & Co., a fixed income investment management firm, which was founded in 1990. He is a director of Pennzoil Quaker Company, M.D. Anderson Cancer Center Board of Visitors, and Rorento N.V.(Netherlands). From 1988 to 1990, he served as Senior Vice President and Director of Fixed Income and Chairman of the Executive Committee of Underwood Neuhaus & Co. Item 11. Executive Compensation The following table summarizes certain information regarding compensation paid or accrued during each of Northern Plains' last three fiscal years to the executive officers of the Partnership (the "Named Officers") for services performed in their capacities as executive officers of Northern Plains:
Summary Compensation Table All Other Annual Compensation Long-Term Compensation Compensation Other Securities Annual Restricted Underlying Bonus Compensation Stock Options/ Name & Position Year Salary (1) (2) Awards (3) SARs (#) (4) Larry L. DeRoin 1999 $266,367 $225,000 $ 7,773 $ - - $10,413 Chief Executive 1998 $256,067 $250,000 $ 7,200 $125,024 19,020 $ 6,380 Officer 1997 $247,333 $200,000 $11,908 $ - 30,570 $ - Jerry L. Peters 1999 $132,933 $100,000 $ 3,983 $ - 9,070 $ 5,260 Chief Financial and 1998 $123,225 $110,000 $ 1,214 $ 60,030 20,000 $ 1,956 Accounting Officer 1997 $118,750 $ 80,000 $ 1,200 $ - 11,430 $ - __________ (1) Mr. Peters elected to defer all or a portion of his bonus into the Enron Corp. Bonus Stock Option Program and/or the Northern Plains Natural Gas Company Phantom Unit Plan for 1997, 1998 and 1999. In 1999, Mr. Peters elected to receive Northern Plains phantom units in lieu of a portion of the cash bonus payment for 1998 under the Northern Plains Natural Gas Company Phantom Unit Plan. The total number of phantom units is 1,532 and the elected holding period for this grant is January 25, 2004. (2) Other Annual Compensation includes cash perquisite allowances. Also, Enron maintains three deferral plans for key employees under which payment of base salary, annual bonus, and long-term incentive awards may be deferred to a later specified date. Under the 1985 Deferral Plan, interest is credited on amounts deferred based on 150% of Moody's seasoned corporate bond yield index with a minimum rate of 12%, which for 1997, 1998 and 1999 was the minimum rate of 12%. No interest has been reported as Other Annual Compensation under the 1985 Deferral Plan for participating Named Officers because the crediting rates during 1997, 1998, and 1999, did not exceed 120% of the long-term Applicable Federal Rate of 14.38% in effect at the time the 1985 Deferral Plan was implemented. Beginning January 1, 1996, the 1994 Deferral Plan credits interest based on fund elections chosen by participants. Since earnings on deferred compensation invested in third-party investment vehicles, comparable to mutual funds, need not be reported, no interest has been reported as Other Annual Compensation under the 1994 Deferral Plan during 1997, 1998 and 1999. (3) The aggregate total of shares in unreleased Enron restricted stock holdings and their values as of December 31, 1999, for each of the Named Officers is: Mr. DeRoin, 4,382 shares valued at $194,452; Mr. Peters, 2,104 shares valued at $93,365. Dividend equivalents for all restricted stock awards accrue from date of grant and are paid upon vesting. (4) The amounts shown include the value of Enron Common Stock allocated to employees' special subaccounts under Enron's Employee Stock Ownership Plan, matching contributions to employees' Enron Corp. Savings Plan, and imputed income on life insurance benefits.
Stock Option Grants During 1999 The following table sets forth information with respect to grants of stock options pursuant to Enron's stock plans to the Named Officers reflected in the Summary Compensation Table. No stock appreciation rights were granted during 1999.
Individual Grants Potential Realizable % of Total Value at Assumed Options/SARs Exercise Annual Rate of Options/SARs Granted to or Base Stock Price Appreciation Granted Employees in Price Expiration For Option Term (4) Name (#) (1) Fiscal Year ($/Sh) Date 0% (3) 5% 10% Jerry L. Peters 9,070(2) 0.03% $32.6875 01/25/06 $ - $120,696 $281,272 (1) If a "change of control" (as defined in the Enron Stock Plans) were to occur before the options become exercisable and are exercised, the vesting described below will be accelerated and all such outstanding options shall be surrendered and the optionee shall receive a cash payment by Enron in an amount equal to the value of the surrendered options (as defined in the Enron Stock Plans). (2) Mr. Peters elected to receive stock options in lieu of a portion of his 1998 cash bonus payment. Stock options were 100% vested on the grant date. (3) An appreciation in stock price, which will benefit all stockholders, is required for optionees to receive any gain. A stock price appreciation of zero percent would render the option without value to the optionees. (4) The dollar amounts under these columns represent the potential realizable value of each grant of options assuming that the market price of Common Stock appreciates in value from the date of grant at the 5% and 10% annual rates prescribed by the SEC and therefore are not intended to forecast possible future appreciation, if any, of the price of Common Stock.
Aggregated Stock Option/SAR Exercises During 1999 and Stock Option/SAR Values as of December 31, 1999 The following table sets forth information with respect to the Named Officers concerning the exercise of Enron SARs and options during the last fiscal year and unexercised Enron options and SARs held as of the end of the fiscal year:
Number of Securities Underlying Unexercised Value of Unexercised Shares Options/SARs at In-the-Money Options/SARs Acquired on Value December 31, 1999 December 31, 1999 Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable Larry L. DeRoin - $ - 124,814 17,716 $3,127,054 $344,299 Jerry L. Peters 6,010 $116,033 51,786 7,764 $1,137,908 $142,186
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.
Estimated Current Credited Current Estimated Credited Years of Compensation Annual Benefit Years of Service Covered Payable Upon Service at Age 65 By Plans Retirement Mr. DeRoin 32.3 39.0 $266,367 $138,575 Mr. Peters 14.9 37.8 $132,933 $ 75,167 ________ NOTE: The estimated annual benefits payable are based on the straight life annuity form without adjustment for any offset applicable to a participant's retirement subaccount in Enron's ESOP.
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. Security Ownership of Certain Beneficial Owners and Management The following table sets forth the beneficial ownership of the voting securities of the Partnership as of February 15, 2000 by our executive officers, members of the Partnership Policy Committee and the Audit Committee and certain beneficial owners. Other than as set forth below, no person is known by the general partners to own beneficially more than 5% of the voting securities.
Amount and Nature of Beneficial Ownership Common Units Number Percent of Units1/ of Class Larry L. DeRoin 10,000 * 1111 South 103rd Street Omaha, NE 68124-1000 Jerry L. Peters 1,300 * 1111 South 103rd Street Omaha, NE 68124-1000 The Williams Companies, Inc.2/ 1,123,500 3.8 One Williams Center Tulsa, OK 74101-3288 Enron Corp.2/ 3,215,453 11.0 1400 Smith Street Houston, TX 77002 Duke Energy Corp.2/ 2,086,500 7.1 422 So. Church St. Charlotte, NC 88242-0001 ______________ * Less than 1%. 1/ All units involve sole voting and investment power. 2/ Indirect ownership through their subsidiaries.
Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934, as amended, requires certain of the Partnership's executive officers and members of the Partnership Policy Committee and any persons who own more than 10% of the Common Units to file reports of ownership and changes in ownership concerning the Common Units with the SEC and to furnish the Partnership with copies of all Section 16(a) forms they file. Based upon the Partnership's review of the Section 16(a) filings that have been received by the Partnership, the Partnership believes that all filings required to be made under Section 16(a) during 1999 were timely made, except that Cuba Wadlington, Jr. did not timely file his Initial Statements of Beneficial Ownership of Securities on Form 3. Item 13. Certain Relationships and Related Transactions We have extensive ongoing relationships with the general partners. Such relationships include the following: (i) Northern Plains provides, in its capacity as the operator of the pipeline system, certain tax, accounting and other information to the Partnership, and (ii) NBP Services, an affiliate of Enron, assists the Partnership in connection with the operation and management of the Partnership pursuant to the terms of an Administrative Services Agreement between the Partnership and NBP Services. In addition, Northern Border Pipeline has extensive ongoing relationships with the general partners and certain of their affiliates and with affiliates of TransCanada. For example, Northern Plains, a general partner and affiliate of Enron, has acted (since 1980), and will continue to act, as the operator of the pipeline system pursuant to the terms of an operating agreement between Northern Plains and Northern Border Pipeline. Enron Engineering & Construction Company ("EE&CC"), an affiliate of Enron, provided project management for the construction of The Chicago Project pursuant to the terms of a project management agreement between Northern Plains and EE&CC. In addition, as of February 1, 2000: * Enron North America Corp., an affiliate of Enron, is one of our transportation customers, and is obligated to pay 5.3% of our annual cost of service; * TransCanada Gas Services, an affiliate of TransCanada PipeLines Limited, is one of our transportation customers and is currently obligated to pay 10.8% of our annual cost of service pursuant to a transportation contract wherein TransCanada Gas Services acts as the agent of its parent, TransCanada; * Transco, an affiliate of Williams, is one of our transportation customers and is currently obligated to pay 0.8% of our annual cost of service; 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 our annual cost of service. The Partnership Policy Committee, whose members are designated by our three general partners, establishes the business policies of the Partnership. We have three representatives on the Northern Border Management Committee, each of whom votes a portion of the Partnership's 70% interest on the Northern Border Management Committee. These representatives are also designated by our general partners. Our interests could conflict with the interests of our general partners or their affiliates, and in such case the members of the Partnership Policy Committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest. Northern Border Pipeline's interests could conflict with the our interest or the interest of TransCanada and their affiliates, and in such case our representatives on the Northern Border Management Committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in the best interest of Northern Border Pipeline. Our fiduciary duty as a general partner of Northern Border Pipeline may restrict the Partnership from taking actions that might be in our best interest but in conflict with the fiduciary duty that our representatives or we owe to TransCanada. Unless otherwise provided for in a partnership agreement, the laws of Delaware and Texas generally require a general partner of a partnership to adhere to fiduciary duty standards under which it owes its partners the highest duties of good faith, fairness and loyalty. Similar rules apply to persons serving on the Partnership Policy Committee or the Northern Border Management Committee. Because of the competing interests identified above, our Partnership Agreement and the partnership agreement for Northern Border Pipeline contain provisions that modify certain of these fiduciary duties. For example: * The Partnership Agreement states that the general partners, their affiliates and their officers and directors will not be liable for damages to the Partnership, its limited partners or their assignees for errors of judgment or for any acts or omissions if the general partners and such other persons acted in good faith. * The Partnership Agreement allows the general partners and the Partnership Policy Committee to take into account the interests of parties in addition to our interest in resolving conflicts of interest. * The Partnership Agreement provides that the general partners will not be in breach of their obligations under the Partnership Agreement or their duties to us or our unitholders if the resolution of a conflict is fair and reasonable to us. The latitude given in the Partnership Agreement in connection with resolving conflicts of interest may significantly limit the ability of a unitholder to challenge what might otherwise be a breach of fiduciary duty. * The Partnership Agreement provides that a purchaser of Common Units is deemed to have consented to certain conflicts of interest and actions of the general partners and their affiliates that might otherwise be prohibited and to have agreed that such conflicts of interest and actions do not constitute a breach by the general partners of any duty stated or implied by law or equity. * Our Audit Committee will, at the request of a general partner or a member of the Partnership Policy Committee, review conflicts of interest that may arise between a general partner and its affiliates (or the member of the Partnership Policy Committee designated by it), on the one hand, and the unitholders or us, on the other. