010313elpasocoastal

Fried, Frank, Harris, Shriver & Jacobson 1001 Pennsylvania Avenue, NW, Suite 800 Washington, DC 20004-2505 Tel: 202.639.7000 Fax: 202.639.7003 (4) (8) www.ffhsj.com FEDERAL TRADE COMMISSION RECEIVED DOCUMENTS MAR 13 2001 SECRETARY Direct Phone: 212.859.8085 Direct Email: linda.blumkin@ffhsj.com March 13, 2001 Office of the Secretary Federal Trade Commission 6th Street and Pennsylvania Avenue, N.W. Room 172 Washington, D.C. 20580 Re: Request for Approval of Divestiture - El Paso Energy Corporation/ The Coastal Corporation - File No. 001-0086 To: Federal Trade Commission: Pursuant to § 2.41(f) of the Federal Trade Commission's ("Commission") Rules of Practice, 16 C.F.R. § 2.41(f) (2000) and Paragraph III.B. of the Decision and Order in the above-captioned matter (the "Decision and Order"), El Paso Corporation ("El Paso"), formerly known as El Paso Energy Corporation, hereby requests approval of the sale of all of the issued and outstanding shares of capital stock of both Midwestern Gas Transmission Company ("MGT") and Midwestern Gas Marketing Company ("MGM") to Border Midwestern Company ("BMC"), a subsidiary of Northern Border Intermediate Limited Partnership("NBILP"), an entity controlled by Northern Border Partners, L.P.("NBP"). Capitalized terms not herein defined shall have the same meanings set forth in the Decision and Order. As discussed with Dolores Wood, I am enclosing an original and 10 (ten) copies of this Public version of the divestiture application and attachments. # Attachments to Request for Approval of Divestiture A. The Stock Purchase Agreement (with all exhibits and schedules). This agreement is confidential and is not included in the public submission. B. A description of the divestiture transaction. C. A description of the purchaser. A Partnership Including Professional Corporations New York Washington Los Angeles London Paris ffdc01\rhilija\222514.1 FRIED FRANK HARRIS SHRIVER & JACOBSON Fried, Frank, Harris, Shriver & Jacobson March 13, 2001 Office of the Secretary Page 2 D. A market analysis that describes how the sale of capital stock to BMC will accomplish the Commission's divestiture goals as set forth in the Decision and Order. E. NBP's public documents, including the most recent 10-K and 10-Q filed with the SEC. If you require further information concerning NBP's plans, please contact counsel for Border Midwestern Company, Mr. Michael Peters, at 713-226-1331. Pursuant to the Order, El Paso is required to complete the divestiture by May 29, 2001. Accordingly, El Paso respectfully requests that this application receive expedited treatment. Please call me if you have any questions regarding any of the above or need any additional information or documentation.¹ Sincerely, Linda R. Blumkin LINDA R. BLUMKIN cc: Jeffery Dahnke, Esq. Robert E. Ogle ¹ With respect to an accounting of sales and other transactions during the previous year between El Paso and BMC, other than ordinary course contracts entered into in 2000 between the parties, the parties are not aware of any material sales or other transactions between the parties or their affiliates in 2000. ffdc01\rhilija\222514.1 Attachment A ## Stock Purchase Agreement This agreement is confidential and is not included in the Public submission. ffdc01\rhilija\222514.1 Attachment B ## Description of the Divestiture Transaction Midwestern Gas Transmission Company is a corporation organized under the laws of Delaware and headquartered in Houston, Texas. MGT is the owner of a 350-mile interstate natural gas pipeline extending from Portland, Tennessee, to Joliet, Illinois. Its affiliate, the Midwestern Gas Marketing Company, is also a corporation organized under the laws of Delaware, with its principal place of business located in Houston, Texas. Through its affiliates El Paso Tennessee Pipeline Company (“EPTP”) and Tennessee Gas Pipeline Company (“TGP”), El Paso Corporation owns all of the issued and outstanding shares of capital stock of MGT (the “Transmission Shares”) and all of the issued and outstanding shares of capital stock of MGM (the “Marketing Shares”). Pursuant to paragraph IIIB of the Decision and Order, El Paso is required to divest all of its rights, title, and interest in the MGT Assets not later than 120 days from the date the Commission accepted the Consent Agreement for public comment. The 120-day period will expire on May 29, 2001. EPTP and TGP have entered into an agreement with Border Midwestern Company, to which EPTP and TGP’s interests in the MGT Assets will be divested. On March 9, 2000, EPTP, TGP, and BMC executed a Stock Purchase Agreement (“Agreement”) pursuant to which EPTP and TGP agreed to sell to BMC the Transmission Shares and the Marketing Shares. TGP and BMC also intend to enter into a Transition Agreement under which TGP will provide transition services for a period not to exceed 9 (nine) months after the closing. By selling its shares of capital stock in the Midwestern Gas Transmission Company and the Midwestern Gas Marketing Company, El Paso will have divested all of its interest in the MGT Assets, as required by the Decision and Order. ffdc01\rhilija\222514.1 The Agreement contains the usual and customary conditions to closing, including approval of the Commission. Commission approval is also required by the Decision and Order. The parties have requested confidential treatment with respect to the terms and conditions of the Agreement. ffdc01\rhilija\222514.1 Attachment C ## Description of the Purchaser -- Border Midwestern Company Border Midwestern Company, is a subsidiary of Northern Border Intermediate Limited Partnership, an entity controlled by Northern Border Partners, L.P. Subsidiaries of Enron Corporation and The Williams Companies, Inc. are the general partners of Northern Border Partners, L.P. Northern Border Partners, L.P. is a publicly traded master limited partnership, owning a 70% general partner interest in Northern Border Pipeline Company, a Texas general partnership (“NBPL”) formed in 1978. The remaining 30% general partner interest in NBPL is owned by TC PipeLines Intermediate Limited Partnership, a subsidiary limited partnership of TC PipeLines, L.P., a publicly traded partnership. NBPL 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. NBPL also connects with multiple pipelines, providing shippers with access to the various natural gas markets served by those pipelines. On March 16, 2000, the FERC approved NBPL’s Project 2000, which will expand and extend the company’s pipeline system approximately 34.4 miles into Indiana. In the year ended December 31, 1999, NBPL estimated that it transported approximately 23% of the total amount of natural gas imported from Canada to the United States. ffdc01\rhilija\222514.1 Attachment D ## Market Analysis In its complaint, the Commission alleged that El Paso’s acquisition of Coastal might substantially reduce competition in transportation of natural gas to the Milwaukee-Waukesha PMSA and the Evansville Area (the “Relevant Areas”). In particular, the Commission alleged that if Guardian Pipeline L.L.C. were to build a pipeline to