-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, ADqnmWv7JFbdU/i1ZInb83qOCJHY/H9SG0B/FuyEAXZPCgILe+A3q3BNTAkPxpjE EEyE0T0pEboyPh7wnz8hEQ== 0000909281-99-000002.txt : 19990319 0000909281-99-000002.hdr.sgml : 19990319 ACCESSION NUMBER: 0000909281-99-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990318 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN BORDER PARTNERS LP CENTRAL INDEX KEY: 0000909281 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 931120873 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-12202 FILM NUMBER: 99567857 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST STREET 2: C/O ENRON BLDG CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138536161 MAIL ADDRESS: STREET 1: 1400 SMITH ST STREET 2: ENRON BUILDING RM 4524 CITY: HOUSTON STATE: TX ZIP: 77002 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _______________________ F O R M 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 Commission file number: 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 93-1120873 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 1400 Smith Street, Houston, Texas 77002-7369 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-853-6161 ___________________ Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Units New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ____ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to be the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X 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, 1999, was approximately $817,270,000. NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS Page No. Part I Item 1. Business 1 Item 2. Properties 8 Item 3. Litigation 9 Item 4. Submission of Matters to a Vote of Security Holders 9 Part II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 10 Item 6. Selected Financial Data 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 13 Item 7a. Quantitative and Qualitative Disclosures About Market Risk 20 Item 8. Financial Statements 21 Item 9. Disagreements on Accounting and Financial Disclosure 21 Part III Item 10. Partnership Management 22 Item 11. Executive Compensation 25 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"). The remaining general partner interests in Northern Border Pipeline are owned by TransCanada Border PipeLine Ltd. (6%) and TransCan Northern Ltd. (24%), both of which are wholly-owned subsidiaries of TransCanada PipeLines Limited ("TransCanada"). Northern Plains Natural Gas Company ("Northern Plains"), Pan Border Gas Company ("Pan Border") and Northwest Border Pipeline Company ("Northwest Border") serve as the General Partners of the Partnership. Northern Plains is a wholly-owned subsidiary of Enron Corp. ("Enron"), and Northwest Border is a wholly-owned subsidiary of The Williams Companies, Inc. ("Williams"). In December 1998, Northern Plains acquired Pan Border from a subsidiary of Duke Energy Corporation. At the closing, Pan Border's sole asset consisted of its general partner interest in the Partnership. The 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 "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 "Partnership Management"). The Partnership's 70% interest in Northern Border Pipeline represents substantially all its assets. Northern Border Pipeline owns a 1,214-mile U.S. interstate pipeline system (the "Pipeline System") that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, to interconnecting pipelines and local distribution systems in the States of North Dakota, South Dakota, Minnesota, Iowa and Illinois, providing shippers access to markets in the Midwest, including Chicago. The Pipeline System has pipeline access to natural gas reserves in the Western Canadian Sedimentary Basin located in the Canadian provinces of Alberta, British Columbia and Saskatchewan, as well as the Williston Basin in the United States. The Pipeline System also has access to production of synthetic gas from the Dakota Gasification Plant in North Dakota. Northern Border Pipeline shippers can arrange transportation, displacement and exchange agreements with third parties to provide access beyond Chicago to markets throughout the United States. 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 the TransCanada subsidiaries. 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. 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. The Partnership also owns 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. The Pipeline System The Pipeline System consists of 822-miles of 42-inch diameter pipe designed to transport 2,373 million cubic feet of natural gas per day ("MMcfd") from the Canadian border to Ventura, Iowa; 30-inch diameter pipe and 36-inch diameter pipe, each approximately 147 miles in length, designed to transport 1,300 MMcfd from Ventura, Iowa to Harper, Iowa; and 226 miles of 36-inch diameter pipe and 19 miles of 30- inch diameter pipe designed to transport 645 MMcfd from Harper, Iowa to a terminus near Manhattan, Illinois (Chicago area). Along the pipeline, there are fifteen compressor stations with total rated horsepower of 476,500 and measurement facilities to support the receipt and delivery of gas at various points along the pipeline. Other facilities include five field offices and a microwave communication system with 51 tower sites. Interconnecting pipeline facilities provide Northern Border Pipeline shippers with flexible access to natural gas markets. The Pipeline System interconnects with the pipeline facilities of: * Northern Natural Gas Company ("Northern Natural"), an Enron subsidiary, at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; * Natural Gas Pipeline Company of America at Harper, Iowa; * MidAmerican Energy Company at Iowa City and Davenport, Iowa; * Interstate 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 (Chicago area) at the terminus of the Pipeline System. At its northern end, the Pipeline System's largest receipt point is its connection to the Foothills Pipe Lines (Sask.) Ltd. system