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to us. * We entered into an amendment to the partnership agreement for Northern Border Pipeline that relieves us and TC PipeLines, their affiliates and their transferees from any duty to offer business opportunities to Northern Border Pipeline, with certain exceptions. We are required to indemnify the members of the Partnership Policy Committee and general partners, their affiliates and their respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than one of the general partners) not opposed to, the Partnership's best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful. PART IV 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 F-1. (a)(3) Exhibits * 3.1 Form of Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (Exhibit 3.1 No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *10.1 Form of Amended and Restated Agreement of Limited Partnership For Northern Border Intermediate Limited Partnership (Exhibit 10.1 to Form S-1). *10.2 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (Exhibit 10.2 to Form S-1). *10.3 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.4 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (Exhibit 10.4 to Form S-1). *10.5 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.5.1 Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K")). *10.6 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *10.7 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). *10.7.1 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 the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")). *10.7.2 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 the Partnership's Annual Report on Form 10-K for the year ended December 31, 1994). *10.7.3 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). *10.7.4 Amended Exhibit A to Northern Border Pipeline Company U.S. Shipper Service Agreement effective April l, 1998 (Exhibit 10.10.4 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1997 ("1997 10-K")). *10.8 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.9 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K). *10.10 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). *10.10.1 Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.11 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.12 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). *10.13 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 Form S-3, Registration Statement No. 333-40601 ("Form S-3")). *10.14 Form of Credit Agreement among Northern Border Partners, L.P., Canadian Imperial Bank of Commerce, as Agent and Lenders (as defined therein) dated as of November 6, 1997 (Exhibit 10(d) to Amendment No. 1 to Form S-3). *10.15 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). *10.16 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). *10.17 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). *10.18 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). *10.19 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). *10.20 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). *10.21 Indenture, dated as of August 17, 1999, between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, as trustee. (Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement, Registration No. 333-88577 ("Form S-4")). *10.22 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). *10.23 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 of Form S-4). 10.24 Credit Agreement, dated as of December 15, 1999, between Northern Border Partners, L.P. and SunTrust Bank, Atlanta. 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership; Northern Border Pipeline Company; NBP Energy Pipelines, L.L.C.; Black Mesa Holdings, Inc.; Black Mesa Pipeline, Inc.; Black Mesa Pipeline Operations L.L.C.; Black Mesa Technologies, Inc. and Black Mesa Technologies Services L.L.C. 23.01 Consent of Arthur Andersen LLP. 27 Financial Data Schedule. *99.1 Northern Plains Natural Gas Company Phantom Unit Plan (Exhibit 99.1 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 1999. 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 28th day of March, 2000. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) By: LARRY L. DEROIN Larry L. DeRoin Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. Signature Title Date LARRY L. DEROIN Chief Executive Officer and March 28, 2000 Larry L. DeRoin Chairman of the Partnership Policy Committee (Principal Executive Officer) STANLEY C. HORTON Member of Partnership March 28, 2000 Stanley C. Horton Policy Committee CUBA WADLINGTON, JR. Member of Partnership March 28, 2000 Cuba Wadlington, Jr. Policy Committee JERRY L. PETERS Chief Financial and March 28, 2000 Jerry L. Peters Accounting Officer NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS Page No. Consolidated Financial Statements Report of Independent Public Accountants F-2 Consolidated Balance Sheet - December 31, 1999 and 1998 F-3 Consolidated Statement of Income - Years Ended December 31, 1999, 1998 and 1997 F-4 Consolidated Statement of Cash Flows - Years Ended December 31, 1999, 1998 and 1997 F-5 Consolidated Statement of Changes in Partners' Capital - Years Ended December 31, 1999, 1998 and 1997 F-6 Notes to Consolidated Financial Statements F-7 through F-20 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 Partners, L.P.: We have audited the accompanying consolidated balance sheet of Northern Border Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, cash flows and changes in partners' capital for each of the three years in the period ended December 31, 1999. 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 generally accepted auditing standards. 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 Partners, L.P. and Subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Omaha, Nebraska, January 20, 2000 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (In Thousands)
December 31, ASSETS 1999 1998 CURRENT ASSETS Cash and cash equivalents $ 22,927 $ 41,042 Accounts receivable 24,946 19,077 Related party receivables 5,292 2,470 Materials and supplies, at cost 4,410 4,189 Under recovered cost of service 3,068 2,781 Total current assets 60,643 69,559 TRANSMISSION PLANT Property, plant and equipment 2,410,133 2,345,700 Less: Accumulated provision for depreciation and amortization 664,777 615,224 Property, plant and equipment, net 1,745,356 1,730,476 INVESTMENTS AND OTHER ASSETS Investment in unconsolidated affiliate 31,895 -- Other 25,543 25,731 Total investments and other assets 57,438 25,731 Total assets $1,863,437 $1,825,766 LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Current maturities of long-term debt $ 183,617 $ 2,805 Accounts payable 8,279 46,032 Accrued taxes other than income 26,608 20,140 Accrued interest 17,608 12,462 Accumulated provision for rate refunds 2,317 -- Total current liabilities 238,429 81,439 LONG-TERM DEBT, net of current maturities 848,369 974,027 MINORITY INTERESTS IN PARTNERS' CAPITAL 250,450 253,031 RESERVES AND DEFERRED CREDITS 10,920 9,843 COMMITMENTS AND CONTINGENCIES (NOTE 7) PARTNERS' CAPITAL General Partners 10,305 10,148 Common Units 504,964 401,388 Subordinated Units -- 95,890 Total partners' capital 515,269 507,426 Total liabilities and partners' capital $1,863,437 $1,825,766 The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME (In Thousands, Except Per Unit Amounts)
Year Ended December 31, 1999 1998 1997 OPERATING REVENUES Operating revenues $321,280 $217,592 $238,543 Provision for rate refunds (2,317) -- (39,969) Operating revenues, net 318,963 217,592 198,574 OPERATING EXPENSES Operations and maintenance 53,451 44,770 37,418 Depreciation and amortization 54,493 43,536 40,172 Taxes other than income 30,952 22,012 22,836 Regulatory credit -- (8,878) -- Operating expenses 138,896 101,440 100,426 OPERATING INCOME 180,067 116,152 98,148 INTEREST EXPENSE Interest expense 67,807 49,923 34,520 Interest expense capitalized (98) (19,001) (3,660) Interest expense, net 67,709 30,922 30,860 OTHER INCOME Allowance for equity funds used during construction 101 10,237 1,400 Other income, net 4,112 2,622 6,589 Other income 4,213 12,859 7,989 MINORITY INTERESTS IN NET INCOME 35,568 30,069 22,253 NET INCOME TO PARTNERS $ 81,003 $ 68,020 $ 53,024 NET INCOME PER UNIT $ 2.70 $ 2.27 $ 1.97 NUMBER OF UNITS USED IN COMPUTATION 29,347 29,345 26,392 The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (In Thousands)
Year Ended December 31, 1999 1998 1997 CASH FLOWS FROM OPERATING ACTIVITIES: Net income to partners $ 81,003 $ 68,020 $ 53,024 Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 54,546 43,551 40,179 Minority interests in net income 35,568 30,069 22,253 Provision for rate refunds 2,317 -- 40,403 Refunds to shippers -- -- (52,630) Allowance for equity funds used during construction (101) (10,237) (1,400) Regulatory credit -- (9,105) -- Changes in components of working capital (1,482) (19,243) 17,101 Other 1,517 794 691 Total adjustments 92,365 35,829 66,597 Net cash provided by operating activities 173,368 103,849 119,621 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (102,270) (652,194) (152,658) Acquisition and consolidation of businesses (31,895) -- 3,374 Other -- -- (586) Net cash used in investing activities (134,165) (652,194) (149,870) CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions General and limited partners (73,160) (68,876) (58,957) Minority Interests (38,149) (18,362) (30,080) Contributions received from Minority Interests -- 66,900 24,300 Issuance of partnership interests, net -- 7,554 90,987 Issuance of long-term debt, net 313,526 498,000 209,000 Retirement of long-term debt (270,805) (2,523) (128,665) Proceeds received upon termination of interest rate forward agreements 12,896 -- -- Long-term debt financing costs (1,626) (63) (969) Repayment of note payable -- -- (10,000) Net cash provided by (used in) financing activities (57,318) 482,630 95,616 NET CHANGE IN CASH AND CASH EQUIVALENTS (18,115) (65,715) 65,367 Cash and cash equivalents-beginning of year 41,042 106,757 41,390 Cash and cash equivalents-end of year $ 22,927 $ 41,042 $ 106,757 Changes in components of working capital: Accounts receivable $ (8,691) $ (1,628) $ 2,283 Materials and supplies (221) 269 460 Accounts payable (3,897) (11,830) 14,562 Accrued taxes other than income 6,468 (368) (772) Accrued interest 5,146 1,696 203 Over/under recovered cost of service (287) (7,382) 365 Total $ (1,482) $ (19,243) $ 17,101 The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (In Thousands)
Total General Common Subordinated Partners' Partners Units Units Capital Partners' Capital at December 31, 1996 $ 8,212 $303,777 $ 98,597 $410,586 Net income to partners 1,061 39,331 12,632 53,024 Issuance of partnership interests, net 1,921 95,133 (979) 96,075 Distributions paid (1,179) (43,654) (14,124) (58,957) Partners' Capital at December 31, 1997 10,015 394,587 96,126 500,728 Net income to partners 1,359 52,077 14,584 68,020 Issuance of partnership interests, net 151 7,457 (54) 7,554 Distributions paid (1,377) (52,733) (14,766) (68,876) Partners' Capital at December 31, 1998 10,148 401,388 95,890 507,426 Subordinated Units converted to Common Units -- 95,890 (95,890) -- Net income to partners 1,710 79,293 -- 81,003 Distributions paid (1,553) (71,607) -- (73,160) Partners' Capital at December 31, 1999 $10,305 $504,964 $ -- $515,269 The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Partners, L.P., a Delaware limited partnership, through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, a Delaware limited partnership, collectively referred to herein as the Partnership, owns a 70% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline). The remaining 30% general partner interest in Northern Border Pipeline is owned by TC PipeLines Intermediate Limited Partnership (TC PipeLines). Effective May 28, 1999, TransCanada Border PipeLine Ltd. and TransCan Northern Ltd., both of which are wholly-owned subsidiaries of TransCanada PipeLines Limited (TransCanada), transferred their combined 30% ownership interest in Northern Border Pipeline to TC PipeLines in connection with an initial public offering of limited partner interests in TC PipeLines, LP. Black Mesa Holdings, Inc. and Black Mesa Pipeline Operations, L.L.C. (collectively Black Mesa), Black Mesa Technologies, Inc. (BMT) and NBP Energy Pipelines, L.L.C. (NBP Energy) are wholly-owned subsidiaries of the Partnership. Northern Plains Natural Gas Company (Northern Plains), a wholly- owned subsidiary of Enron Corp. (Enron), Pan Border Gas Company (Pan Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border Pipeline Company (Northwest Border), a wholly- owned subsidiary of The Williams Companies, Inc. serve as the General Partners of the Partnership and collectively own a 2% general partner interest in the Partnership. 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 General Partners or their affiliates also own Common Units representing, in the aggregate, an effective 14.5% limited partner interest in the Partnership at December 31, 1999 (see Note 6). The Partnership is managed by or is under the direction of a committee (Partnership Policy Committee) consisting of one person appointed by each General Partner. The members appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting interest on the Partnership Policy Committee. The Partnership has entered into an administrative services agreement with NBP Services Corporation (NBP Services), a wholly-owned subsidiary of Enron, pursuant to which NBP Services provides certain administrative services for the Partnership and is reimbursed for its direct and indirect costs and expenses. Northern Border Pipeline is a general partnership, formed in 1978, pursuant to the Texas Uniform Partnership Act. 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 the Partnership (one representative appointed by each of the General Partners of the Partnership) and one representative from TC PipeLines. The Partnership's representatives selected by Northern Plains, Pan Border and Northwest Border have 35%, 22.75% and 12.25%, respectively, of the voting interest on the Northern Border Pipeline Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. 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, 1999, 1998 and 1997, Northern Border Pipeline reimbursed the Operator approximately $29.7 million, $30.0 million and $24.6 million, respectively. Additionally, an Enron affiliate was responsible for project management on Northern Border Pipeline's expansion and extension of its pipeline from near Harper, Iowa to a point near Manhattan, Illinois (The Chicago Project). The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline's partners are to be made on a pro rata basis according to each partner's capital account balance. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Black Mesa, through a wholly-owned subsidiary, owns a 273-mile, 18-inch diameter coal slurry pipeline that originates at a coal mine in Kayenta, Arizona and ends at the 1,500 megawatt Mohave Power Station located in Laughlin, Nevada. NBP Energy owns a 39% common membership interest in Bighorn Gas Gathering, L.L.C. (Bighorn). Bighorn owns a gas gathering system in a portion of the Powder River Basin located in Campbell and Sheridan Counties, Wyoming (see Note 3). 