compete with Coastal’s ANR pipeline, then together El Paso and Coastal would own or control a significant share of all natural gas pipeline capacity into the Milwaukee-Waukesha PMSA, including the MGT Assets. The Commission also alleged that together El Paso and Coastal currently own or control a significant share of all pipeline capacity to the Evansville Area, including the ANR pipeline and the MGT Assets. The MGT Assets include a 350-mile interstate natural gas pipeline extending from Portland, Tennessee, to Joliet, Illinois, which transports natural gas into the Evansville Area and would become the upstream supplier to the Guardian pipeline once it were to enter service. Without agreeing with the Commission that El Paso’s acquisition of Coastal would have substantially lessened competition for the transmission of natural gas to the Relevant Areas, the sale of the shares of capital stock in the MGT Assets will eliminate the concerns expressed by the Commission with respect to the Relevant Areas. BMC’s acquisition of the interest in the MGT Assets does not raise any competitive issues, as NBPL’s existing pipeline system does not transport natural gas into the Relevant Areas. In view of the above, the parties believe that the sale of El Paso’s interest in the MGT Assets to BMC resolves the Commission’s concerns as reflected in the Complaint and complies with the Decision and Order. ffdc01\rhilija\222514.1 Attachment E ## Northern Border Pipeline Company's Public Documents Northern Border Partners, L.P., Form 10-K for the fiscal year ended December 31, 1999 Northern Border Partners, L.P., Form 10-Q for the period ended September 30, 2000 ffdc01\rhilija\222514.1 Page 1 75 of 435 DOCUMENTS Copyright 2000 Disclosure Incorporated EDGARPlus(R) COMPANY: NORTHERN BORDER PARTNERS L P TICKER: NBP EXCHANGE: NYS FORM-TYPE: 10-K DOCUMENT-DATE: March 28, 2000 FILING-DATE: March 28, 2000 Full text Company info Contents Other Return Special Printing Instructions for this Document. *** TEXT OF FILING *** 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 (State or other jurisdiction of incorporation or organization) 93-1120873 (I.R.S. Employer 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 ___ LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 2 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 3 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 4 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 5 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 6 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 7 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 8 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 9 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. LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 10 # 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 11 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 12 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 13 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 14 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 15 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. # LEXIS-NEXIS # LEXIS-NEXIS # LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 16 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 High Low Cash Distributions 1999 First Quarter $35.50 $30.375 $0.61 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 17 | 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 | LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 18 | 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. LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 19 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 20 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. LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 21 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 22 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 23 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 24 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 25 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 26 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 27 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 28 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 | Annual Compensation | | | | Long-Term Compensation | | | All Other Compensation | | --- | --- | --- | --- | --- | --- | --- | --- | | Name & Position | Year | Salary | Bonus (1) | Other Annual Compensation (2) | Restricted Stock Awards (3) | Securities Underlying Options/ 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 29 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 $93,365. Dividend equivalents for all restricted stock awards accrue from date of grant and are paid upon vesting. (4) The amounts shown include the value of Enron Common Stock allocated to employees' special subaccounts under Enron's Employee Stock Ownership Plan, matching contributions to employees' Enron Corp. Savings Plan, and imputed income on life insurance benefits. Stock Option Grants During 1999 The following table sets forth information with respect to grants of stock options pursuant to Enron's stock plans to the Named Officers reflected in the Summary Compensation Table. No stock appreciation rights were granted during 1999. | Name | Options/SARs Granted (#) (1) | Individual Grants % of Total | | Expiration Date | Potential Realizable Value at Assumed Annual Rate of Stock Price Appreciation For Option Term (4) | | | | --- | --- | --- | --- | --- | --- | --- | --- | | | | Options/SARs Granted to Employees in Fiscal Year | Exercise or Base Price ($/Sh) | | 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 30 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: | Name | Shares Acquired on Exercise (#) | Value Realized | Number of Securities Underlying Unexercised Options/SARs at December 31, 1999 | | Value of Unexercised In-the-Money Options/SARs December 31, 1999 | | | --- | --- | --- | --- | --- | --- | --- | | | | | 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 | [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 31 | | 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 1111 South 103rd Street 10,000 * LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 32 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; LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 33 * 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 34 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 35 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 1, 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 36 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). [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 37 *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) LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 38 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 Chairman of the Partnership Policy Committee (Principal Executive Officer) | March 28, 2000 | | STANLEY C. HORTON | Member of Partnership Policy Committee | March 28, 2000 | | Stanley C. Horton | | | | CUBA WADLINGTON, JR. | Member of Partnership Policy Committee | March 28, 2000 | | Cuba Wadlington, Jr. | | | | JERRY L. PETERS | Chief Financial and Accounting Officer | March 28, 2000 | | Jerry L. Peters | | | 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 39 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) | ASSETS | December 31, | | | --- | --- | --- | | | 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 | -- | LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 40 | 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 | LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 41 | 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 | [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 42 | 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) | | General Partners | Common Units | Subordinated Units | Total Partners' 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 43 # 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- [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 44 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 45 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 46 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. [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 47 (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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 48 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: (In thousands) December 31, 1999 1998 Northern Border Pipeline Senior notes - average 8.43%, due from 2000 to 2003 $ 250,000 $250,000 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 49 | 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 50 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 51 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 52 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 53 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 54 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 per unit amounts) | Year ended December 31, | | | | --- | --- | --- | --- | | | 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 | LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 55 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 per unit amounts) | Operating Revenues, net | Operating Income | Net Income to Partners | Net Income 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 56 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 Additions | | Column D Deductions | Column E | | --- | --- | --- | --- | --- | --- | | Description | Balance at Beginning of Year | Charged to Costs and Expenses | Charged to Other Accounts | For Purpose For Which Reserves Were Created | Balance at 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 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 57 * 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 58 Pipeline Company U.S. Shipper Service Agreement effective April 1, 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 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 59 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 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-K FILING-DATE: March 28, 2000 Page 60 indicated; all other exhibits are filed herewith. DCN: 00581417 LOAD-DATE: March 29, 2000 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS PAGE 1 9 of 435 DOCUMENTS Copyright 2000 Disclosure Incorporated EDGARPlus(R) COMPANY: NORTHERN BORDER PARTNERS L P TICKER: NBP EXCHANGE: NYS FORM-TYPE: 10-Q DOCUMENT-DATE: September 30, 2000 FILING-DATE: November 13, 2000 Full text Company info Contents Other Return * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * TEXT OF FILING * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2000 Commission File Number 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 93-1120873 (I.R.S. Employer Identification Number) Enron Building 1400 Smith Street Houston, Texas (Address of principal executive offices) 77002 (Zip code) (877) 208-7318 (Registrant's telephone number, including area code) 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 1 of 20 LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS PAGE 2 EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES # TABLE OF CONTENTS Page No. # PART I. FINANCIAL INFORMATION # ITEM 1. Financial Statements | Consolidated Statement of Income - Three Months Ended September 30, 2000 and 1999 and Nine Months Ended September 30, 2000 and 1999 | 3 | | --- | --- | | Consolidated Balance Sheet - September 30, 2000 and December 31, 1999 | 4 | | Consolidated Statement of Cash Flows - Nine Months Ended September 30, 2000 and 1999 | 5 | | Consolidated Statement of Changes in Partners' Capital - Nine Months Ended September 30, 2000 | 6 | | Notes to Consolidated Financial Statements | 7 | ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 11 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk 18 # PART II. OTHER INFORMATION ITEM 6. Exhibits and Reports on Form 8-K 19 # PART I. FINANCIAL INFORMATION # ITEM 1. FINANCIAL STATEMENTS NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME (In Thousands, Except Per Unit Amounts) (Unaudited) | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | --- | --- | --- | --- | --- | | | 2000 | 1999 | 2000 | 1999 | | OPERATING REVENUES | | | | | | Operating revenues | $86,755 | $79,046 | $264,318 | $235,953 | | Provision for rate refunds | (3,205) | -- | (16,715) | -- | | Operating revenues, net | 83,550 | 79,046 | 247,603 | 235,953 | | OPERATING EXPENSES | | | | | | Operations and maintenance | 13,802 | 13,279 | 41,360 | 38,606 | | Depreciation and amortization | 15,333 | 13,855 | 46,548 | 41,037 | | Taxes other than income | 6,532 | 7,184 | 22,230 | 22,366 | | Operating expenses | 35,667 | 34,318 | 110,138 | 102,009 | LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS PAGE 3 EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 | OPERATING INCOME | 47,883 | 44,728 | 137,465 | 133,944 | | --- | --- | --- | --- | --- | | INTEREST EXPENSE | 20,593 | 17,238 | 58,533 | 49,808 | | OTHER INCOME | 3,336 | 605 | 5,149 | 3,926 | | MINORITY INTERESTS IN NET INCOME | 10,288 | 8,738 | 27,735 | 26,513 | | NET INCOME TO PARTNERS | $20,338 | $19,357 | $ 56,346 | $ 61,549 | | NET INCOME PER UNIT | $ 0.66 | $ 0.65 | $ 1.85 | $ 2.05 | | NUMBER OF UNITS USED IN COMPUTATION | 29,347 | 29,347 | 29,347 | 29,347 | The accompanying notes are an integral part of these consolidated financial statements. ### PART I. FINANCIAL INFORMATION (Continued) ### ITEM 1. FINANCIAL STATEMENTS (Continued) NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (In Thousands) (Unaudited) | ASSETS | September 30, 2000 | December 31, 1999 | | --- | --- | --- | | CURRENT ASSETS | | | | Cash and cash equivalents | $ 46,119 | $ 22,927 | | Accounts receivable | 33,535 | 30,238 | | Materials and supplies, at cost | 6,668 | 4,410 | | Under recovered cost of service | -- | 3,068 | | Total current assets | 86,322 | 60,643 | | TRANSMISSION PLANT | | | | Property, plant and equipment | 2,413,378 | 2,410,133 | | Less: Accumulated provision for depreciation and amortization | 708,988 | 664,777 | | Property, plant and equipment, net | 1,704,390 | 1,745,356 | | INVESTMENTS AND OTHER ASSETS | | | | Investment