in Canada, which in turn is connected to the pipeline systems of NOVA Gas Transmission Ltd. ("NOVA") in Alberta and of Transgas Limited in Saskatchewan. The NOVA system gathers and transports a substantial portion of Canadian natural gas production. The Pipeline System also connects with the 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 system. The Pipeline System was initially constructed in 1982 with capacity additions in 1991, 1992 and 1998. A recent expansion, called The Chicago Project, was placed into service in December 1998 and increased the Pipeline System's capacity by 42% to its current capacity of 2,373 MMcfd. The estimated cost of The Chicago Project is $892 million (See "FERC Regulation - Cost of Service Tariff"). Future Demand and Competition Northern Border Pipeline's operations are supported by significant supplies of natural gas in Canada. In 1998, approximately 88% of the natural gas transported by the Pipeline System was produced in the Western Canadian Sedimentary Basin. Northern Border Pipeline's capacity utilization was an average of 99% of summer design capacity during 1998. It is estimated that the Pipeline System's share of Canadian gas exported to the United States in January and February 1999, the first full two months of operations of The Chicago Project, was nearly 23%. On November 17, 1997, Northern Border Pipeline announced the commencement of an open season during which prospective shippers were invited to submit requests for capacity on a possible further expansion and extension of the Pipeline System ("Project 2000"). From the bids submitted, project shippers signed precedent agreements for additional capacity from Port of Morgan, Montana to Ventura, Iowa of 62 MMcfd and from Ventura, Iowa to Manhattan, Illinois of 185 MMcfd and new capacity to North Hayden, Indiana of 545 MMcfd. In October 1998, Northern Border Pipeline filed a certificate application with the FERC to construct and operate facilities necessary to transport these volumes with construction costs estimated to be approximately $190 million. If approved and constructed, Project 2000 will strategically position Northern Border Pipeline to move gas east and will place it in direct contact with major industrial gas comsumers. Project 2000 would afford shippers access to the northern Indiana industrial zone, including Northern Indiana Public Service Company, a major Midwest local distribution company with a large industrial load requirement and total annual system deliveries in excess of 300 billion cubic feet. A notice to prepare an environmental assessment for this project was issued by the FERC on January 22, 1999 to all affected landowners and other interested parties giving those parties the opportunity to provide comments. Northern Border Pipeline has been advised that permanent releases of existing capacity have been negotiated between several existing and project shippers. If such releases are finalized, certain proposed facilities will not be needed, reducing the estimated construction cost to approximately $130 million, and an amendment of the certificate application will be filed advising FERC of these changes. Northern Border Pipeline competes with other pipeline companies that transport gas from the Western Canadian Sedimentary Basin or that transport gas to end-use markets in the Midwest. Its competitive position is affected by the availability of Canadian natural gas for export and demand for natural gas in the United States. Shippers of gas produced in the Western Canadian Sedimentary Basin have other options to transport Canadian natural gas to the United States, including transportation on pipelines eastward in Canada or to markets on the West Coast. The sponsors of the Alliance Pipeline project recently received Canadian and United States regulatory approvals for the construction of a new pipeline to originate in western Canada and terminate in the vicinity of Chicago, Illinois. These sponsors have announced their plans for the pipeline to be in service by October 2000. The new pipeline would directly compete with Northern Border Pipeline by transporting gas from the Western Canadian Sedimentary Basin to the midwestern United States. Although there may be a large increase in natural gas moving from the Western Canadian Sedimentary Basin into the Chicago market, there are several additional projects proposed to transport natural gas from the Chicago area to growing eastern markets. The proposed projects, currently being pursued by unrelated third parties, are targeting markets in eastern Canada and the northeast United States. None of these proposed projects has received final regulatory approval. Shippers The Pipeline System serves a number of shippers with diverse financial and business profiles. Based on shippers' cost of service obligations, 93% of the capacity is contracted by producers and marketers. The remaining capacity is contracted primarily by interstate pipelines (2%) and local distribution companies (5%). At present, the termination dates of these contracts range from October 31, 2001 to December 21, 2013. The weighted average contract life as of December 31, 1998 (based upon shippers' cost of service obligations) is slightly under eight years with 97% of capacity contracted through mid-September 2003. Firm shippers on the Pipeline System as of December 31, 1998 that are affiliated with general partners of the Partnership or the general partners of Northern Border Pipeline are: Enron Capital & Trade Resources Corp.