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) Principles of Consolidation and Use of Estimates The consolidated financial statements include the assets, liabilities and results of operations of the Partnership and its majority-owned subsidiaries. The Partnership operates through a subsidiary limited partnership of which the Partnership is the sole limited partner and the General Partners are the sole general partners. The 30% ownership of Northern Border Pipeline by TC PipeLines, formerly held by the TransCanada subsidiaries, is accounted for as a minority interest. All significant intercompany items have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles 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, 1999 and 1998, Northern Border Pipeline has reflected regulatory assets of approximately $12.1 million and $12.8 million, respectively, in Other Assets on the consolidated balance sheet. During the construction of The Chicago Project, Northern Border Pipeline placed certain 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. As required by the certificate of public convenience and necessity issued by the FERC, Northern Border Pipeline recorded a regulatory credit of approximately $8.9 million in 1998, which deferred the cost of service of these new facilities. Northern Border Pipeline is allowed to recover the regulatory asset that resulted from the cost of service deferral from its shippers over a ten-year period commencing with the in-service date of The Chicago Project. At December 31, 1999 and 1998, the unrecovered regulatory asset related to The Chicago Project facilities was approximately $8.2 million and $8.9 million, respectively. The remaining regulatory asset at both December 31, 1999 and 1998, of approximately $3.9 million, relates to costs recorded from previous expansions and extensions of the pipeline system. Northern Border Pipeline is seeking recovery of these amounts in its current rate proceeding (see Note 7). (C) Revenue Recognition Northern Border Pipeline bills the cost of service 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 that period in accordance with the FERC tariff to the estimated billing is accumulated, including carrying charges thereon, and is either billed to or credited back to the shippers. Revenues reflect actual cost of service. An amount equal to differences between billing estimates and the actual cost of service, including carrying charges, is reflected in current assets or current liabilities. (D) Income Taxes Income taxes are the responsibility of the partners and are not reflected in these financial statements. However, the Northern Border Pipeline tariff establishes the method of accounting for and calculating income taxes and requires Northern Border Pipeline to reflect in its cost of service 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 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 $316 million and $300 million at December 31, 1999 and 1998, respectively, and are primarily related to accelerated depreciation and other plant-related differences. (E) Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments. (F) Property, Plant and Equipment and Related Depreciation and Amortization Property, plant and equipment is stated at original cost. In December 1998, Northern Border Pipeline placed into service the facilities for The Chicago Project. At December 31, 1999 and 1998, respectively, approximately $3.5 million and $37.4 million of project costs incurred but not paid for The Chicago Project were recorded in accounts payable and property, plant and equipment on the consolidated balance sheet and were excluded from the change in accounts payable and capital expenditures for property, plant and equipment, net on the consolidated statement of cash flows. Maintenance and repairs are charged to operations in the period incurred. The provision for depreciation and amortization of Northern Border Pipeline's transmission line is an integral part of its FERC tariff. The effective depreciation rate applied to Northern Border Pipeline's transmission plant in 1999, 1998, and 1997 was 2.0%, 2.5%, and 2.5%, respectively. In 2000, the depreciation rate increases to 2.3% and is scheduled to continue to increase gradually on an annual basis until it reaches 3.2% in 2002. Composite rates are applied to all other functional groups of property having similar economic characteristics. The depreciation rate for transmission plant is being reviewed in Northern Border Pipeline's current rate proceeding (see Note 7). 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. (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. The rate employed for the equity component of AFUDC is the equity rate of return stated in Northern Border Pipeline's FERC tariff. (H) Risk Management Financial instruments are used in the management of the Partnership's 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. (I) Investment in Unconsolidated Affiliate Investment in unconsolidated affiliate is accounted for by the equity method. 3. ACQUISITIONS On May 31, 1997, the Partnership exchanged 125,357 Common Units for all of the outstanding common stock of BMT (formerly Williams Technologies, Inc.). Effective with the acquisition of BMT, which was recorded using the purchase method of accounting, the Partnership increased its ownership position in Black Mesa from the 60.5% acquired in 1996 to 71.75% and began to reflect Black Mesa, including Black Mesa's minority ownership interests, in the Partnership's consolidated financial statements. Prior to this time, the Partnership's investment in Black Mesa was accounted for using the equity method. On December 29, 1997, the Partnership acquired the remaining minority ownership interest in Black Mesa through the exchange of 46,956 Common Units and cash. The following is a summary of the effects of the acquisition of BMT and consolidation of Black Mesa on the Partnership's consolidated financial position in 1997 (amounts in thousands): Cash $ 3,374 Net property, plant and equipment 18,350 Other current and noncurrent assets 10,159 Long-term debt, including current maturities (23,520) Other liabilities (3,090) Minority interests (185) Common Units $ 5,088 On December 21, 1999, NBP Energy acquired a 39% common membership interest in Bighorn Gas Gathering, L.L.C. (Bighorn) for approximately $31.9 million. The remaining common membership interests in Bighorn are owned by CMS Field Services, Inc. (CFS) (50%) and Continental Holdings Company (1%), both of which are wholly-owned subsidiaries of CMS Energy Corporation, and Enron Midstream Services, L.L.C. (10%), a wholly-owned subsidiary of Enron. In addition to the common membership interest, which represents approximately 93.8% of the capitalization, Bighorn has two non- voting classes of shares, each of which represents approximately 3.1% of the total capitalization, that are currently owned by CFS. NBP Energy has contracted to purchase 80% of one of those classes of shares ("A shares") for $20.8 million. The payment is due on or before June 15, 2000. To secure its obligation to acquire the A shares, NBP Energy has pledged all of its common membership interest to CFS. Both of the non-voting classes of shares are subject to certain distribution preferences as well as limitations based on the cumulative number of wells connected to the Bighorn system at the end of each calendar year. These shares will receive an income allocation equal to the cash distributions received and are not entitled to any other allocations of income or distributions of cash. Ownership of these shares does not affect the amount of capital contributions that are required to be made to the operations of Bighorn by the common membership interests. 4. SHIPPER SERVICE AGREEMENTS Operating revenues are collected pursuant to the FERC tariff which directs that Northern Border Pipeline collect its cost of service through firm transportation service agreements (firm service agreements). Northern Border Pipeline's FERC tariff provides an opportunity to recover all operations and maintenance costs of the pipeline, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Billings for the firm service agreements are based on contracted volumes to determine the allocable share of the cost of service and are not dependent upon the percentage of available capacity actually used. Northern Border Pipeline's 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 contracts with numerous other shippers as a result of its self-implementing blanket transportation authority. Revenues received from the interruptible service contracts are credited to the cost of service reducing the billings for the firm service agreements. Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.) Inc. (PAGUS), is presently obligated for approximately 25.7% of the cost of service through three firm service agreements which expire in October 2003. Financial guarantees exist through October 2001 for approximately 16.3% of the total cost of service related to the contracted capacity of PAGUS, including 10.5% guaranteed by Northern Natural Gas Company, a wholly-owned subsidiary of Enron. The remaining cost of service 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 contracts for the years ended December 31, 1999, 1998 and 1997 were $76.6 million, $87.3 million and $86.8 million, respectively. Shippers affiliated with the partners of Northern Border Pipeline have firm service agreements representing approximately 17.3% of the cost of service. These firm service agreements extend for various terms with termination dates that range from October 2003 to May 2009. Operating revenues from the affiliated firm service agreements and interruptible service contracts for the years ended December 31, 1999, 1998 and 1997 were $52.5 million, $22.4 million and $20.2 million, respectively. Black Mesa's operating revenue is derived from a pipeline transportation agreement (Pipeline Agreement) with the coal supplier for the Mohave Power Station that expires in December 2005. The pipeline is the sole source of fuel for the Mohave plant. Under the terms of the Pipeline Agreement, Black Mesa receives a monthly demand payment, a per ton commodity payment and a reimbursement for certain other expenses. 5. CREDIT FACILITIES AND LONG-TERM DEBT Detailed information on long-term debt is as follows:
December 31, (In thousands) 1999 1998 Northern Border Pipeline Senior notes - average 8.43%, due from 2000 to 2003 $ 250,000 $250,000 Pipeline credit agreement Term loan, due 2002 439,000 484,500 Five-year revolving credit facility -- 127,500 Senior notes - 7.75%, due 2009 200,000 -- Unamortized proceeds from termination of interest rate forward agreements 12,397 -- Unamortized debt discount (938) -- Northern Border Partners, L.P. Credit agreements - due 2000 114,500 95,000 Black Mesa 10.7% Note agreement, due quarterly to 2004 17,027 19,832 Total 1,031,986 976,832 Less: Current maturities of long-term debt 183,617 2,805 Long-term debt $ 848,369 $974,027
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 (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 consolidated balance sheet and is being amortized against interest expense over the life of the 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 $639 million. At December 31, 1999 and 1998, Northern Border Pipeline had outstanding interest rate swap agreements with notional amounts of $40 million and $90 million, respectively. The agreement outstanding at December 31, 1999, will terminate in November 2001. Under the agreements, 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, 1999 and 1998, 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 agreements, was 6.73% and 6.17% at December 31, 1999 and 1998, respectively. In November 1997, the Partnership entered into a credit agreement (Partnership Credit Agreement) with certain financial institutions to borrow up to an aggregate principal amount of $175 million under a revolving credit facility. The Partnership Credit Agreement is to be used for interim funding of the Partnership's required capital contributions to Northern Border Pipeline for construction of The Chicago Project. The amount available under the Partnership Credit Agreement is reduced to the extent the Partnership issues additional limited partner interests to fund the Partnership's required capital contributions for The Chicago Project in excess of $25 million. The public offering of Common Units discussed in Note 6 reduced the amount available under the Partnership Credit Agreement to $104 million. With the conversion of Northern Border Pipeline's three-year revolving credit facility to a term loan, the maturity date of the Partnership Credit Agreement is November 2000. In December 1999, the Partnership entered into a one-year credit agreement (1999 Credit Agreement) with a single financial institution to borrow up to an aggregate principal amount of $25 million under a revolving line of credit. The 1999 Credit Agreement is to be used for capital contributions to Northern Border Pipeline or for acquisitions by the Partnership. If the Partnership Credit Agreement is terminated, the 1999 Credit Agreement automatically terminates. Both the Partnership Credit Agreement and the 1999 Credit Agreement permit the Partnership 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. The Partnership is required to pay a commitment fee on the aggregate undrawn principal amount under the facilities. At December 31, 1999 and 1998, the average interest rate on the credit agreements was 6.78% and 6.04%, respectively. Interest paid, net of amounts capitalized, during the years ended December 31, 1999, 1998 and 1997 was $62.5 million, $28.7 million and $31.6 million, respectively. Aggregate repayments of long-term debt required for the next five years are as follows: $184 million, $44 million, $521 million, $69 million and $2 million for 2000, 2001, 2002, 2003 and 2004, respectively. 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, 1999 and 1998, respectively, $132 million and $173 million of partners' capital of Northern Border Pipeline could be distributed. The Partnership Credit Agreement restricts incurrence of senior indebtedness by the Partnership and requires the maintenance of a ratio of debt to total capital, excluding the debt of consolidated subsidiaries, of no more than 35 percent. 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 senior notes due from 2000 to 2003 was approximately $273 million and $287 million at December 31, 1999 and 1998, respectively. The estimated fair value of the senior notes due 2009 was approximately $201 million at December 31, 1999. The estimated fair value of the Black Mesa note agreement was approximately $18 million and $23 million at December 31, 1999 and 1998, respectively. At December 31, 1999 and 1998, the estimated fair value which would be payable to terminate the interest rate swap agreements, taking into account current interest rates, was approximately $1 million and $3 million, respectively. The Partnership presently intends to maintain the current schedule of maturities for the senior notes, the Black Mesa note agreement and the interest rate swap agreements that will result in no gains or losses on their respective repayment. The carrying value of the Pipeline Credit Agreement, Partnership Credit Agreement and 1999 Credit Agreement approximates the fair value since the interest rates are periodically adjusted to current market conditions. 6. PARTNERS' CAPITAL At December 31, 1999, partners' capital consisted of 29,347,313 Common Units representing an effective 98% limited partner interest in the Partnership (including 14.5% held collectively by the General Partners or their affiliates) and a 2% general partner interest. At December 31, 1998, partners' capital consisted of 22,927,313 Common Units representing an effective 76.6% limited partner interest in the Partnership; 6,420,000 Subordinated Units representing an effective 21.4% limited partner interest in the Partnership (including 14.5% held collectively by the General Partners or their affiliates); and a 2% general partner interest. Effective January 19, 1999, the 6,420,000 outstanding Subordinated Units were converted into an equal number of Common Units since the Partnership Policy Committee determined the subordination period ended as a result of satisfying the criteria set forth in the partnership agreement. In January 1998 and December 1997, the Partnership sold, through an underwritten public offering, 225,000 Common Units and 2,750,000 Common Units, respectively. The units sold in 1998 resulted from the underwriters exercise of an over- allotment option to purchase a limited number of additional Common Units. In conjunction with the issuance of the additional Common Units, the Partnership's general partners made capital contributions to the Partnership to maintain a 2% general partner interest in accordance with the partnership agreements. The net proceeds, of the public offering and the general partners' capital contributions, of approximately $7.6 million and $90.9 million in 1998 and 1997, respectively, were used by the Partnership to fund a portion of the capital contributions to Northern Border Pipeline for construction of The Chicago Project. The Partnership will make distributions to its partners with respect to each calendar quarter in an amount equal to 100% of its Available Cash. "Available Cash" generally consists of all of the cash receipts of the Partnership adjusted for its cash disbursements and net changes to cash reserves. Available Cash will generally be distributed 98% to the Unitholders and 2% to the General Partners. The holders of Units are entitled to receive the minimum quarterly distribution of $0.55 per Unit per quarter if and to the extent there is sufficient Available Cash. Partnership income is allocated to the General Partners and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated 100% to the General Partners. As an incentive, the General Partners' percentage interest in quarterly distributions is increased after certain specified target levels are met (see Note 9). At the time the quarterly distributions exceed $0.605 per Unit, the General Partners receive 15% of the excess. As the quarterly distributions are increased above $0.715 per Unit, the General Partners receive increasing percentages in excess of the targets reaching a maximum of 50% of the excess of the highest target level. 