in gas gathering businesses | 208,705 | -- | | Investment in unconsolidated affiliate | 60,331 | 31,895 | | Other | 29,561 | 25,543 | | Total investments and other assets | 298,597 | 57,438 | | Total assets | $2,089,309 | $1,863,437 | LIABILITIES AND PARTNERS' CAPITAL [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS PAGE 4 EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 CURRENT LIABILITIES | Current maturities of long-term debt | $ 44,373 | $ 183,617 | | --- | --- | --- | | Accrued distributions payable | 21,398 | -- | | Accounts payable | 7,079 | 8,279 | | Accrued taxes other than income | 29,180 | 26,608 | | Accrued interest | 14,205 | 17,608 | | Over recovered cost of service | 5,342 | -- | | Accumulated provision for rate refunds | 19,660 | 2,317 | | Total current liabilities | 141,237 | 238,429 | | LONG-TERM DEBT, NET OF CURRENT MATURITIES | 1,200,051 | 848,369 | | MINORITY INTERESTS IN PARTNERS' CAPITAL | 248,736 | 250,450 | | RESERVES AND DEFERRED CREDITS | 8,081 | 10,920 | | PARTNERS' CAPITAL | | | | General Partners | 9,824 | 10,305 | | Common Units | 481,380 | 504,964 | | Total partners' capital | 491,204 | 515,269 | | Total liabilities and partners' capital | $2,089,309 | $1,863,437 | The accompanying notes are an integral part of these consolidated financial statements. CON PART I. FINANCIAL INFORMATION (Continued) ITEM 1. FINANCIAL STATEMENTS (Continued) NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (In Thousands) (Unaudited) | | Nine Months Ended September 30, | | | --- | --- | --- | | | 2000 | 1999 | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | Net income to partners | $ 56,346 | $ 61,549 | | Adjustments to reconcile net income to partners to net cash provided by operating activities: | | | | Depreciation and amortization | 46,752 | 41,071 | | Minority interests in net income | 27,735 | 26,513 | | Provision for rate refunds, including interest | 17,343 | -- | | Changes in components of working capital | 4,347 | 6,189 | | Other | (6,095) | 816 | | Total adjustments | 90,082 | 74,589 | LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS PAGE 5 EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 | Net cash provided by operating activities | 146,428 | 136,138 | | --- | --- | --- | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | Investment in unconsolidated affiliate | (8,766) | -- | | Acquisition of gas gathering businesses | (229,505) | -- | | Capital expenditures for property, plant and equipment | (7,506) | (90,426) | | Net cash used in investing activities | (245,777) | (90,426) | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | Cash distributions to Unitholders and General Partners | (59,013) | (54,870) | | Distributions to Minority Interests | (29,449) | (29,374) | | Issuance of long-term debt | 431,148 | 281,026 | | Proceeds received upon termination of interest rate forward agreements | -- | 12,896 | | Retirement of long-term debt | (217,807) | (262,076) | | Long-term debt financing costs | (2,338) | (1,561) | | Net cash provided by (used in) financing activities | 122,541 | (53,959) | | NET CHANGE IN CASH AND CASH EQUIVALENTS | 23,192 | (8,247) | | Cash and cash equivalents-beginning of period | 22,927 | 41,042 | | Cash and cash equivalents-end of period | $ 46,119 | $ 32,795 | | Supplemental Disclosures of Cash Flow Information: | | | | Cash paid for: | | | | Interest (net of amount capitalized) | $ 64,840 | $ 52,809 | | Changes in components of working capital: | | | | Accounts receivable | $ (3,297) | $ (8,501) | | Materials and supplies | (2,258) | (176) | | Over/under recovered cost of service | 8,410 | 9,905 | | Accounts payable | 2,323 | 3,290 | | Accrued taxes other than income | 2,572 | 4,901 | | Accrued interest | (3,403) | (3,230) | | Total | $ 4,347 | $ 6,189 | The accompanying notes are an integral part of these consolidated financial statements. PART I. FINANCIAL INFORMATION (Continued) ITEM 1. FINANCIAL STATEMENTS (Continued) NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (In Thousands) (Unaudited) [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS PAGE 6 EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 | | General Partners | Common Units | Total Partners' Capital | | --- | --- | --- | --- | | Partners' Capital at December 31, 1999 | $10,305 | $504,964 | $515,269 | | Net income to partners | 2,159 | 54,187 | 56,346 | | Distributions declared, payable November 2000 | (854) | (20,544) | (21,398) | | Distributions paid to partners | (1,786) | (57,227) | (59,013) | | Partners' Capital at September 30, 2000 | $ 9,824 | $481,380 | $491,204 | The accompanying notes are an integral part of this consolidated financial statement. PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Continued) NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. The consolidated financial statements included herein have been prepared by Northern Border Partners, L.P. (the "Partnership") without audit pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, they reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, the Partnership believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 1999. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make 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. The Partnership owns a 70% general partner interest in Northern Border Pipeline Company ("Northern Border Pipeline"). Black Mesa Holdings, Inc., Black Mesa Pipeline Operations, L.L.C. and Crestone Energy Ventures, L.L.C. ("Crestone Energy") (formerly NBP Energy Pipelines, L.L.C.) are wholly-owned subsidiaries of the Partnership. [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 7 2. In December 1999, Crestone Energy purchased a \(39\%\) common membership interest in Bighorn Gas Gathering, L.L.C. ("Bighorn") for approximately \(\$ 31.9\)million and in June 2000, Crestone Energy purchased \(80\%\) of class A shares in Bighorn for approximately \(\$ 20.8\)million. These transactions are reflected as an investment in unconsolidated affiliate on the Consolidated Balance Sheet at September 30, 2000. In September 2000, Crestone Energy purchased interests in gas gathering businesses in the Powder River and Wind River basins in Wyoming from Enron North America Corp. ("ENA"), a subsidiary of Enron Corp., for approximately $208.7 million ("September Acquisition"). The September Acquisition included the purchase of a 100% interest in Enron Midstream Services, L.L.C., now known as Crestone Gathering Services, L.L.C. ("CGS"), a 33.33% interest in Fort Union Gas Gathering, L.L.C. and a 35% interest in Lost Creek Gathering, L.L.C. The purchase of CGS increased Crestone Energy's ownership in Bighorn to a 49% common membership interest and a 100% interest in the class A shares. The September Acquisition is reflected as an investment in gas gathering businesses on the Consolidated Balance Sheet. The Partnership is currently in the process of allocating the purchase price. 