("ECT"), a subsidiary of Enron; TransCanada Gas Services Inc., a subsidiary of, and as agent for, TransCanada; and Transcontinental Gas Pipe Line Corporation ("Transco"), a subsidiary of Williams. Together those shippers currently hold 16.9% of capacity. Northern Border Pipeline's largest shipper, Pan-Alberta Gas U.S. Inc. ("PAGUS"), currently holds 707 MMcfd, 26.5% of the capacity, under three transportation contracts with terms that have been extended to October 31, 2003. The extension of the termination date for one of the contracts covering 150 MMcfd is subject to further FERC authorization. An affiliate of Enron provides guaranties for 300 MMcfd, of PAGUS' contractual obligations through October 31, 2001. In addition, PAGUS' remaining transportation 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 150 MMcfd, an escrow account and an upstream capacity transfer agreement. FERC Regulation General FERC extensively regulates Northern Border Pipeline as a "natural gas company" under the Natural Gas Act (the "NGA"). Under the NGA and the Natural Gas Policy Act, the FERC has jurisdiction over Northern Border Pipeline with respect to virtually all aspects of its business, including transportation of 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, the initiation and discontinuation of services, and certain other matters. Northern Border Pipeline, where required, holds certificates of public convenience and necessity issued by the FERC covering its facilities, activities and services. Under Section 8 of the NGA, the FERC has the power to prescribe the accounting treatment for items for regulatory purposes. The Northern Border Pipeline books and records are periodically audited pursuant to Section 8. Northern Border Pipeline's rates and charges for transportation in interstate commerce are subject to regulation by the FERC. Natural gas companies may not charge rates exceeding rates deemed 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. Certain types of rates may be discounted without further FERC authorization. Cost of Service Tariff Northern Border Pipeline's firm transportation shippers contract to pay for an allocable share of the cost of service associated with the Pipeline System's capacity. During any given month, all such shippers pay 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 allocable share of the cost of service regardless of the amount of gas they actually transport. The cost of service tariff is regulated by the FERC and provides an opportunity to recover all operations and maintenance costs of the Pipeline System, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Northern Border Pipeline may not charge or collect more than its cost of service pursuant to its tariff on file with the FERC. Northern Border Pipeline's investment in the Pipeline System is reflected in various accounts referred to collectively as its regulated "rate base." The cost of service includes a return, with related income taxes, on the rate base. Over time, the rate base declines as a result of, among other things, the monthly depreciation and amortization. The Northern Border Pipeline rate base 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 ("IROR"), has been amortized through monthly additions to the cost of service. As a result, the Partnership's net income for 1998 included $9.9 million for such amortization along with a related income tax allowance, net of the effect of minority interests. This impact on net income is expected to continue until November 2001 when the IROR is fully amortized. 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 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' accounts. Northern Border Pipeline also provides interruptible transportation service. 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 back to the firm shippers' accounts. In its 1995 rate case, Northern Border Pipeline reached a settlement that was filed in a Stipulation and Agreement ("Stipulation"). Although it was contested, it was approved by the FERC on August 1, 1997. In the Stipulation, 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 Stipulation also determined several other cost of service parameters. In accordance with the effective tariff, Northern Border Pipeline's allowed equity rate of return is 12%. For at least seven years from the date The Chicago Project was completed, Northern Border Pipeline, under the terms of the Stipulation, may continue to calculate its allowance for income taxes as a part of its cost of service in the manner it has 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 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. 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 Northern Border Pipeline's 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, that amount will be allocated 50% to Northern Border Pipeline and 50% to its shippers (50% of the difference between 5% of the budgeted cost and $6 million will be included in Northern Border Pipeline's rate base, and 50% will be excluded). All cost overruns exceeding 5% of the budgeted cost are excluded from the rate base. 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 has been estimated as of the December 22, 1998 in-service date to be $889 million, with the final construction cost estimated to be $892 million. Thus, Northern Border Pipeline's report to the FERC and its shippers in late December 1998, reflected the conclusion that, based on information as of that date, once the budgeted cost has been established, there would be no adjustment to rate base as a result of the PCCM. Northern Border Pipeline is obligated by the Stipulation to update its calculation of the PCCM six months after the in-service date of The Chicago Project. The Stipulation requires the calculation of the PCCM to be reviewed by an independent national accounting firm. Several parties to the Stipulation have advised the FERC that they may have questions and desire further information about the report, and may possibly wish to test it (or the final report) and the conclusions contained therein in an appropriate proceeding in the future. The parties also stated that if it is determined that Northern Border Pipeline is not able to include certain claimed costs for The Chicago Project in its rate base, they reserve their rights to seek refunds, with interest, of any overcollections. Although the Partnership believes the initial