7. COMMITMENTS AND CONTINGENCIES Regulatory Proceedings 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 is approximately $30 million. A number of Northern Border Pipeline's shippers and competing pipelines have 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 the proposed changes were implemented with subsequent billings subject to refund. At December 31, 1999, Northern Border Pipeline recorded a $2.3 million provision for rate refunds. The June order and a subsequent clarification issued by the FERC in August 1999 set for hearing not only Northern Border Pipeline's proposed changes but also several issues raised by intervenors including the appropriateness of Northern Border Pipeline's cost of service tariff, rolled-in rate treatment of The Chicago Project, capital project cost containment mechanism amount recorded for The Chicago Project, depreciation schedule and creditworthiness standards. A procedural schedule has been established which provides for the hearing to commence in July 2000. At this time, the Partnership can give no assurance as to the outcome on any of these issues. 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). If approved and constructed, Project 2000 would afford shippers on the expanded and extended pipeline system access to industrial gas consumers in northern Indiana. As a result of permanent releases of capacity between several existing and project shippers originally included in the October 1998 application, Northern Border Pipeline amended its application with the FERC in March 1999. Numerous parties filed to intervene in this proceeding. Several parties protested this application asking that the FERC deny Northern Border Pipeline's request for rolled-in rate treatment for the new facilities and that Northern Border Pipeline be required to solicit indications of interest from existing shippers for capacity releases that would possibly eliminate the construction of certain new facilities. In September 1999, the FERC issued a policy statement on certification and pricing of new construction projects. The policy statement announces a preference for establishing the transportation charge for newly constructed facilities on a separate, stand-alone basis. This reverses the existing presumption in favor of rolled-in pricing once certain conditions were met. In response to the policy statement, Northern Border Pipeline amended its application with the FERC in December 1999. The December amended application reflects estimated capital expenditures of approximately $94 million. Several parties renewed their protests on this latest amended application. While Northern Border Pipeline cannot predict when the FERC will issue its final order on the Project 2000 amended application, Northern Border Pipeline has requested such action by March 15, 2000. In January 1998, Northern Border Pipeline filed an application with the FERC to acquire the linepack gas required to operate the pipeline from the shippers and to provide the linepack gas in the future for its operations. The cost of the linepack gas acquired in 1998, which is included in rate base, totaled approximately $11.7 million. In August 1997, Northern Border Pipeline received FERC approval of a Stipulation and Agreement (Stipulation) filed on October 15, 1996 to settle its November 1995 rate case. In accordance with the terms of the Stipulation, Northern Border Pipeline's allowed equity rate of return was reduced from the requested 14.25% to 12.75% for the period June 1, 1996 to September 30, 1996 and to 12% thereafter. Additionally, Northern Border Pipeline agreed to reduce its transmission plant depreciation rate retroactively to June 1, 1996, and agreed to implement a $31 million settlement adjustment mechanism (SAM) when The Chicago Project was placed in service. The SAM effectively reduces the allowed return on rate base. In October 1997, Northern Border Pipeline used a combination of cash on hand and borrowings on a revolving credit facility to pay refunds to its shippers of approximately $52.6 million. Also as agreed to in the Stipulation, Northern Border Pipeline implemented a capital project cost containment mechanism (PCCM). The purpose of the PCCM was to limit Northern Border Pipeline's ability to include cost overruns on The Chicago Project in rate base and to provide incentives to Northern Border Pipeline for cost underruns. The PCCM amount is determined by comparing the final cost of The Chicago Project to the budgeted cost. The Stipulation required the budgeted cost for The Chicago Project, which had been initially filed with the FERC for approximately $839 million, to be adjusted for the effects of inflation and project scope changes, as defined in the Stipulation. Such adjusted budgeted cost of The Chicago Project has been estimated to be $897 million, with the final construction cost estimated to be $894 million. Thus, Northern Border Pipeline's notification to the FERC and its shippers in June 1999 reflects the conclusion that there is a $3 million addition to rate base as a result of the PCCM. The Stipulation required that the calculation of the PCCM be reviewed by an independent national accounting firm. The independent accountants completed their examination of Northern Border Pipeline's PCCM calculation in October 1999. The independent accountants concluded Northern Border Pipeline had complied, in all material respects, with the requirements of the Stipulation related to the PCCM. Northern Border Pipeline filed its June 1999 report and the independent accountants' report in its current rate case proceeding discussed previously. Testimony filed by the FERC staff and intervenors in the current rate case proceeding has proposed changes to the PCCM computation, which would result in rate base reductions ranging from $32 million to $43 million. Although the Partnership believes the computation has been made in accordance with the terms of the Stipulation, it is unable to predict at this time whether any adjustments will be required. Should developments in the rate case result in rate base reductions, a non-cash charge to write down transmission plant would result and such charge could be material to the operating results of the Partnership. Environmental Matters The Partnership 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. The Partnership believes that the resolution of these issues will not have a material adverse impact on the Partnership's results of operations or financial position. 8. CAPITAL EXPENDITURE AND INVESTMENT PROGRAM Total capital expenditures for 2000 are estimated to be $25 million. This includes approximately $10 million for Project 2000 (see Note 7) and approximately $15 million for renewals and replacements of the existing facilities. Funds required to meet the capital expenditures for 2000 are anticipated to be provided primarily from internal sources. In addition to the commitment to acquire additional ownership in Bighorn for $20.8 million (see Note 3), the Partnership is required to fund 39% of Bighorn's operations. For 2000, the capital contribution to Bighorn is estimated to be approximately $10 million. Funds required to be invested in Bighorn are anticipated to be provided primarily from debt borrowings. 9. NET INCOME PER UNIT Net income per unit is computed by dividing net income, after deduction of the General Partners' allocation, by the weighted average number of Units outstanding. The General Partners' allocation is equal to an amount based upon their combined 2% general partner interest, adjusted to reflect an amount equal to incentive distributions. Net income per unit was determined as follows:
(In thousands, except Year ended December 31, per unit amounts) 1999 1998 1997 Net income to partners $81,003 $68,020 $53,024 Net income allocated to General Partners (1,620) (1,359) (1,061) Adjustment to reflect incentive distributions (90) -- -- (1,710) (1,359) (1,061) Net income allocable to Units $79,293 $66,661 $51,963 Weighted average units outstanding 29,347 29,345 26,392 Net income per unit $ 2.70 $ 2.27 $ 1.97
10. ACCOUNTING PRONOUNCEMENTS In 1998, the Financial Accounting Standards Board (FASB) 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 must 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. A company may implement SFAS No. 133 as of the beginning of any fiscal quarter after issuance, however, the statement cannot be applied retroactively. The Partnership and its subsidiaries do not plan to adopt SFAS No. 133 early. The Partnership believes that SFAS No. 133 will not have a material impact on its financial position or results of operations. 11. QUARTERLY FINANCIAL DATA (Unaudited)
(In thousands, except Operating Operating NetIncome Net Income per unit amounts) Revenues, net Income to Partners per Unit 1999 First Quarter $78,895 $45,048 $21,631 $0.72 Second Quarter 78,012 44,342 20,561 0.69 Third Quarter 79,046 44,815 19,357 0.65 Fourth Quarter 83,010 45,862 19,454 0.65 1998 First Quarter $52,820 $25,650 $14,933 $0.50 Second Quarter 53,782 27,717 16,410 0.55 Third Quarter 54,442 29,722 18,042 0.60 Fourth Quarter 56,548 33,063 18,635 0.62
12. SUBSEQUENT EVENTS On January 18, 2000, the Partnership declared an increase in the quarterly cash distribution from $0.61 per Unit to $0.65 per Unit for the period October 1, 1999 through December 31, 1999. The distribution is payable February 14, 2000, to the General Partners and to the Unitholders of record at January 31, 2000. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE To Northern Border Partners, L.P.: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements of Northern Border Partners, L.P. and Subsidiaries included in this Form 10-K and have issued our report thereon dated January 20, 2000. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Partners, L.P. and Subsidiaries listed in Item 14 of Part IV of this Form 10-K is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Omaha, Nebraska, January 20, 2000 SCHEDULE II NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 (In Thousands)
Column A Column B Column C Column D Column E Additions Deductions Balance at Charged to Charged For Purpose For Beginning Costs and to Other Which Reserves Balance at Description of Year Expenses Accounts Were Created End of Year Reserve for regulatory issues 1999 $6,726 $650 $-- $-- $7,376 1998 $6,726 $ -- $-- $-- $6,726 1997 $5,953 $773 $-- $-- $6,726
UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _______________________ EXHIBITS TO F O R M 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 Commission file number: 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 93-1120873 (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 1400 Smith Street, Houston, Texas 77002-7369 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: 713-853-6161 ___________________ EXHIBIT INDEX * 3.1 Form of Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (Exhibit 3.1 No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *10.1 Form of Amended and Restated Agreement of Limited Partnership For Northern Border Intermediate Limited Partnership (Exhibit 10.1 to Form S-1). *10.2 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (Exhibit 10.2 to Form S-1). *10.3 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.4 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (Exhibit 10.4 to Form S-1). *10.5 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.5.1 Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K")). *10.6 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *10.7 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). *10.7.1 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 the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")). *10.7.2 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 the Partnership's Annual Report on Form 10-K for the year ended December 31, 1994). *10.7.3 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). *10.7.4 Amended Exhibit A to Northern Border Pipeline Company U.S. Shipper Service Agreement effective April l, 1998 (Exhibit 10.10.4 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1997 ("1997 10-K")). *10.8 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.9 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K). *10.10 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). *10.10.1 Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.11 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.12 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). *10.13 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 Form S-3, Registration Statement No. 333-40601 ("Form S-3")). *10.14 Form of Credit Agreement among Northern Border Partners, L.P., Canadian Imperial Bank of Commerce, as Agent and Lenders (as defined therein) dated as of November 6, 1997 (Exhibit 10(d) to Amendment No. 1 to Form S-3). *10.15 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). *10.16 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). *10.17 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). *10.18 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). *10.19 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). *10.20 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). *10.21 Indenture, dated as of August 17, 1999, between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, as trustee. (Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement, Registration No. 333-88577 ("Form S-4")). *10.22 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). *10.23 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 of Form S-4). 10.24 Credit Agreement, dated as of December 15, 1999, between Northern Border Partners, L.P. and SunTrust Bank, Atlanta. 