3. In October 1998, Northern Border Pipeline filed a certificate application with the Federal Energy Regulatory Commission ("FERC") to seek approval to expand and extend its pipeline system into Indiana ("Project 2000"). When completed, Project 2000 would afford shippers on the expanded and extended pipeline system access to industrial gas consumers in northern Indiana. The certificate application was subsequently amended by Northern Border Pipeline in March and December 1999. On March 16, 2000, the FERC issued an order granting Northern Border Pipeline's application for a certificate to construct and operate the proposed facilities. The FERC approved Northern Border Pipeline's request for rolled-in rate treatment based upon the proposed project costs. The project has a targeted in-service date of November 2001. The capital expenditures for the project are estimated to be approximately $94 million. 4. Northern Border Pipeline filed a rate proceeding with the FERC in May 1999 for, among other things, a redetermination of its allowed equity rate of return. The total annual cost of service increase due to Northern Border Pipeline's proposed changes was approximately $30 million. A number of Northern Border Pipeline's shippers and competing pipelines filed interventions and protests. In June 1999, the FERC issued an order in which the proposed changes were suspended until December 1, 1999, after which the proposed changes were implemented with subsequent billings subject to refund. 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, which was Northern Border Pipeline's expansion and extension project placed in service in December 1998; capital project cost containment mechanism ("PCCM") amount recorded for The Chicago LEXIS·NEXIS LEXIS·NEXIS LEXIS·NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 8 Project; depreciation schedule; and creditworthiness standards. As agreed to in a prior rate case settlement, the PCCM was implemented to limit Northern Border Pipeline's ability to include cost overruns on The Chicago Project in rate base and to provide incentives for cost underruns. The PCCM amount is computed by comparing the final cost of The Chicago Project to the budgeted cost, adjusted for the effects of inflation and project scope changes as defined in the prior rate case settlement. Testimony filed by the FERC staff and intervenors in the current rate case proceeding had proposed changes to the PCCM computation, which would have resulted in rate base reductions ranging from $32 million to $43 million. On September 26, 2000, Northern Border Pipeline filed a stipulation and agreement that documents the proposed settlement of its pending rate case. The settlement was reached between Northern Border Pipeline, the majority of its shippers and the FERC staff and will become effective if and when approved by the FERC. Northern Border Pipeline anticipates the FERC will act on the settlement in the first quarter of 2001. If the settlement is approved, shippers will pay stated transportation rates based on a straight fixed variable rate design. Under the straight fixed variable rate design, approximately 98% of the shipper payments are attributed to demand charges, based upon contracted firm capacity, and 2% to commodity charges based on the volumes of gas actually transported on the system. On a per unit of transportation basis, the rates under the settlement are approximately equal to the previous rates under the cost of service tariff. The settlement further provides for the incorporation into Northern Border Pipeline's rate base all of the construction costs of The Chicago Project and specifies an annual depreciation rate on transmission plant of 2.25%. Northern Border Pipeline has netted a provision for rate refunds against operating revenues to reflect the significant terms of the settlement in its Statement of Income. While the proposed settlement agreement has not been opposed by any of its shippers, Northern Border Pipeline can give no assurance whether it will be approved by the FERC. 5. In June 2000, the Partnership completed a private offering of $150 million of 8 7/8% Senior Notes due 2010 ("Partnership Senior Notes"). The proceeds from the private offering, net of debt discounts and issuance costs, were primarily used to reduce existing indebtedness under a November 1997 credit agreement and to acquire the class A shares in Bighorn (see Note 2). In September 2000, the Partnership completed a private offering of an additional $100 million of Partnership Senior Notes. The proceeds from this offering, along with the proceeds from the credit agreements described below, were used for the acquisition of the interests in gas gathering businesses from ENA. The indenture under which the Partnership Senior Notes were issued does not limit the amount of indebtedness or other obligations that the Partnership may incur, but does contain material financial covenants, including restrictions on the incurrence of secured indebtedness. In September 2000, the Partnership filed a registration statement with the SEC to exchange the $250 million of Partnership Senior Notes for notes with substantially identical terms. The Partnership expects the exchange will be LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 9 completed in the fourth quarter of 2000. The Partnership entered into interest rate swap agreements with an aggregate notional principal amount of $150 million in June 2000. The interest rate swap agreements are scheduled to terminate in June 2010. Under the agreements, the Partnership makes payments to counterparties at variable rates based on the London Interbank Offered Rate (6.66% at September 30, 2000) and in return receives payments based on an average fixed rate of 7.64%. In June 2000, the Partnership entered into two credit agreements with certain financial institutions, a $75 million 364-day credit agreement and a $75 million three-year revolving credit agreement (collectively, "Partnership Credit Agreements"). The Partnership Credit Agreements are to be used for capital expenditures, working capital and general business purposes. Upon proper notification to the financial institutions, the maturity date of the Partnership Credit Agreements may be extended to June 2005. The Partnership Credit Agreements 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. The Partnership is required to pay a fee on the principal commitment amount of $150 million. At September 30, 2000, $97.5 million had been borrowed under the Partnership Credit Agreements primarily for the acquisition of the interests in gas gathering businesses from ENA. The Partnership Credit Agreements require the maintenance of a ratio of debt to total capital, excluding the debt of consolidated subsidiaries, of no more than 35%. At the closing of the acquisition from ENA, the Partnership amended the Partnership Credit Agreements to increase the permitted ratio of debt to total capital to no more than 45% and gradually decreasing to 35% by September 30, 2001. 