computation has been made pursuant to the terms of the Stipulation, it is unable to make a definitive determination at this time whether any adjustments will be required. Should subsequent developments cause costs not to be recovered pursuant to the PCCM, a non-cash charge to write down transmission plant may result, and such charge could be material to the operating results of the Partnership. Northern Border Pipeline is required by the terms of its tariff to file a rate case with the FERC by no later than May 31, 1999 for a redetermination of its allowed equity rate of return. The Partnership cannot predict the impact, if any, of the outcome of the next rate case. Proposed Regulations In a Notice of Proposed Rulemaking ("NOPR") issued on July 29, 1998, the FERC proposed changes to its regulations governing short-term transportation services. Among the proposals considered in the NOPR are: * Auctions for short-term capacity; * Removal of price caps for secondary market transactions; * Revisions to FERC's reporting requirements; * Revisions to tariff provisions governing imbalances; and * Negotiated services. In a companion Notice of Inquiry issued the same day, the FERC requested industry comment on its pricing policies in the existing long-term market for transportation services and its pricing policies for new capacity. The FERC also issued a NOPR to revise its procedures under which shippers or others may have complaints considered by the FERC. The Partnership cannot assess the impact on Northern Border Pipeline of any final rules adopted by the FERC as a result of these proceedings at this time. The FERC also commenced proceedings to revise its pipeline construction regulations. On September 30, 1998, the FERC issued a NOPR to amend its regulations to reflect current FERC policies governing the issuance of pipeline construction certificates and to codify the filing of certain related information. Also on September 30, 1998, the FERC issued a NOPR that would give applicants seeking to construct, operate or abandon natural gas services or facilities the option of using a pre-filing collaborative process to resolve significant issues among parties and the pipeline. The NOPR also proposes that a significant portion of the environmental review process could be completed as part of the collaborative process. As part of the NOPR, the FERC intends to examine existing landowner and pipeline construction issues. The Partnership cannot assess the impact on Northern Border Pipeline of any final rules adopted by the FERC as a result of these proceedings at this time. Environmental and Safety Matters The operations of the Partnership are subject to federal, state and local laws and regulations relating to safety and the protection of the environment which include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas Pipeline Safety Act of 1969, as amended, and the Pipeline Safety Act of 1992. Although the Partnership believes that its 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 the Partnership cannot provide any assurances that it 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 the Partnership is 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 the 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, measurement 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. 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 notified the Bureau of Indian Affairs ("BIA") in March 1996 that it was exercising its option to renew the pipeline right-of-way lease for an additional 15 year term. 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 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. 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 in this proceeding was issued by the Federal Court granting Northern Border Pipeline continued access and possession during the pendency of the condemnation action on the tracts in question. A stipulation has been entered into involving all but one tract involved in the condemnation action in which the parties have agreed that the Court may enter an order assessing compensation in the amount established in an agreed upon appraisal. A hearing was held by the Court in January 1999 in which evidence was presented on the value of the interest being condemned. No order has been entered as yet. Amounts ordered by the Court as compensation should be included in Northern Border Pipeline's cost of service. To date the BIA has not issued a formal right-of-way grant for those tracts for which sufficient landowners consents were obtained. It is anticipated that the issuance of such a grant will take place in conjunction with the resolution of the condemnation action. Item 3. Litigation The Partnership and its subsidiaries 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 the Partnership's results of operations or financial position. Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during 1998. PART II Item 5. Market for the Registrant's Common Units and Related Security Holder Matters The following table sets forth, for the periods indicated, the high and low sale prices per Common Unit, as reported on the New York Stock Exchange Composite Tape, and the amount of cash distributions per Common Unit declared for each quarter:
Price Range Cash High Low Distributions 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 1997 First Quarter $29.125 $26.125 $0.55 Second Quarter 29.375 26.875 0.55 Third Quarter 33.25 28.50 0.55 Fourth Quarter 35.00 32.063 0.575