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership; Northern Border Pipeline Company; NBP Energy Pipelines, L.L.C.; Black Mesa Holdings, Inc.; Black Mesa Pipeline, Inc.; Black Mesa Pipeline Operations L.L.C.; Black Mesa Technologies, Inc. and Black Mesa Technologies Services L.L.C. 23.01 Consent of Arthur Andersen LLP. 27 Financial Data Schedule. *99.1 Northern Plains Natural Gas Company Phantom Unit Plan (Exhibit 99.1 to Form S- 8, Registration No. 333-66949). *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. EX-10 2 MATERIAL CONTRACTS EXHIBIT 10.24 CREDIT AGREEMENT between NORTHERN BORDER PARTNERS, L.P., Borrower and SUNTRUST BANK, ATLANTA, Lender $25,000,000 Revolving Credit Facility December 15, 1999 PREPARED BY HAYNES AND BOONE, L.L.P. CREDIT AGREEMENT THIS CREDIT AGREEMENT is entered into as of December 15, 1999, between NORTHERN BORDER PARTNERS, L.P., a Delaware limited partnership ("Borrower"), and SUNTRUST BANK, ATLANTA ("Lender"). Borrower has requested from Lender a $25,000,000 revolving line of credit - subject to certain limitations below - for the purpose of making capital contributions to NBPC, whether directly or through the Guarantor or for acquisitions or capital investments by the Borrower, either directly or indirectly through its Subsidiaries. ACCORDINGLY, for adequate and sufficient consideration, Borrower and Lender agree as follows: SECTION 1 DEFINITIONS AND TERMS. 1.1 Definitions. Capitalized terms used in the Loan Documents shall have the meanings assigned to such terms in Schedule 1. 1.2 References to the CIBC Credit Agreement. Throughout this agreement, references will be made to the CIBC Credit Agreement. References to the CIBC Credit Agreement - including (without limitation) the defined terms, representations, warranties, covenants, and agreements contained therein: (i) are intended to be for Lender's continuing benefit; and (ii) shall be references to such agreement as it is in effect on the date hereof, regardless of whether the CIBC Credit Agreement, or any term or provision contained therein, is hereafter amended or modified, non-compliance therewith is hereafter waived, or the CIBC Credit Agreement hereafter expires by its terms or is terminated. 1.3 Time References. Unless otherwise specified, in the Loan Documents (a) time references (e.g., 10:00 a.m.) are to CST, and (b) in calculating a period from one date to another, the word "from" means "from and including" and the word "to" or "until" means "to but excluding." 1.4 Other References. Unless otherwise specified, in the Loan Documents (a) where appropriate, the singular includes the plural and vice versa, and words of any gender include each other gender, (b) heading and caption references may not be construed in interpreting provisions, (c) monetary references are to currency of the United States of America, (d) section, paragraph, annex, schedule, exhibit, and similar references are to the particular Loan Document in which they are used, (e) references to "telecopy," "facsimile," "fax," or similar terms are to facsimile or telecopy transmissions, (f) references to "including" mean including without limiting the generality of any description preceding that word, (g) the rule of construction that references to general items that follow references to specific items are limited to the same type or character of those specific items is not applicable in the Loan Documents, (h) references to any Person include that Person's heirs, personal representatives, successors, trustees, receivers, and permitted assigns, (i) references to any Law include every amendment or supplement to it, rule and regulation adopted under it, and successor or replacement for it, and (j) references to any Loan Document or other document include every renewal and extension of it, amendment and supplement to it, and replacement or substitution for it. 1.5 Accounting Principles. Unless otherwise specified, in the Loan Documents (a) GAAP determines all accounting and financial terms and compliance with financial covenants, (b) GAAP in effect on the date of this agreement determines compliance with financial covenants, (c) otherwise, all accounting principles applied in a current period must be comparable in all material respects to those applied during the preceding comparable period, and (d) while Borrower has any consolidated Subsidiaries (i) all accounting and financial terms and compliance with reporting covenants must be on a consolidated basis, as applicable, and (ii) compliance with financial covenants must be in accordance with the compliance requirements specified within the CIBC Agreement. SECTION 2 COMMITMENT. 2.1 Facility. Subject to the provisions in the Loan Documents, Lender agrees to extend credit to Borrower under the Facility which Borrower may borrow, repay, and reborrow under this agreement subject to the following conditions: (a) Each Borrowing may only be $100,000 or a greater integral multiple of $100,000 if a Base-Rate Borrowing or $1,000,000 or a greater integral multiple of $100,000 if a LIBOR Borrowing or a Quoted-Rate Borrowing; (b) Each Borrowing may only occur on a Business Day on or after the Closing Date and before the Termination Date; and (c) The aggregate of all Borrowings may never exceed $25,000,000 at any time. 2.2 Borrowing Procedure. Borrower may request a Borrowing by making or delivering a Borrowing Request (that may be telephonic if promptly confirmed in writing on the same date as the Borrowing Request) to Lender, which is irrevocable and binding on Borrower. Each Borrowing Request shall state the Type, amount, and Interest Period for each Borrowing, and must be received by Lender no later than (i) (if applicable) 10:00 a.m. CST (11:00 a.m. EST) on the second Business Day before the Borrowing Date for any LIBOR Borrowing, or (ii) 8:30 a.m. CST (9:30 a.m. EST) on the Borrowing Date for any Base-Rate Borrowing or Quoted-Rate Borrowing. 2.3 Borrowing Notices. Each Borrowing Request (whether telephonic or written) constitutes a representation and warranty by Borrower that as of the Borrowing Date all of the conditions precedent in Section 6 have been satisfied. 2.4 Termination. Borrower may - upon giving at least two Business Days prior written and irrevocable notice to Lender - terminate all or part of the Facility as follows: (a) Each partial termination of the Facility must be in an amount of not less than $5,000,000 or a greater integral multiple of $1,000,000. (b) At the time of any such termination, Borrower shall pay to Lender all accrued and unpaid fees under this agreement, the interest attributable to the amount of that termination, and any related Funding Loss. Any part of the Commitment that is terminated may not be reinstated. SECTION 3 TERMS OF PAYMENT. 3.1 Note and Payments. (a) Note. Principal Debt under the Facility is evidenced by the Note. (b) Payment. Borrower must make each payment and prepayment on the Obligation to Lender's principal office in Atlanta, Georgia in immediately available funds by 10:00 a.m. CST (11:00 a.m. EST) on the day due; otherwise, those funds continue to accrue interest as if they were received on the next Business Day. 3.2 Interest and Principal Payments. (a) Interest. Accrued interest on each LIBOR Borrowing or Quoted-Rate Borrowing is due and payable on the last day of its respective Interest Period and on the Termination Date. Accrued interest on each Base-Rate Borrowing is due and payable: (i) on the date of any prepayment, (ii) on the last day of each calendar month (commencing on the first of those dates following the Closing Date), (iii) on the date any such Base-Rate Borrowing is converted to a LIBOR Borrowing under Section 3.9, and (iv) on the Termination Date. (b) Principal. The Principal Debt is due and payable on the Termination Date. Before the occurrence of the Termination Date, Borrower may prepay, without penalty and in whole or in part, the Principal Debt, so long as (i) each voluntary partial prepayment must be in a principal amount not less than $1,000,000 or a greater integral multiple of $100,000, (ii) Borrower shall give prior written and irrevocable notice to Lender (A) at least three Business Days before any prepayment of a Quoted-Rate Borrowing, (B) at least two Business Days before any prepayment of a LIBOR Borrowing or (C) at least one Business Day before any prepayment of a Base-Rate Borrowing, and (iii) Borrower shall pay any related Funding Loss upon demand. Conversions under Section 3.9 are not prepayments. 3.3 Interest Options. Borrowings under the Facility shall bear interest at an annual rate equal to the lesser of either (i) the Maximum Rate, or (ii) the Base Rate, Quoted Rate or LIBOR plus the Applicable Margin (in each case as designated or deemed designated by Borrower), as the case may be. Each change in the Base Rate and Maximum Rate is effective, without notice to Borrower or any other Person, upon the effective date of change. 3.4 Quotation of Rates. Borrower may call Lender before delivering a Borrowing Request to receive an indication of the interest rates then in effect, but the indicated rates do not bind Lender or affect the interest rate that is actually in effect when Borrower makes a Borrowing Request on the Borrowing Date. 3.5 Default Rate. If permitted by Law, all past-due Principal Debt, and past-due interest accruing on any of the foregoing bears interest from the date due (stated or by acceleration) at the Default Rate until paid, regardless whether payment is made before or after entry of a judgment. 3.6 [Intentionally Deleted]. 3.7 Interest Calculations. Interest will be calculated on the basis of actual number of days (including the first day but excluding the last day) elapsed but computed as if each calendar year consisted of 360 days (unless the calculation would result in an interest rate greater than the Maximum Rate, or in the case of interest on Base-Rate Borrowings in which event interest will be calculated on the basis of a year of 365 or 366 days, as the case may be). All interest rate determinations and calculations by Lender are conclusive and binding absent manifest error. 3.8 Interest Periods. When Borrower requests any LIBOR Borrowing or Quoted-Rate Borrowings, Borrower may elect the applicable interest period (each an "Interest Period"), which may be, at Borrower's option: (i) for a LIBOR Borrowing one, two, or three months; and (ii) for Quoted-Rate Borrowings 30, 60, or 90 days. Borrower's selection of such Interest Periods shall be subject to Section 11.1 and the following conditions, (u) no Interest Period may extend beyond the Maturity Date; (v) the initial Interest Period for a Quoted-Rate Borrowing commences on the applicable Borrowing Date; (w) the initial Interest Period for a LIBOR Borrowing commences on the applicable Borrowing Date or conversion date, and each subsequent Interest Period applicable to any such LIBOR Borrowing commences on the day when the next preceding applicable Interest Period expires; (x) if any Interest Period for a LIBOR Borrowing begins on a day for which no numerically corresponding Business Day in the calendar month at the end of the Interest Period exists, then the Interest Period ends on the last Business Day of that calendar month; (y) if Borrower is required to pay any portion of a LIBOR Borrowing or Quoted-Rate Borrowing before the end of its Interest Period in order to comply with the payment provisions of the Loan Documents, Borrower shall also pay any related Funding Loss; and (z) no more than four Interest Periods may be in effect at one time. 3.9 Conversions. Subject to the dollar limits of Section 2.1 and provided that Borrower may not convert to or select a new Interest Period for a LIBOR Borrowing or a Quoted- Rate Borrowing at any time when a Default or Potential Default exists, Borrower may (a) convert a Borrowing of one Type into a Borrowing of another Type; and (b) continue a LIBOR Borrowing or Quoted-Rate Borrowing for a new Interest Period. Such a continuation may be made by telephonic request to Lender no later than 10:00 a.m. CST (11:00 a.m. EST) on the second Business Day before the conversion date or the last day of the Interest Period, as the case may be (for conversion to a LIBOR Borrowing, or election of a new Interest Period), and no later than 8:30 a.m. CST (9:30 a.m. EST) on the last day of the Interest Period (for conversion to a Base-Rate Borrowing or Quoted-Rate Borrowing). Borrower shall provide a Conversion Notice to Lender no later than two days after the date of the conversion or election. A request for conversion may be made telephonically if promptly confirmed to Lender in writing on the same date as the Conversion Notice. Absent Borrower's telephonic request for conversion or election of a new Interest Period or if a Default or Potential Default exists, then, a LIBOR Borrowing or a Quoted- Rate Borrowing shall be deemed converted to a Base-Rate Borrowing effective when the applicable Interest Period expires. 3.10 Order of Application. If a Default or Potential Default exists or if Borrower fails to give direction, any payment (including proceeds from the exercise of any Rights) shall be applied in the following order: (i) to all fees and expenses for which Lender has not been paid or reimbursed in accordance with the Loan Documents (and if such payment is less than all unpaid or unreimbursed fees and expenses, then the payment shall be paid against unpaid and unreimbursed fees and expenses in the order of incurrence or due date); (ii) to accrued interest on the Principal Debt; then (iii) to the Principal Debt (but Lender agrees to apply proceeds in an order that will minimize any Funding Loss). 3.11 [Intentionally Deleted.] 3.12 Basis Unavailable or Inadequate for LIBOR. If, on or before any date when LIBOR is to be determined for a Borrowing, Lender reasonably determines that the basis for determining the applicable rate is not available or Lender determines that the resulting rate does not accurately reflect the cost to Lender of making or converting Borrowings at that rate for the applicable Interest Period, then Lender shall promptly notify Borrower of that determination (which is conclusive and binding on Borrower absent manifest error) and the applicable Borrowing shall bear interest at the Base Rate. Until Lender notifies Borrower that those circumstances no longer exist, Lender's commitment under this agreement to make, or to convert to, LIBOR Borrowings, as the case may be, are suspended. 3.13 Taxes. Any Taxes payable by Lender or ruled (by a Tribunal) payable by Lender in respect of this agreement or any other Loan Document shall, if permitted by Law, be paid by Borrower, together with interest and penalties, if any, except for Taxes payable on or measured by the overall net income of Lender (including, but not limited to, franchise taxes to the extent they are calculated based on such net income). Lender shall notify Borrower and deliver to Borrower a certificate setting forth in reasonable detail the calculation of the amount of Taxes payable, which certificate is conclusive and binding (absent manifest error), and Borrower shall pay that amount to Lender for its account or the account of Lender, as the case may be within five Business Days after demand. If Lender subsequently receives a refund of the Taxes paid to it by Borrower, then Lender shall promptly pay the refund to Borrower. 