6. Net income per unit is computed by dividing net income, after deduction of the general partners' allocation, by the weighted average number of outstanding common units. The general partners' allocation is equal to an amount based upon their collective 2% general partner interest adjusted for incentive distributions. The distributions paid to partners and distributions declared amounts shown on the accompanying consolidated statement of changes in partners' capital include incentive distributions to the general partners of approximately $1.1 million. On September 25, 2000, the Partnership declared a cash distribution of $0.70 per unit ($2.80 per unit on an annualized basis) for the quarter ended September 30, 2000. The distribution is payable November 14, 2000, to unitholders of record at October 31, 2000. 7. In November 2000, the Partnership sold, through an underwritten public offering, 1,875,000 Common Units. In conjunction with the issuance of the additional Common Units, the Partnership's general partners made capital contributions to the LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 10 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 contribution totaled approximately $53 million and were used to repay amounts borrowed under the Partnership Credit Agreements. As part of the underwritten public offering, the Partnership granted the underwriters an over-allotment option to purchase up to an additional 281,250 Common Units. The underwriters have exercised the over-allotment option and the Partnership expects proceeds of approximately $8 million, including the general partners' capital contribution, to be received on November 14, 2000. PART I. FINANCIAL INFORMATION - (Continued) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES Results of Operations Northern Border Partners, L.P. (the "Partnership") owns a 70% general partner interest in Northern Border Pipeline Company ("Northern Border Pipeline"). Northern Border Pipeline's revenue is derived from agreements with various shippers for the transportation of natural gas. It transports gas under a Federal Energy Regulatory Commission ("FERC") regulated tariff. Northern Border Pipeline has used a cost of service form of tariff since its inception but has agreed to convert to stated rates as part of a settlement of its current rate case discussed below. The cost of service tariff provides Northern Border Pipeline an opportunity to recover all of the operations and maintenance costs of the pipeline, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated return on equity. Northern Border Pipeline is generally allowed to collect from its shippers a return on regulated rate base as well as recover that rate base through depreciation and amortization. The return amount Northern Border Pipeline may collect from its shippers declines as the rate base is recovered. Billings for the firm transportation 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 filed a rate proceeding with the FERC in May 1999 for, among other things, a redetermination of its allowed equity rate of return. The total annual cost of service increase due to Northern Border Pipeline's proposed changes was approximately $30 million. In June 1999, the FERC issued an order in which the proposed changes were suspended until December 1, 1999, after which the proposed changes were implemented with subsequent billings subject to refund. On September 26, 2000, Northern Border Pipeline filed a LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 11 stipulation and agreement that documents the proposed settlement of its pending rate case. The settlement was reached between Northern Border Pipeline, the majority of its shippers and the FERC staff and will become effective if and when approved by the FERC. Northern Border Pipeline anticipates the FERC will act on the settlement in the first quarter of 2001. If the settlement is approved, shippers will pay stated transportation rates based on a straight fixed variable rate design. Under the straight fixed variable rate design, approximately 98% of the shipper payments are attributed to demand charges, based upon contracted firm capacity, and 2% to commodity charges based on the volumes of gas actually transported on the system. On a per unit of transportation basis, the rates under the settlement are approximately equal to the previous rates under the cost of service tariff. The settlement further provides for the incorporation into Northern Border Pipeline's rate base all of the construction costs of The Chicago Project, which was Northern Border Pipeline's expansion and extension project placed in service in December 1998, and specifies an annual depreciation rate on transmission plant of 2.25%. Under the settlement, both Northern Border Pipeline and its existing shippers will not be able to seek rate changes until November 1, 2005. Northern Border Pipeline's earnings and cash flow will depend on its future costs, contracted capacity, the volumes of gas transported and its ability to recontract capacity at acceptable rates. Northern Border Pipeline has netted a provision for rate refunds against operating revenues to reflect the significant terms of the settlement in its Statement of Income. While the proposed settlement agreement has not been opposed by any of its shippers, Northern Border Pipeline can give no assurance whether it will be approved by the FERC. # Third Quarter 2000 Compared With Third Quarter 1999 Operating revenues, net increased $4.5 million (6%) for the third quarter of 2000, as compared to the same period in 1999, due primarily to a $4.3 million increase in net operating revenues of Northern Border Pipeline. Northern Border Pipeline's net operating revenues for 2000 reflect the significant terms of the settlement discussed previously. Operating revenues for 1999 were determined under Northern Border Pipeline's cost of service tariff. Depreciation and amortization expense increased $1.5 million (11%) for the third quarter of 2000, as compared to the same period in 1999, due primarily to an increase in the depreciation rate applied to Northern Border Pipeline's transmission plant. As required by its cost of service tariff, Northern Border Pipeline used a depreciation rate of 2.0% for all of 1999, which was increased to 2.3% beginning January 1, 2000. Interest expense increased $3.4 million (19%) for the third quarter of 2000, as compared to the same period in 1999. Interest expense for Northern Border Pipeline increased approximately $1.0 million, due primarily to an increase in interest rates between 1999 and 2000. Interest expense for the Partnership increased approximately $2.4 million, due to [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 12 additional borrowings and an increase in interest rates. The additional borrowings were made primarily for the acquisition of a 39% common membership interest and 80% of the non-voting class A shares in Bighorn Gas Gathering, L.L.C. ("Bighorn") and the acquisition of gas gathering businesses in the Powder River and Wind River basins in Wyoming (see Note 2 - Notes to Consolidated Financial Statements). Other income increased $2.7 million for the third quarter of 2000, as compared to the same period in 1999. Other income for Northern Border Pipeline increased $2.6 million, due primarily to a reduction in reserves