As of March 5, 1999, there were approximately 1,656 record holders of Common Units and approximately 34,538 beneficial owners of the Common Units, including Common Units held in street name. The Partnership currently has 29,347,313 Common Units outstanding, representing a 98% limited partner interest. The Common Units are the only outstanding limited partner interests. Thus, the Partnership's 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 19, 1999, the Partnership declared an increase in the distribution to $0.61 per Unit ($2.44 per Unit on an annualized basis), payable February 12, 1999 to the General Partners and Unitholders of record at January 29, 1999. On May 31, 1997, the Partnership issued 125,357 Common Units in a private placement, exempt pursuant to Section 4(2) of the Securities Act of 1933, to the stockholders of Williams Technologies, Inc., an Oklahoma corporation ("WTI"), in consideration of the sale by such stockholders to the Partnership of all of the capital stock of WTI. On December 29, 1997, the Partnership issued 46,956 Common Units in a private placement, exempt pursuant to Section 4(2) of the Securities Act of 1933, to Central Pacific Resources Partnership as partial consideration for the acquisition by the Partnership of an interest in Black Mesa Pipeline Operations, LLC. 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, 1998 1997 1996 1995 1994 INCOME DATA: Operating revenue $ 217,592 $ 198,574 $ 201,943 $ 206,497 $ 211,580 Operations and maintenance 44,770 37,418 28,366 26,730 28,919 Depreciation and amortization 43,536 40,172 46,979 47,081 41,959 Taxes other than income 22,012 22,836 24,390 23,886 24,438 Regulatory credit (8,878) -- -- -- -- Operating income 116,152 98,148 102,208 108,800 116,264 Interest expense, net 30,922 30,860 32,670 35,106 38,375 Other income (expense) 12,859 7,989 2,900 469 (1,389) Minority interests in net income 30,069 22,253 22,153 22,360 23,147 Net income to partners $ 68,020 $ 53,024 $ 50,285 $ 51,803 $ 53,353 Net income per Unit $ 2.27 $ 1.97 $ 1.88 $ 1.94 $ 2.00 Number of units used in computation 29,345 26,392 26,200 26,200 26,200 CASH FLOW DATA: Net cash provided by operating activities $ 103,849 $ 119,621 $ 137,534 $ 127,078 $ 121,088 Capital expenditures 652,194 152,658 18,597 8,411 2,985 Distribution per Unit 2.30 2.20 2.20 2.20 2.20 BALANCE SHEET DATA (AT END OF PERIOD): Net property, plant and equipment $1,730,476 $1,118,364 $ 937,859 $ 957,587 $ 983,842 Total assets 1,825,766 1,266,917 1,016,484 1,041,339 1,083,468 Long-term debt, including current maturities 976,832 481,355 377,500 410,000 445,000 Minority interests in partners' capital 253,031 174,424 158,089 166,789 173,984 Partners' capital 507,426 500,728 410,586 419,117 426,130 OPERATING DATA (unaudited): Northern Border Pipeline: Million cubic feet of gas delivered 619,669 633,280 633,908 615,133 597,898 Average daily throughput (MMcfd) 1,737 1,770 1,764 1,720 1,663
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Year Ended December 31, 1998 Compared With the Year Ended December 31, 1997 Operating revenue increased $19.0 million for the year ended December 31, 1998, as compared to the results for the comparable period in 1997. Operating revenue attributable to Northern Border Pipeline increased $10.5 million due primarily to returns on higher levels of invested equity. Northern Border Pipeline's FERC tariff provides 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 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. As a result of placing the facilities for The Chicago Project into service, Northern Border Pipeline added approximately $840 million to its gas plant in service in 1998 (See "Business-The Pipeline System"). Operating revenue for Black Mesa was $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 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 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 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 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. Minority interests in net income increased $7.8 million for the year ended December 31, 1998, as compared to the same period in 1997, due to increased net income for Northern Border Pipeline. Year Ended December 31, 1997 Compared With the Year Ended December 31, 1996 Operating revenue decreased $3.4 million for the year ended December 31, 1997, as compared to the results for the comparable period in 1996. Operating revenue attributable to Northern Border Pipeline decreased $15.9 million due primarily to lower depreciation and amortization expense, taxes other than income and returns on a lower rate base. Additionally, in accordance with the Stipulation approved by the FERC to settle Northern Border Pipeline's November 1995 rate case, the allowed equity rate of return was 12.75% through September 30, 1996 and 12.0% thereafter (See "Business-FERC Regulation-Cost of Service Tariff"). These lower recoveries were partially offset by higher operations and maintenance expense recoveries. Operating revenue for Black Mesa was $12.5 million for 1997. Operations and maintenance expense increased $9.1 million for the year ended December 31, 1997, from the comparable period in 1996 due primarily to $7.7 million of expense for Black Mesa. Operations and maintenance expense attributable to Northern Border Pipeline increased $1.5 million for the year ended December 31, 1997, from the comparable period in 1996 due primarily to higher administrative expenses. Depreciation and amortization expense decreased $6.8 million for the year ended December 31, 1997, as compared to the same period in 1996. Depreciation and amortization expense attributable to Northern Border Pipeline decreased $8.3 million. In accordance with the terms of the Stipulation, the depreciation rate applied to Northern Border Pipeline's gross transmission plant was 2.5% for 1997. The average depreciation rate applied to gross transmission plant for the year ended December 31, 1996 was 3.1%. Depreciation and amortization expense for Black Mesa was $1.5 million for 1997. Taxes other than income decreased $1.6 million for the year ended December 31, 1997, as compared to the results for the same period in 1996. Taxes other than income attributable to Northern Border Pipeline decreased $2.0 million due primarily to lower property tax assessments received in various states where the pipeline system operates. Taxes other than income for Black Mesa was $0.4 million for 