3.14 Change in Laws. If any Law makes it unlawful for Lender to make or maintain LIBOR Borrowings or Quoted-Rate Borrowings, then Lender shall promptly notify Borrower, (a) as to undisbursed funds, that requested Borrowing shall be made as a Base-Rate Borrowing, and (b) as to any outstanding Borrowing (i) if maintaining the Borrowing until the last day of the applicable Interest Period is unlawful, the Borrowing shall be converted to a Base-Rate Borrowing as of the date of notice, in which event Borrower will be required to pay any related Funding Loss, or (ii) if not prohibited by Law, the Borrowing shall be converted to a Base-Rate Borrowing as of the last day of the applicable Interest Period, or (iii) if any conversion will not resolve the unlawfulness, Borrower shall promptly prepay the Borrowing, without penalty but with related Funding Loss. 3.15 Funding Loss. BORROWER SHALL INDEMNIFY LENDER AGAINST, AND PAY TO IT UPON DEMAND, ANY FUNDING LOSS INCURRED BY LENDER. WHEN LENDER DEMANDS THAT BORROWER PAY ANY FUNDING LOSS, LENDER SHALL DELIVER TO BORROWER A CERTIFICATE WITHIN 120 DAYS OF THE INCURRENCE THEREOF, SETTING FORTH IN REASONABLE DETAIL THE BASIS FOR IMPOSING THE FUNDING LOSS AND THE CALCULATION OF THE AMOUNT, WHICH CALCULATION IS CONCLUSIVE AND BINDING ABSENT MANIFEST ERROR. THE PROVISIONS OF AND UNDERTAKINGS AND INDEMNIFICATION IN THIS SECTION SURVIVE THE SATISFACTION AND PAYMENT OF THE OBLIGATION AND TERMINATION OF THIS AGREEMENT. SECTION 4 COMMITMENT FEE. From and after the Effective Date, Borrower agrees to pay in accordance with Section 3.1 a commitment fee to Lender, as it accrues on the last day of each March, June, September, and December - commencing on December 31, 1999 - and on the Termination Date. Each payment of such fee is equal to the following, determined for the calendar quarter (or portion of a calendar quarter commencing on the date of this agreement or ending on such later Termination Date) preceding and including the date it is due; from the Effective Date until the Termination Date, the product of (i) 0.10%, times (ii) the unadvanced principal amount of the Principal Debt during the applicable quarter or portion of it, times (iii) a fraction with the number of days in the applicable quarter or portion of it as the numerator and 360 as the denominator. SECTION 5 GUARANTY. In consideration of the intercompany advances which may be made by Borrower to Guarantor, Borrower shall cause Guarantor to unconditionally guarantee the full payment and performance of the Obligation by execution of a Guaranty. SECTION 6 CONDITIONS PRECEDENT. Lender is not obligated to fund the initial Borrowing unless (a) Lender has received all of the items described in Schedule 6; (b) Lender and its counsel have completed due diligence satisfactory to each, including without limitation, a review of financial projections of Borrower, including statements of income, balance sheets, and cash flow statements; (c) Lender has received and reviewed to its satisfaction the Compliance Certificate (with all attachments) delivered by Borrower to the "Agent" and "Lender" as required under the CIBC Credit Agreement for the quarter ended September 30, 1999, certified by a senior financial officer of Borrower. In addition, Lender is not obligated to fund (as opposed to continue or convert) any Borrowing unless on the applicable Borrowing Date (and after giving effect to the requested Borrowing): (w) Lender timely receives a Borrowing Request or Conversion Notice, as the case may be; (x) all of the representations and warranties in the Loan Documents and the CIBC Credit Agreement are true and correct in all material respects (unless they speak to a specific date or are based on facts which have changed by transactions contemplated or expressly permitted by this agreement); (y) no Material Adverse Event, Default, or Potential Default exists; and (z) no limitation in Section 2.1 is exceeded. Each Borrowing Request, however delivered, constitutes Borrower's representation and warranty that the conditions in clauses (w) through (z) above are satisfied. Upon Lender's request, Borrower shall deliver to Lender evidence substantiating any of the matters in the Loan Documents that are necessary to enable Borrower to qualify for the Borrowing. Each condition precedent in this agreement (including, without limitation, those on Schedule 6) is material to the transactions contemplated by this agreement, and time is of the essence with respect to each condition precedent. SECTION 7 REPRESENTATIONS AND WARRANTIES. Borrower represents and warrants to Lender as follows: 7.1 Corporate Existence, Good Standing and Authority. Each Company is duly organized, validly existing, and in good standing under the Laws of its jurisdiction of organization. Except where not a Material Adverse Event, each Company is duly qualified to transact business and is in good standing as a foreign legal entity in each jurisdiction where the nature and extent of its business and properties require due qualification and good standing. Each Company possesses the requisite authority and power to conduct its business as is now being conducted and to own and operate its assets. 7.2 Authorization and Contravention The execution and delivery by each Company of each Loan Document to which it is a party and the performance by it of its obligations under those Loan Documents (a) are within its partnership power, (b) have been duly authorized by all necessary partnership action, (c) require no action by or filing with any Tribunal (except any action or filing that has been taken or made on or before the Effective Date), (d) did not violate any provision of its partnership agreement, charter or bylaws and (e) do not violate any provision of Law applicable to it or any Material Agreement to which it is a party. 7.3 Binding Effect Upon execution and delivery by all parties to it, each Loan Document will constitute a legal and binding obligation of each Company party to it, enforceable against it in accordance with that Loan Document's terms except as that enforceability may be limited by Debtor Laws and general principles of equity. 7.4 CIBC Credit Agreement Each representation and warranty in the CIBC Credit Agreement as pertains to Borrower, or its Subsidiaries, are true and correct (each of which representation and warranty is incorporated herein by reference together with related definitions and ancillary provisions) and would be true and correct if each reference therein to "Obligation," "this agreement," "Notes," "Loan Document," "Material Adverse Effect," "Loans," "Default," "Event of Default" were, respectfully, references to Obligation, this agreement, Note, Loan Documents, Material Adverse Event, Borrowings, Potential Default, or a Default. 7.5 No Default. No Default or Potential Default has occurred and is continuing. 7.6 Purpose. Borrower will use the proceeds of the Facility for capital contributions to NBPC, whether directly or through the Guarantor or for acquisitions or capital investments by the Borrower, either directly or indirectly through its Subsidiaries. 7.7 Financials and Existing Debt. The Current Financials were prepared in accordance with GAAP and present fairly, in all material respects, the Borrower's consolidated financial condition, results of operations, and cash flows as of, and for the portion of the fiscal year ending on their dates (subject only to normal year-end adjustments for interim statements). Except for transactions directly related to, specifically contemplated by, or expressly permitted by the Loan Documents or as disclosed in the reports filed by Borrower pursuant to the Securities and Exchange Act of 1934 and delivered to Lender after the date of the Current Financials, no material adverse changes have occurred in the Borrower's consolidated financial condition from that shown in the Current Financials. 7.8 Full Disclosure. If a Material Adverse Event has occurred, each material fact or condition relating thereto has been disclosed in writing to Lender. All information (taken as a whole) previously furnished to Lender in connection with the Loan Documents was - and all information furnished in the future (taken as a whole) by Borrower to Lender will be - true and accurate in all material respects or based on reasonable estimates on the date the information is stated or certified. 7.9 Year 2000 Compliance. Borrower has implemented its plan (the "Y2K Plan") insuring that Borrower's and each Subsidiary's software and hardware systems are Year 2000 Compliant and Ready to the extent that errors or failures that may result in such software or hardware systems will not result in a Material Adverse Event. As used herein, "Year 2000 Compliant and Ready" means that the Borrower's and each Subsidiary's hardware and software systems with respect to the operation of their business and their general business plan will: (i) handle date information involving any and all dates before, during and/or after January 1, 2000, including accepting input, providing output and performing date calculations in whole or in part; (ii) operate accurately without interruption on and in respect of any and all dates before, during and/or after January 1, 2000 and without any change in performance; (iii) respond to and process two digit year input without creating any ambiguity as to the century; and (iv) store and provide date input information without creating any ambiguity as to the century. SECTION 8 COVENANTS. For so long as Lender is committed to lend under this agreement and until the Obligation has been fully paid and performed, Borrower covenants and agrees that: 8.1 CIBC Credit Agreement. It will, for Lender's benefit, timely and properly observe, perform, and otherwise comply with each agreement and covenant (each of which is incorporated herein by reference together with related definitions and ancillary provisions) pertaining to it under the CIBC Credit Agreement as each such agreement and covenant is in effect on the date hereof, regardless of whether any such agreement or covenant is hereafter amended or modified, non-compliance therewith is hereafter waived by the "Agent" or any "Lender" under the CIBC Credit Agreement or any such loan document hereafter expires by its terms or is terminated, as if each reference therein to "Lender," "Agent," "General Partner," "this Agreement," "Loan Document," "Indebtedness," "Intermediate Partnership," "the Notes," "Material Adverse Effect," and "the Required Lenders," are, respectfully, references to Lender, Lender, General Partner, this agreement, Loan Documents, Debt, Guarantor, Note, Material Adverse Event, and Lender. In confirmation, but not replacement or limitation, of, the foregoing agreement, Borrower shall: (a) In accordance with Section 7.1.7 of the CIBC Credit Agreement, ensure that the claims and rights of Lender against it under the Loan Documents will not be subordinate to, and will rank at all times at least pari passu with, all other Debt of the Borrower. The Borrower will not amend, modify or supplement any credit agreement, notes, or other document relating to its Debt in any manner which would make them materially more onerous to Borrower than the provisions of this Agreement and the Note as in effect from time to time; (b) In accordance with Section 7.2.2(e) of the CIBC Credit Agreement, not, and will not permit the Guarantor to, create, incur, assume, or suffer to exist any Lien upon any of its property, revenues or assets, whether now owned or hereafter acquired, except Liens securing Borrower's or Guarantor's Debt, if, and only if, concurrently with the creation of such Lien, the Debt - including, but not limited to, the Obligation - is equally and ratably secured by such Liens; and (c) In accordance with Section 7.2.1 of the CIBC Credit Agreement, not, and will not permit the Guarantor to, create, incur, assume or suffer to exist or to otherwise become or be liable in respect of any Debt, other than, the Debt described in such Section7.2.1; provided, however, that this agreement - and the Principal Debt advanced under the terms of this agreement - comprises the Debt referred to in such Section 7.2.1(d). No further Debt may be incurred by Borrower or Guarantor under such Section. 8.2 Certain Items Furnished. In addition to, and without limiting the generality, of the foregoing, Borrower shall furnish to Lender: (a) Financial Statements. Copies of each financial statement, compliance certificate, report, notice and information provided to the "Agent" or "Lenders" under the CIBC Credit Agreement, as and when provided to them; (b) Notice. As soon as possible, but in any event within 10 Business Days after becoming aware - of (i) the existence and, if requested by Lender, status of any Litigation that, if determined adversely to any Company, would be a Material Adverse Event, (ii) any change in any material fact or circumstance represented or warranted by any Company in any Loan Document that could be reasonably expected to result in a Material Adverse Event, or (iii) a Default or Potential Default, specifying the nature thereof and what action the Companies have taken, are taking, or propose to take; and (c) Other Information. Promptly when requested by Lender, such information (not otherwise required to be furnished under this agreement) about any Company's business affairs, assets, and liabilities, and any opinions, certifications, and documents, in addition to those mentioned herein. 8.3 Expenses. Promptly after demand Borrower shall pay (a) all costs, fees, and expenses paid or incurred by Lender incident to any Loan Document (including, without limitation, the reasonable fees and expenses of Lender's counsel in connection with the negotiation, preparation, delivery, and execution of the Loan Documents and any related amendment, waiver, or consent) and (b) all costs and expenses incurred by Lender in connection with the enforcement of the obligations of any Company under the Loan Documents or the exercise of any Rights under the Loan Documents (including, without limitation, allocated costs of in-house counsel, other reasonable attorneys' fees, and court costs), all of which are part of the Obligation, bearing interest, (if not paid within ten Business Days after demand accompanied by an invoice describing the costs, fees, and expenses in reasonable detail) at the Default Rate until paid. SECTION 9 DEFAULT. The term "Default" means the occurrence of any one or more of the following: 9.1 Payment of Obligation. The failure or refusal of Borrower to pay any portion of the Obligation, as the same becomes due in accordance with the terms of the Loan Documents. 9.2 Covenants. Any Company's failure or refusal to punctually and properly perform, observe, and comply with any covenant (other than covenants to pay the Obligation) applicable to it; provided, that, with respect to Sections 8.2(a), 8.2(c), and 8.3, no such Default shall occur until such Company's failure or refusal to punctually and properly perform, observe, and comply with any of such covenants shall continue for 30 days after the first occurrence of such failure or refusal. 9.3 Debtor Relief. Borrower or any other Company shall not be Solvent, or any Company (a) fails to pay its Debts generally as they become due, (b) voluntarily seeks, consents to, or acquiesces in the benefit of any Debtor Law, or (c) becomes a party to or is made the subject of any proceeding provided for by any Debtor Law, other than as a creditor or claimant, that could suspend or otherwise adversely affect the Rights of Lender granted in the Loan Documents (unless, in the event such proceeding is involuntary, the petition instituting same is dismissed within 60 days after its filing). 