previously established for regulatory issues. Nine Months September 30, 2000 Compared With Nine Months Ended September 30, 1999 Operating revenues, net increased $11.7 million (5%) for the first nine months of 2000, as compared to the same period in 1999, due primarily to a $11.2 million increase in net operating revenues of Northern Border Pipeline. Northern Border Pipeline's net operating revenues for 2000 reflect the significant terms of the settlement discussed previously. Operating revenues for 1999 were determined under Northern Border Pipeline's cost of service tariff. Operations and maintenance expense increased $2.8 million (7%) for the first nine months of 2000, as compared to the same period in 1999, due primarily to increased administrative expenses for Northern Border Pipeline. Depreciation and amortization expense increased $5.5 million (13%) for the first nine months of 2000, as compared to the same period in 1999, due primarily to an increase in the depreciation rate applied to Northern Border Pipeline's transmission plant. As required by its cost of service tariff, Northern Border Pipeline used a depreciation rate of 2.0% for all of 1999, which was increased to 2.3% beginning January 1, 2000. Interest expense increased $8.7 million (18%) for the first nine months of 2000, as compared to the same period in 1999. Interest expense for Northern Border Pipeline increased approximately $4.7 million, due primarily to an increase in interest rates between 1999 and 2000. Interest expense for the Partnership increased approximately $4.3 million, due to additional borrowings and an increase in interest rates. The additional borrowings were made primarily for the acquisition of a 39% common membership interest and 80% of the non-voting class A shares in Bighorn and the acquisition of gas gathering businesses in the Powder River and Wind River basins in Wyoming (see Note 2 - Notes to Consolidated Financial Statements). Other income increased $1.2 million (31%) for the first nine months of 2000, as compared to the same period in 1999. The 2000 results reflect a reduction in Northern Border Pipeline's reserves previously established for regulatory issues of $2.7 million. Additionally, the 2000 results include $1.4 million of [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 13 income earned from third-party usage of capacity on Northern Border Pipeline's microwave system. The 1999 results included $3.0 million of other non-operating income. 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 ("Pipeline Senior Notes"). The proceeds from the Pipeline Senior Notes were used to reduce indebtedness under a June 1997 credit agreement. Northern Border Pipeline entered into a credit agreement ("Pipeline Credit Agreement") with certain financial institutions in June 1997. The Pipeline Credit Agreement is comprised of a term loan and a $200 million five-year revolving credit facility, both maturing in June 2002. At September 30, 2000, $424.0 million was outstanding under the term loan and $60.0 million were outstanding under the revolving credit facility. At September 30, 2000, Northern Border Pipeline also had outstanding $184 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 were repaid in August 2000 primarily by borrowing under the Pipeline Credit Agreement. The Series B Notes with a principal amount of $41 million mature in August 2001. In June 2000, the Partnership completed a private offering of $150 million of 8 7/8% Senior Notes due 2010 ("Partnership Senior Notes"). In September 2000, the Partnership completed an additional private offering of $100 million of Partnership Senior Notes. In September 2000, the Partnership filed a registration statement with the Securities and Exchange Commission to exchange the Partnership Senior Notes for notes with substantially identical terms. The Partnership expects the exchange will be completed in the fourth quarter of 2000. The proceeds from the Partnership Senior Notes were used in acquisitions made by the Partnership in June 2000 and September 2000 (see Note 2 - Notes to Consolidated Financial Statements). The Partnership entered into interest rate swap agreements with an aggregate notional principal amount of $150 million in June 2000. The interest rate swap agreements are scheduled to terminate in June 2010. Under the agreements, the Partnership makes payments to counterparties at variable rates based on the London Interbank Offered Rate (6.66% at September 30, 2000) and in return receives payments based on an average fixed rate of 7.64%. In June 2000, the Partnership entered into two credit agreements with certain financial institutions, a $75 million 364- [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 14 day credit agreement and a $75 million three-year revolving credit agreement (collectively, "Partnership Credit Agreements"). The Partnership Credit Agreements are to be used for capital expenditures, working capital and general business purposes. Upon proper notification to and consent of the financial institutions, the maturity date of the Partnership Credit Agreements may be extended to June 2005. Prior to the termination of the Partnership Credit Agreements, the Partnership may request an increase in the commitment level to a maximum $200 million in the aggregate for both agreements. At September 30, 2000, $97.5 million had been borrowed under the Partnership Credit Agreements. The proceeds were used in acquisitions made by the Partnership in September 2000 (see Note 2 - Notes to Consolidated Financial Statements). In November 2000, the Partnership sold, through an underwritten public offering, 1,875,000 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 contribution totaled approximately $53 million and were used to repay amounts borrowed under the Partnership Credit Agreements. As part of the underwritten public offering, the Partnership granted the underwriters an over-allotment option to purchase up to an additional 281,250 Common Units. The underwriters have exercised the over-allotment option and the Partnership expects proceeds of approximately $8 million, including the general partners' capital contribution, to be received on November 14, 2000. Short-term liquidity needs will be met by internal sources and through the credit facilities 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. # Cash Flows From Operating Activities Cash flows provided by operating activities increased $10.3 million to $146.4 million for the first nine months of 2000, as compared to the same period in 1999 primarily due to the billings collected subject to refund related to Northern Border Pipeline's current rate proceeding (see Note 4 - Notes to Consolidated Financial Statements). # Cash Flows From Investing Activities The investment in unconsolidated affiliate for the first nine months of 2000 reflect capital contributions of $8.8 million to Bighorn for construction of gas gathering facilities. The Partnership has agreed to make additional 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 Partnership LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 