1997. Interest expense, net decreased $1.8 million for the year ended December 31, 1997, as compared to the results for the same period in 1996, due to an increase in interest expense of $1.4 million offset by an increase in the amount of interest expense capitalized of $3.2 million. The increase in interest expense was due primarily to Black Mesa. The increase in interest expense capitalized primarily relates to Northern Border Pipeline's expenditures for The Chicago Project. Other income increased $5.1 million for the year ended December 31, 1997, as compared to the same period in 1996. The increase was primarily due to $4.8 million received by Northern Border Pipeline for vacating certain microwave frequency bands and a $1.0 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. Liquidity and Capital Resources General 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 bank loan agreements and for general business purposes, and a $550 million three-year revolving credit facility to be used for the construction of The Chicago Project. The three-year revolving credit facility may, if certain conditions are met, be converted to a term loan maturing in June 2002. Northern Border Pipeline intends to, and has the ability to, convert the three-year revolving credit facility to a term loan in 1999. At December 31, 1998, $127.5 million and $484.5 million had been borrowed on the five-year and three-year revolving credit facilities, 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 capital contributions for The Chicago Project in excess of $25 million. The public offerings of Common Units discussed in the following paragraph reduced the amount available under the Partnership Credit Agreement to $104 million. The maturity date of the Partnership Credit Agreement will be November 2000 if Northern Border Pipeline converts its $550 million three-year revolving credit facility to a term loan; otherwise the maturity date is June 2000. At December 31, 1998, $95 million had been borrowed on the Partnership Credit Agreement. In December 1997, the Partnership sold, through an underwritten public offering, 2,750,000 Common Units. In conjunction with the issuance of the 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 approximately $90.9 million were used by the Partnership to fund a portion of the capital contributions to Northern Border Pipeline for construction of The Chicago Project. As part of the underwritten public offering, the Partnership granted the underwriters an over-allotment option to purchase a limited number of additional Common Units. This option was exercised on January 5, 1998, and the Partnership sold an additional 225,000 Common Units resulting in additional net proceeds, including the general partners' capital contributions, of approximately $7.6 million. In September 1998, Northern Border Pipeline executed interest rate forward agreements with an aggregate notional amount of $150 million to hedge the interest rate for a planned issuance of fixed rate debt during 1999. Northern Border Pipeline plans to use the proceeds from the debt borrowing to repay amounts borrowed on the Pipeline Credit Agreement. 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 Panhandle Eastern Pipe Line Company, 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 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 other current assets and liabilities partially offset by the effect of the refund activity in 1997 discussed below. For the year ended December 31, 1998, the changes in other current assets and liabilities 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 other current assets and liabilities 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 decreased $17.9 million to $119.6 million for the year ended December 31, 1997 as compared to the same period in 1996 primarily related to a $52.6 million refund in October 1997 in accordance with the Stipulation approved by the FERC to settle Northern Border Pipeline's November 1995 rate case. During 1997, $40.4 million had been collected subject to refund by Northern Border Pipeline as a result of its rate case. Cash Flows From Investing Activities Capital expenditures of $652.2 million for the year ended December 31, 1998, include $638.7 million for The Chicago Project (See "Business-The Pipeline System") and $11.7 million for linepack gas. The remaining $1.8 million of capital expenditures for 1998 is primarily related to renewals and replacements of existing facilities. For the comparable period in 1997, capital expenditures were $152.7 million, which included $135.7 million for The Chicago Project and $17.0 million primarily related to renewals and replacements of Northern Border Pipeline's existing facilities. Total capital expenditures for 1999 are estimated to be $131 million including $30 million for Project 2000 (see "Business- Future Demand and Competition") and $85 million for The Chicago Project. Approximately $37 million of the capital expenditures for The Chicago Project is for construction completed in 1998. An additional $16 million of 1999 capital expenditures is planned for renewals and replacements of the existing facilities. Northern Border Pipeline anticipates funding its 1999 capital expenditures primarily by borrowing on the Pipeline Credit Agreement and using working capital. Funds required to meet the remainder of Northern Border Pipeline's capital expenditures will be provided primarily from capital contributions from the Partnership and minority interest holders. The Partnership intends to use a combination of proceeds from the sale of Common Units, capital contributions from its general partners and borrowings on the Partnership Credit Agreement to finance its capital contributions to Northern Border Pipeline. The Partnership anticipates selling additional Common Units to repay amounts borrowed on the Partnership Credit Agreement to finance capital contributions for The Chicago Project. Cash flows provided by acquisition