9.4 Misrepresentation. Any representation or warranty made by any Company in any Loan Document at any time proves to have been incorrect when made. 9.5 Cross-Default. The occurrence of a "Default" or "Event of Default" under the CIBC Credit Agreement - regardless of whether such "Default" or "Event of Default" is thereafter waived. The occurrence of a "Guaranty Default" or "Guaranty Event of Default" under the CIBC Guaranty - regardless of whether such "Guaranty Default" or "Guaranty Event of Default" is thereafter waived. 9.6 Validity and Enforceability. This agreement, the Note, the Guaranty, or any other Loan Document ceases to be in full force and effect in any material respect or is declared to be null and void or its validity or enforceability is contested in writing by any Company party to it or any Company party to it denies in writing that it has any further liability or obligations under it. SECTION 10 RIGHTS AND REMEDIES. 10.1 Remedies Upon Default. (a) Debtor Relief. If a Default exists under Section 9.3, the commitment to extend credit under this agreement automatically terminates, and the entire unpaid balance of the Obligation automatically becomes due and payable without any action of any kind whatsoever. (b) Other Defaults. If any Default exists, Lender may do any one or more of the following: (i) if the maturity of the Obligation has not already been accelerated under Section 9.3, declare the entire unpaid balance of all or any part of the Obligation immediately due and payable, whereupon it is due and payable; (ii) terminate the commitment of Lender to extend credit under this agreement; (iii) reduce any claim to judgment; and (iv) exercise any and all other legal or equitable Rights afforded by the Loan Documents, by applicable Laws, or in equity. (c) Offset. If a Default exists, to the extent permitted by applicable Law, Lender may exercise the Rights of offset and banker's lien against each and every account and other property, or any interest therein, which any Company may now or hereafter have with, or which is now or hereafter in the possession of, Lender to the extent of the full amount of the Obligation owed to Lender. 10.2 Company Waivers. To the extent permitted by Law, Borrower and Guarantor each waive presentment and demand for payment, protest, notice of intention to accelerate, notice of acceleration, and notice of protest and nonpayment, and each agree that its liability with respect to all or any part of the Obligation is not affected by any renewal or extension in the time of payment of all or any part of the Obligation, by any indulgence, or by any release or change in any security for the payment of all or any part of the Obligation. 10.3 Performance by Lender. If any Company's covenant, duty, or agreement is not performed in accordance with the terms of the Loan Documents, Lender may, while a Default exists, at its option, perform or attempt to perform that covenant, duty, or agreement on behalf of that Company (and any amount expended by Lender in its performance or attempted performance is payable by the Companies, jointly and severally, to Lender on demand, becomes part of the Obligation, and bears interest at the Default Rate from the date of Lender's expenditure until paid). However, Lender does not assume and shall never have, except by its express written consent, any liability or responsibility for the performance of any Company's covenants, duties, or agreements. 10.4 Course of Dealing. The acceptance by Lender of any partial payment on the Obligation is not a waiver of any Default then existing. No waiver by Lender of any Default is a waiver of any other then-existing or subsequent Default. No delay or omission by Lender in exercising any Right under the Loan Documents impairs that Right or is a waiver thereof or any acquiescence therein, nor will any single or partial exercise of any Right preclude other or further exercise thereof or the exercise of any other Right under the Loan Documents or otherwise. 10.5 Cumulative Rights. All Rights available to Lender under the Loan Documents are cumulative of and in addition to all other Rights granted to Lender at law or in equity, whether or not the Obligation is due and payable and whether or not Lender has instituted any suit for collection, foreclosure, or other action in connection with the Loan Documents. 10.6 Certain Proceedings. Borrower shall promptly execute and deliver, or cause the execution and delivery of, all applications, certificates, instruments, registration statements, and all other documents and papers Lender requests in connection with the obtaining of any consent, approval, registration, qualification, permit, license, or authorization of any Tribunal or other Person necessary or appropriate for the effective exercise of any Rights under the Loan Documents. Because Borrower agrees that Lender's remedies at Law for failure of Borrower to comply with the provisions of this section would be inadequate and that failure would not be adequately compensable in damages, Borrower agrees that the covenants of this section may be specifically enforced. 10.7 Expenditures by Lender. Any sums spent by Lender in the exercise of any Right under any Loan Document is payable to Lender within five Business Days after demand, becomes part of the Obligation, and bears interest at the Default Rate from the date spent until the date repaid. SECTION 11 MISCELLANEOUS. 11.1 Nonbusiness Days. Any payment or action that is due under any Loan Document on a non-Business Day may be delayed until the next-succeeding Business Day (but interest shall continue to accrue on any applicable payment until payment is in fact made) unless the payment concerns a LIBOR Borrowing or Quoted-Rate Borrowing, in which case if the next-succeeding Business Day is in the next calendar month, then such payment shall be made on the next-preceding Business Day. 11.2 Communications. Unless otherwise specifically provided, whenever any Loan Document requires or permits any consent, approval, notice, request, or demand from one party to another, communication must be in writing (which may be by fax) to be effective and shall be deemed to have been given (a) if by fax, when transmitted to the appropriate fax number (and all communications sent by fax must be confirmed promptly thereafter by telephone; but any requirement in this parenthetical shall not affect the date when the fax shall be deemed to have been delivered), (b) if by mail, on the third Business Day after it is enclosed in an envelope and properly addressed, stamped, sealed, and deposited in the appropriate official postal service, or (c) if by any other means, when actually delivered. Until changed by notice pursuant to this agreement, the address (and fax number) for Borrower is stated beside its respective signature to this agreement and for Lender is stated beside its name on the signature page to this agreement. 11.3 Form and Number of Documents. The form, substance, and number of counterparts of each writing to be furnished under this agreement must be satisfactory to Lender and its counsel. 11.4 Exceptions to Covenants. No Company may take or fail to take any action that is permitted as an exception to any of the covenants contained in any Loan Document if that action or omission would result in the breach of any other covenant contained in any Loan Document. 11.5 Survival. All covenants, agreements, undertakings, representations, and warranties made in any of the Loan Documents survive all closings under the Loan Documents and, except as otherwise indicated, are not affected by any investigation made by any party. 11.6 Governing Law. Unless otherwise stated in any Loan Document, the Laws of the State of New York and of the United States of America govern the Rights and duties of the parties to the Loan Documents and the validity, construction, enforcement, and interpretation of the Loan Documents. 11.7 Invalid Provisions. Any provision in any Loan Document held to be illegal, invalid, or unenforceable is fully severable; the appropriate Loan Document shall be construed and enforced as if that provision had never been included; and the remaining provisions shall remain in full force and effect and shall not be affected by the severed provision. Lender and each Company party to the affected Loan Document agree to negotiate, in good faith, the terms of a replacement provision as similar to the severed provision as may be possible and be legal, valid, and enforceable. 11.8 Amendments, and Waivers. (a) Conflicts. Any conflict or ambiguity between the terms and provisions of this agreement and terms and provisions in any other Loan Document is controlled by the terms and provisions of this agreement. (b) Waivers. No course of dealing or any failure or delay by Lender, or any of their respective Representatives with respect to exercising any Right of Lender under this agreement operates as a waiver thereof. A waiver must be in writing and signed by Lender to be effective, and a waiver will be effective only in the specific instance and for the specific purpose for which it is given. 11.9 Multiple Counterparts. Any Loan Document may be executed in a number of identical counterparts (including, at Lender's discretion, counterparts or signature pages executed and transmitted by fax) with the same effect as if all signatories had signed the same document. All counterparts must be construed together to constitute one and the same instrument. 11.10 Parties Bound. Each Loan Document binds and inures to the parties to it, any intended beneficiary of it, and each of their respective successors and permitted assigns. No Company may assign or transfer any Rights or obligations under any Loan Document without first obtaining Lender's consent, and any purported assignment or transfer without Lender's consent is void. Lender may transfer, pledge, assign, sell any participation in, or otherwise encumber its portion of the Obligation, and may disclose information pertaining to the Borrower for such purposes. Any assignment will be made with Borrower's consent (which consent shall not be unreasonably withheld) and, once completed, release Lender of its funding obligation with respect to the amount assigned. 11.11 Venue, Service of Process, and Jury Trial. BORROWER, FOR ITSELF AND ITS SUCCESSORS AND ASSIGNS, IRREVOCABLY (A) SUBMITS TO THE NONEXCLUSIVE JURISDICTION OF THE STATE AND FEDERAL COURTS IN NEW YORK, (B) WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION (INCLUDING IT BEING AN INCONVENIENT FORUM) THAT IT MAY NOW OR IN THE FUTURE HAVE TO THE LAYING OF VENUE OF ANY LITIGATION ARISING OUT OF OR IN CONNECTION WITH ANY LOAN DOCUMENT AND THE OBLIGATION BROUGHT IN THE COURTS OF NEW YORK, OR IN THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK, AND (C) CONSENTS TO THE SERVICE OF PROCESS OUT OF ANY OF THOSE COURTS IN ANY LITIGATION BY THE MAILING OF COPIES OF THAT PROCESS BY CERTIFIED MAIL, RETURN RECEIPT REQUESTED, POSTAGE PREPAID, BY HAND DELIVERY, OR BY DELIVERY BY A NATIONALLY-RECOGNIZED COURIER SERVICE, AND SERVICE SHALL BE DEEMED COMPLETE UPON DELIVERY OF THE LEGAL PROCESS AT ITS ADDRESS FOR PURPOSES OF THIS AGREEMENT. BORROWER ACKNOWLEDGES THAT THESE WAIVERS ARE A MATERIAL INDUCEMENT TO LENDER'S AGREEMENT TO ENTER INTO A BUSINESS RELATIONSHIP, THAT LENDER HAS ALREADY RELIED ON THESE WAIVERS IN ENTERING INTO THIS AGREEMENT, AND THAT LENDER WILL CONTINUE TO RELY ON EACH OF THESE WAIVERS IN RELATED FUTURE DEALINGS. BORROWER FURTHER WARRANTS AND REPRESENTS THAT IT HAS REVIEWED THESE WAIVERS WITH ITS LEGAL COUNSEL, AND THAT IT KNOWINGLY AND VOLUNTARILY AGREES TO EACH WAIVER FOLLOWING CONSULTATION WITH LEGAL COUNSEL. The waivers in this section are irrevocable, meaning that they may not be modified either orally or in writing, and these waivers apply to any future renewals, extensions, amendments, modifications, or replacements in respect of the applicable Loan Document. In connection with any Litigation, this agreement may be filed as a written consent to a trial by the court. 11.12 No General Partners' Liability. Lender agrees for itself and its respective successors and assigns, including any subsequent holder of the Note, that any claim against the Borrower which may arise under any Loan Document shall be made only against, and shall be limited to the assets of, the Borrower, except to the extent the Guarantor may have obligations with respect to such claim pursuant to the terms of the Guaranty, and that no judgment, order or execution entered in any suit, action or proceeding, whether legal or equitable, on this agreement, the Note or any other Loan Document, shall be obtained or enforced against any General Partner or its assets for the purpose of obtaining satisfaction and payment of the Note, the Debt evidenced thereby or any claims arising thereunder or under this agreement or any other Loan Document, any right to proceed against the General Partners individually or their respective assets being hereby expressly waived, renounced and remitted by Lender for itself and its successors and assigns. Nothing in the Section, however, shall be construed so as to prevent Lender or any other holder of the Note from commencing any action, suit or proceeding with respect to or causing legal papers to be served on any General Partner for the purpose of obtaining jurisdiction over the Borrower. 