15 Credit Agreements. The acquisition of gas gathering businesses for the first nine months of 2000 include the acquisition of gas gathering businesses in the Powder River and Wind River basins in Wyoming for approximately $208.7 million and the acquisition of 80% of the non-voting class A shares in Bighorn for approximately $20.8 million (see Note 2 - Notes to Consolidated Financial Statements). Capital expenditures of $7.5 million for the first nine months of 2000 included $3.3 million for Project 2000 (see Note 3 - Notes to Consolidated Financial Statements). For the comparable period in 1999, capital expenditures were $90.4 million and included $78.3 million for The Chicago Project. The remaining capital expenditures for 2000 and 1999 were primarily related to renewals and replacements of existing facilities. Total capital expenditures for 2000 are estimated to be $26 million. Capital expenditures for Northern Border Pipeline are estimated to be $18 million, including $8 million for Project 2000 and $10 million primarily for renewals and replacements of existing facilities. Northern Border Pipeline currently anticipates funding its 2000 capital expenditures primarily by using internal sources and borrowing on its revolving credit facility. Capital expenditures and equity investments for Crestone Energy Ventures, L.L.C. ("Crestone Energy") are estimated to be $7 million for 2000. The Partnership anticipates financing Crestone Energy's capital expenditures and equity investments primarily by using the Partnership Credit Agreements. # Cash Flows From Financing Activities Cash flows provided by financing activities was $122.5 million for the first nine months of 2000 compared to cash flows used of $54.0 million for the same period in 1999. Cash distributions to the unitholders and the general partners increased $4.1 million to $59.0 million reflecting an increase in the quarterly distribution from $0.61 per Unit to $0.65 per Unit. The distribution for the fourth quarter of 2000 of $0.70 per Unit was declared in September 2000 to be paid in November 2000. The proceeds from the private offering of the Partnership Senior Notes including premiums but net of associated debt discounts and issuance costs, totaled approximately $252.0 million. The net proceeds were used to repay the Partnership's existing indebtedness of $119.5 million, to fund the acquisition of the Bighorn class A shares of $20.8 million and to partially fund the acquisition of gas gathering businesses discussed previously. The funding for the remainder of the gas gathering businesses came from borrowings under the Partnership Credit Agreements of $97.5 million. In August 2000, Northern Border Pipeline repaid its Series A Notes of $66 million primarily by borrowing under the Pipeline Credit Agreement. Under the Pipeline Credit Agreement, borrowings totaled $75 million and repayments totaled $30 million during the nine months ended September 30, 2000. Financing activities for the nine months ended September 30, 1999, included $197.5 million from the [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 16 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 $82.0 million for the nine months ended September 30, 1999. During the nine months ended September 30, 1999, $255.0 million was repaid on the Pipeline Credit Agreement. # New Accounting Pronouncement In 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company 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. In June 2000, the FASB issued SFAS No. 138, which amended certain guidance within SFAS No. 133. The Partnership plans to adopt SFAS No. 133 beginning January 1, 2001. The Partnership believes that SFAS No. 133 (as amended) will not have a material impact on its financial position or results of operations. # Information Regarding Forward Looking Statements The statements in this Quarterly Report that are not historical information are forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward looking statements include the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in "Notes to Consolidated Financial Statements" regarding Northern Border Pipeline's efforts to pursue opportunities to further increase its capacity and Northern Border Pipeline's efforts to finalize settlement of its rate case. Although the Partnership believes that its expectations regarding future events are based on reasonable assumptions within the bounds of its knowledge of its business, it can give no assurance that its goals will be achieved or that its expectations regarding future developments will be realized. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include industry results, future demand for natural gas, availability of supplies of Canadian natural gas, political and regulatory developments that impact FERC proceedings involving Northern Border Pipeline, LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 17 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 peers, political and regulatory developments in Canada, and conditions of the capital markets and equity markets. # ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Partnership's interest rate exposure results from the portion of its consolidated debt portfolio subject to variable rates. To mitigate potential fluctuations in interest rates, the Partnership maintains a significant portion of its consolidated debt portfolio in fixed rate debt. The Partnership also uses interest rate swap agreements to manage its level of exposure to interest rate changes. The Partnership's annual interest rate exposure from a hypothetical 1% increase in interest rates was $6.9 million at September 30, 2000, as compared to $5.1 million at December 31, 1999. Approximately $4.4 million of the September amount would result from applying the hypothetical 1% increase in interest rates to Northern Border Pipeline's outstanding debt portfolio. In its Annual Report on Form 10-K for the year ended December 31, 1999, the Partnership reported that Northern Border Pipeline would be able to recover an increase in interest expense under its cost of service tariff, if an increase were to occur. If the rate case settlement is approved (see Note 4 - Notes to Consolidated Financial Statements), Northern Border Pipeline would bear the risk for an increase in interest rates. # PART II. OTHER INFORMATION NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits. None. (b) Reports on Form 8-K. The company filed a Current Report on Form 8-K, dated September 26, 2000, reporting the filing of a stipulation and agreement with the FERC to document the proposed settlement of Northern Border Pipeline Company's pending rate case. # SIGNATURES Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. LEXIS-NEXIS LEXIS-NEXIS LEXIS-NEXIS EDGARPlus(R) FORM-TYPE: 10-Q FILING-DATE: November 13, 2000 PAGE 18 NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) Date: November 13, 2000 By: JERRY L. PETERS Jerry L. Peters Chief Financial and Accounting Officer DCN: 00761426 LOAD-DATE: November 16, 2000 [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS [LOGO] LEXIS-NEXIS