and consolidation of businesses of $3.4 million for the year ended December 31, 1997, are related primarily to the consolidation of Black Mesa's cash balance. Cash Flows From Financing Activities Cash flows provided by financing activities increased $387.0 million to $482.6 million for the year ended December 31, 1998, as compared to the same period in 1997. Financing activities for 1998 include borrowings under the Pipeline Credit Agreement and Partnership Credit Agreement totaling $498.0 million and were used primarily for construction expenditures related to The Chicago Project. In 1997, borrowings under the Pipeline Credit Agreement totaled $209 million and were used primarily to retire amounts related to Northern Border Pipeline's existing bank loan agreements of $137.5 million and for construction expenditures related to The Chicago Project. Financing activities for 1998 reflect $7.6 million in net proceeds from the issuance of 225,000 Common Units and a related capital contribution by the Partnership's general partners in January 1998. In 1997, financing activities reflect $90.9 million in net proceeds from the issuance of 2,750,000 Common Units and a related capital contribution by the Partnership's general partners in December 1997. Contributions received from minority interests increased $42.6 million to $66.9 million and were used by Northern Border Pipeline to fund a portion of its capital expenditures. Distributions to minority interests decreased $11.7 million to $18.4 million primarily due to a change in the timing of Northern Border Pipeline's distributions. Year 2000 The Partnership and its subsidiaries, similar to most businesses, 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, but, in addition, a great deal of information processing technology is embedded in microelectronic devices. The Year 2000 problem results 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. If not corrected, many computer applications could fail or create erroneous results. The effects of the Year 2000 problem are compounded because of the interdependence of computer and telecommunication systems in the United States and throughout the world. This interdependence is true for the Partnership, its subsidiaries and their respective suppliers and customers. The Partnership and its subsidiaries have developed a plan, which will be modified as events warrant, to address Year 2000 problems (the "Plan"). The Plan is designed to take reasonable steps to prevent mission-critical functions from being impaired due to the Year 2000 problem. "Mission-critical" functions are those critical functions whose loss would cause an immediate stoppage of or significant impairment to major business areas (a major business area is one of material importance to the Partnership's and its subsidiaries' businesses). The Partnership and its subsidiaries are committed to allocating the resources necessary to implement the Plan. A core team of individuals has been established to implement and complete the Plan (the "Y2K Team"). The Plan includes developing a comprehensive component inventory of computer hardware, software, embedded chips and third-party interfaces; assessing the risk of non-compliance of each component; identifying the impact of any component failure; assessing Year 2000 compliance of each component; identifying and implementing solutions for non-compliance of components; testing of solutions implemented; and developing contingency plans for mission-critical components and systems. As of February 1999, computer software, hardware, embedded chips, and third-party interfaces have been identified, inventoried, and assessed. Where necessary, remediation, replacement, or adequate work- arounds have been identified and implemented or are in the process of being implemented. Testing of computer hardware, software, and embedded systems is ongoing and is expected to be substantially completed early in the second quarter of 1999. The Plan recognizes that the computer, telecommunications and other systems ("Outside Systems") of outside entities ("Outside Entities") have the potential for major, mission-critical, adverse effects on the conduct of the Partnership's and its subsidiaries' businesses. The Partnership and its subsidiaries do not have control of these Outside Systems. However, the Plan includes an ongoing process of identifying and contacting Outside Entities whose systems have or may have a substantial effect on the Partnership's and its subsidiaries' ability to continue to conduct the mission-critical aspects of their businesses without disruption from Year 2000 problems. The Plan requires the Partnership and its subsidiaries to attempt to inventory and assess the extent to which these Outside Systems may not be Year 2000 compatible. The Y2K Team will attempt reasonably to coordinate with these Outside Entities in an ongoing effort to obtain assurances these Outside Systems will be Year 2000 compatible well before January 1, 2000. A listing of critical Outside Entities has been developed which includes shippers, electrical suppliers, and interconnecting pipelines. Currently, the Y2K team is in the process of contacting these entities to determine their Year 2000 readiness and the extent to which joint testing or mutual contingency planning is required. The assessment of the Year 2000 readiness of Outside Entities is an important factor in the internal contingency planning process. The processes of inventorying, assessing, analyzing, remediating through replacement or adequate work-arounds, testing, and developing contingency plans for mission-critical functions in anticipation of the year 2000 are necessarily iterative processes. That is, the steps are repeated as the Y2K Team learns more about the Year 2000 problem and its effects on internal systems and on Outside Systems, and about the effects that embedded chips may have on the Partnership's and its subsidiaries' systems and Outside Systems. As