11.13 Entirety. THE LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN BORROWER AND LENDER MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. REMAINDER OF PAGE INTENTIONALLY BLANK. SIGNATURE PAGES FOLLOW. Signature Page to that certain Credit Agreement dated as of December 15, 1999 between NORTHERN BORDER PARTNERS, L.P., as Borrower and SUNTRUST BANK, ATLANTA, as Lender. NORTHERN BORDER PARTNERS, L.P., as Borrower By /s/ Larry L. DeRoin Name: Larry L. DeRoin Title: Chief Executive Officer Address: 1400 Smith Street Houston, TX 77002 Signature Page to that certain Credit Agreement dated as of December 15, 1999 between NORTHERN BORDER PARTNERS, L.P., as Borrower and SUNTRUST BANK, ATLANTA, as Lender. SUNTRUST BANK, ATLANTA, as Lender By /s/Todd C. Davis Name: Todd C. Davis Title: Vice President Address: 303 Peachtree Street, 3rd Floor Atlanta, GA 30308 SCHEDULES AND EXHIBITS Schedule 1 - Defined Terms Schedule 6 - Closing Documents Exhibit A - Note Exhibit B - Guaranty Exhibit C-1 - Borrowing Request Exhibit C-2 - Conversion Notice Exhibit D - Opinion of General Counsel to Companies SCHEDULE 1 DEFINED TERMS Acceptance Agreement means that certain Acceptance Agreement dated the date hereof, executed between Borrower and Lender, and listed on Schedule 6 hereto. Applicable Margin means, for any LIBOR Borrowing, (i) for any day during the period from and including the Effective Date, through and including the 180th calendar day thereafter, 0.50% per annum and (ii) for any day subsequent thereto, 0.75% per annum. Authorized Representative means, officers of Northern Plains Natural Gas Company whose signatures and incumbency shall have been certified to Lender pursuant to Section 6 and who have been authorized by the Borrower pursuant to resolution as its "Authorized Representative." Under the terms of this agreement, an Authorized Representative may execute and present Borrowing Requests and Conversion Notices. Base Rate means, for any day, the greater of either (a) the annual interest rate most recently announced by SunTrust Bank, Atlanta at its principal office in Atlanta, Georgia, as its prime rate, with the understanding that such prime rate is one of its base rates and serves as the basis upon which effective rates of interest are calculated for those loans making reference to the prime rate, and is evidenced by the recording of such prime rate after its announcement in such internal publication or publications as SunTrust Bank, Atlanta may designate, automatically fluctuating upward and downward without special notice to Borrower or any other Person, or (b) the sum of the Federal-Funds Rate plus (i) for the period between December 3, 1999 through January 31, 2000 (inclusive of such dates), one and one-half percent (1.5%); or (ii) for all other times, one half of one percent (0.5%). Base-Rate Borrowing means a Borrowing bearing interest at the Base Rate. Borrower is defined in the preamble to this agreement. Borrowing means any amount disbursed under the Loan Documents by Lender to or on behalf of Borrower under the Loan Documents, either as an original disbursement of funds, a renewal, extension, or continuation of an amount outstanding. Borrowing Date means the date on which funds are requested by Borrower in a Borrowing Request. Borrowing Request means a request, subject to Section 2.2, substantially in the form of Exhibit C-1. Business Day means (a) for purposes of any LIBOR Borrowing, a day when commercial banks are open for international business in London, England, and (b) for all other purposes, any day other than Saturday, Sunday, and any other day that commercial banks are authorized by Law to be closed in Georgia. CIBC Credit Agreement means that certain Credit Agreement dated as of November 6, 1997 among the Borrower, certain commercial lending institutions, and Canadian Imperial Bank of Commerce, as Agent, providing for a revolving line of credit in an amount not to exceed $175,000,000. CIBC Guaranty means that certain Guaranty dated as of November 6, 1997 by Northern Border Intermediate Limited Partnership, a Delaware limited partnership, as guarantor in favor of the "Lender Parties" defined therein, to guarantee, among other things, Borrower's obligations under the CIBC Credit Agreement. Closing Date means the date agreed to by Borrower and Lender for the initial Borrowing, which must be a Business Day occurring no earlier than December 15, 1999 Code means the Internal Revenue Code of 1986. Commitment means Lender's obligation under Section 2.1 to make advances under the Facility. Companies means, at any time, Borrower and each of its Subsidiaries. Conversion Notice means a request, subject to Section 3.9, substantially in the form of Exhibit C-2. CST means Central Standard Time. Current Date means any date within 30 days prior to the Effective Date. Current Financials, unless otherwise specified, means either (a) the Borrower's most recent 10K and 10Q filed with the Securities and Exchange Commission, or (b) at any time after annual Financials are first delivered under Section 7.7, Borrower's annual Financials then most recently delivered to Lender under Section 7.7, together with the Borrower's quarterly Financials then most recently delivered to Lender under Section 7.7. Debt means - of any Person, at any time, and without duplication - all obligations, contingent or otherwise, which in accordance with GAAP should be classified upon such Person's balance sheet as liabilities, but in any event including the sum of the following: (a) all obligations for borrowed money; (b) all obligations evidenced by bonds, debentures, notes, bankers' acceptances or similar instruments; (c) all obligations to pay the deferred purchase price of property or services except trade accounts payable arising in the ordinary course of business; (d) all direct or contingent obligations in respect of letters of credit; (e) liabilities secured (or for which the holder of the Debt has an existing Right, contingent or otherwise to be so secured) by any Lien existing on property owned or acquired by that Person; (f) lease obligations that have been (or under GAAP should be) capitalized for financial reporting purposes; plus (g) all guaranties, endorsements, and other contingent obligations for Debt of others. Debtor Laws means the Bankruptcy Code of the United States of America and all other applicable liquidation, conservatorship, bankruptcy, moratorium, rearrangement, receivership, insolvency, reorganization, suspension of payments, or similar Laws affecting creditors' Rights. Default is defined in Section 9. Default Rate means, for any day, an annual interest rate equal from day to day to the lesser of either (a) the then- existing Base Rate plus 3% or (b) the Maximum Rate. Effective Date means December 15, 1999. EST means Eastern Standard Time. Facility is the amount available to Borrower, not to exceed $25,000,000 at any time. Federal-Funds Rate means, for any day, the annual rate (rounded upwards, if necessary, to the nearest 1/16%) determined (which determination is conclusive and binding, absent manifest error) by Lender to be equal to (a) the weighted average of the rates on overnight federal-funds transactions with member bank of the Federal Reserve System arranged by federal-funds brokers on that day, as published by the Federal Reserve Bank of New York on the next Business Day, or (b) if those rates are not published for any day, the average of the quotations at approximately 9:00 a.m. CST (10:00 a.m. EST) received by Lender from three federal- funds brokers of recognized standing selected by Lender in its sole discretion. Financials of a Person means balance sheets, profit and loss statements, reconciliations of capital and surplus, and statements of cash flow prepared (a) according to GAAP (subject to year end audit adjustments with respect to interim Financials) and (b) except as stated in Section 1.5, in comparative form to prior year-end figures or corresponding periods of the preceding fiscal year or other relevant period, as applicable. Funding Loss means any loss, expense, or reduction in yield (but not any Applicable Margin) that Lender incurs because (a) Borrower fails or refuses to take any Borrowing that it has requested under this agreement, or (b) Borrower prepays or pays any Borrowing or converts any Borrowing to a Borrowing of another Type, in each case, other than on the last day of the applicable Interest Period. GAAP means generally accepted accounting principles of the Accounting Principles Board of the American Institute of Certified Public Accountants and the Financial Accounting Standards Board that are applicable from time to time. General Partner means any of Northern Plains Natural Gas Company, Pan Border Gas Company, and Northwest Border Pipeline Company, and their successors and assigns in such capacity. Guarantor means Northern Border Intermediate Limited Partnership, a Delaware limited partnership. Guaranty means a guaranty substantially in the form of the attached Exhibit B. Interest Period is defined in Section 3.8. Laws means all applicable statutes, laws, treaties, ordinances, rules, regulations, orders, writs, injunctions, decrees, judgments, opinions, and interpretations of any Tribunal. Lender is defined in the preamble to this agreement. LIBOR means, for a LIBOR Borrowing and for the relevant Interest Period, the annual interest rate (rounded upward, if necessary, to the nearest 0.01%) equal to the quotient obtained by dividing (a) the rate per annum for deposits in United States dollars for a period equal to such Interest Period appearing on the display designated as Page 3750 on the Dow Jones Markets Service (or such other page on that service or such other service designated by the British Banker's Association for the display of such Association's Interest Settlement Rates for Dollar deposits) as of 11:00 a.m. (London, England time) on the day that is two Business Days prior to the first day of the Interest Period or if such page 3750 is unavailable for any reason at such time, the rate which appears on the Reuters Screen ISDA Page as of such date and such time; provided, that if Lender determines that the relevant foregoing sources are unavailable for the relevant Interest Period, LIBOR shall mean the rate of interest determined by Lender to be the average (rounded upward, if necessary, to the nearest 1/100th of 1%) of the rates per annum at which deposits in United States dollars are offered to Lenders; two (2) Business Days preceding the first day of such Interest Period by leading banks in the London interbank market as of 10:00 a.m. for delivery on the first day of such Interest Period, for the number of days comprised therein and in an amount comparable to the amount of the LIBOR Borrowing of Lenders by (b) one minus the Reserve Requirement (expressed as a decimal) applicable to the relevant Interest Period. LIBOR Borrowing means a Borrowing bearing interest at the sum of LIBOR plus the Applicable Margin. Lien means any lien, mortgage, security interest, pledge, assignment, charge, title retention agreement, or encumbrance of any kind and any other arrangement for a creditor's claim to be satisfied from assets or proceeds prior to the claims of other creditors or the owners (other than title of the lessor under an operating lease). Litigation means any action by or before any Tribunal. Loan Documents means (a) this agreement, certificates and reports delivered under this agreement, and exhibits and schedules to this agreement, (b) all agreements, documents, and instruments in favor of Lender ever delivered under this agreement or otherwise delivered in connection with all or any part of the Obligation (other than assignments), and (c) all renewals, extensions, and restatements of, and amendments and supplements to, any of the foregoing. Material Adverse Event shall mean, with respect to any event, act, condition or occurrence of whatever nature (including any adverse determination in any litigation, arbitration, or governmental investigation or proceeding), whether singly or in conjunction with any other event or events, act or acts, condition or conditions, occurrence or occurrences whether or not related, a material adverse change in, or a material adverse effect on, (i) the business, results of operations, financial condition, assets, or liabilities of the Borrower and its Subsidiaries taken as a whole, as represented to Lender in the most recently delivered Current Financials, (ii) the ability of the Borrower to perform its obligations under the Loan Documents, (iii) the rights and remedies of the Lender under any of the Loan Documents or (iv) the legality, validity or enforceability of any of the Loan Documents. Material Agreement means any written or oral agreement, contract, commitment or understanding under which any Company is obligated to make payments in excess of $10,000,000 in any fiscal year or is entitled to receive revenues in any fiscal year in excess of 5% of Borrower's consolidated annual revenues for such year. Maturity Date means the earlier to occur of (a) the 364th calendar day following the Effective Date; or (b) the "Commitment Termination Date" defined under the CIBC Credit Agreement as in effect on the Effective Date, regardless of whether such agreement is hereafter modified, renewed or extended. Maximum Amount and Maximum Rate respectively mean, for Lender, the maximum non-usurious amount and the maximum non- usurious rate of interest that, under applicable Law, that Lender is permitted to contract for, charge, take, reserve, or receive on the Obligation. NBPC means Northern Border Pipeline Company, a Texas general partnership. Note means a promissory note substantially in the form of the attached Exhibit A, as renewed, extended, amended, and restated. Obligation means all present and future (a) Debts, liabilities, and obligations of any Company to Lender and related to any Loan Document, whether principal, interest, fees, costs, attorneys' fees, or otherwise, and (b) renewals, extensions, and modifications of any of the foregoing. Person means any individual, entity, or Tribunal. Potential Default means any event's occurrence or any circumstance's existence that would - upon any required notice, time lapse, or both - become a Default. Principal Debt means, at any time, the unpaid principal balance of all Borrowings. Quoted Rate means the fixed rate per annum for a specified maturity, which may be mutually agreed upon by Borrower and Lender pursuant to this agreement. Quoted-Rate Borrowing means a Borrowing bearing interest at the Quoted Rate. Representatives means representatives, officers, directors, employees, accountants, attorneys, and agents. Reserve Requirement means, for any LIBOR Borrowing and for the relevant Interest Period, the total reserve requirements (including all basic, supplemental, emergency, special, marginal, and other reserves required by applicable Law) actually applicable to Lender's eurocurrency fundings or liabilities as of the first day of that Interest Period. Responsible Officer means Borrower's chief executive officer, or chief financial officer. Rights means rights, remedies, powers, privileges, and benefits. Solvent means, as to any Person, that (a) the aggregate fair market value of its assets exceeds its liabilities, (b) it has sufficient cash flow to enable it to pay its Debts as they mature, and (c) it does not have unreasonably small capital to conduct its businesses. Subsidiary of any Person means any entity of which (i) more than 50% (in number of votes) of the stock (or equivalent interests) is owned of record or beneficially, directly or indirectly, by that Person, or (ii) any partnership, association, joint venture, limited liability company or similar business organization more than fifty percent (50%) of the ownership interest having ordinary voting power of which shall at the time be directly or indirectly owned by such Person, by such Person and one or more Subsidiaries of such Person, or by one or more Subsidiaries of such Person. Taxes means, for any Person, taxes, assessments, or other governmental charges or levies imposed upon it, its income, or any of its properties, franchises, or assets. Termination Date means the earlier of either (a) the Maturity Date or (b) the effective date that Lender's Commitment is fully canceled or terminated. Tribunal means any (a) local, state, territorial, federal, or foreign judicial, executive, regulatory, administrative, legislative, or governmental agency, board, bureau, commission, department, or other instrumentality, (b) private arbitration board or panel, or (c) central bank. Type means any type of Borrowing determined with respect to the applicable interest option. EX-23 3 CONSENTS OF EXPERTS AND COUNSEL EXHIBIT 23.01 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included in this Annual Report on Form 10-K, into the Company's previously filed Registration Statement File No. 333-40601, Registration Statement File No. 333-66949, Registration Statement File No. 333-72323, and Registration Statement File No. 333-72351. ARTHUR ANDERSEN LLP Omaha, Nebraska, March 27, 2000 EX-27 4 ARTICLE 5 FDS FOR 10-K
5 1,000 12-MOS DEC-31-1999 DEC-31-1999 7,258 15,669 30,238 0 4,410 60,643 2,410,133 664,777 1,863,437 238,429 848,369 0 0 0 515,269 1,863,437 0 318,963 0 138,896 0 0 67,709 81,003 0 81,003 0 0 0 81,003 2.70 2.70
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