the steps are repeated, it is likely that new problems will be identified and addressed. The Partnership and its subsidiaries anticipate that they will continue with these processes through January 1, 2000 and, if necessary based on experience, into the year 2000 in order to assess and remediate problems that reasonably can be identified only after the start of the new century. As part of the implementation of the Plan, the Y2K Team has developed a contingency plan to minimize the consequences of potential problems that have not been identified or that cannot be remediated before January 1, 2000. The contingency plan concentrates on those areas that are essential to continuing business operations and/or safety of its personnel and the public. These areas include, but are not limited to, systems that are used to operate and control the Pipeline System and enable the physical transportation of natural gas. The contingency plan includes the creation of teams that will be standing by on December 31, 1999, prepared to respond rapidly and otherwise as necessary to mission-critical Year 2000-related problems as soon as they become known. The composition of teams that are assigned to deal with Year 2000 problems will vary according to the mission-critical nature and location of the problem. The contingency plan is dynamic and will be continually revised as potential new problem areas are identified and areas are remediated. The Partnership and its subsidiaries have not incurred material historical costs associated with the Year 2000 issues. Further, the Partnership and its subsidiaries anticipate that their future costs of implementing the Plan will not be material. Although management believes its estimates are reasonable, there can be no assurance, for the reasons stated in the following paragraph, that the actual costs of implementing the Plan will not differ materially from the estimated costs or that the Partnership and its subsidiaries will not be adversely affected by Year 2000 issues. The extent and magnitude of the Year 2000 problem as it may affect the Partnership and its subsidiaries, both before and for some period after January 1, 2000, are difficult to predict or quantify for a number of reasons. Among the most important is the potential complexity of locating embedded microprocessors that may be in a great variety of hardware used for process or flow control, environmental, transportation, access, communications and other systems. The Partnership and its subsidiaries believe that they will be able to identify and remediate mission-critical systems containing embedded microprocessors or will have contingency plans to deal with these systems. Other important difficulties relate to the lack of control over and difficulty inventorying, assessing, remediating, verifying and testing Outside Systems; the complexity of evaluating all software (computer code) internal to the Partnership and its subsidiaries that may not be Year 2000 compatible; and the potential limited availability of certain necessary internal or external resources, including but not limited to trained hardware and software engineers, technicians and other personnel to perform adequate remediation, verification and testing of internal systems or Outside Systems. Year 2000 costs are difficult to estimate accurately because of unanticipated vendor delays, technical difficulties, the impact of tests of Outside Systems, and similar events. There can be no assurance for example that all Outside Systems will be adequately remediated so that they are Year 2000 ready by January 1, 2000, or by some earlier date, so as not to create a material disruption to business. If, despite diligent, prudent efforts under the Plan, there are Year 2000-related failures that create substantial disruptions to the Partnership and its subsidiaries' businesses, the adverse impact could be material. Moreover, the estimated costs of pursuing the current course of action do not take into account the costs, if any, that might be incurred as a result of Year 2000-related failures that occur despite implementation of the Plan, as it may be modified over time. In a recent SEC release regarding Year 2000 disclosures, the SEC stated that public companies must disclose the most reasonably likely worst case Year 2000 scenario. Analysis of the most reasonably likely worst case Year 2000 scenarios the Partnership may face leads to contemplation of the following possibilities: widespread failure of electrical, gas, and similar supplies by utilities serving the Partnership; widespread disruption of the services of communications common carriers; similar disruption to means and modes of transportation for the Partnership and its employees, contractors, suppliers, and customers; significant disruption to the Partnership's ability to gain access to, and remain working in, office buildings and other facilities; the failure of substantial numbers of the Partnership's mission-critical information (computer) hardware and software systems, including both internal business systems and systems (such as those with embedded chips) controlling operational facilities such as electrical generation, transmission, and distribution systems; and the failure of Outside Systems, the effects of which would have a cumulative material adverse impact on the Partnership's mission-critical systems. Among other things, the Partnership could face substantial claims due to service interruptions, inability to fulfill contractual obligations, inability to account for certain revenues or obligations or to bill shippers accurately and on a timely basis, and increased expenses associated with litigation, stabilization of operations following mission-critical failures, and the execution of contingency plans. The Partnership could also experience an inability by shippers to pay, on a timely basis or at all, obligations owed to the Partnership. Under these circumstances, the adverse effect on the Partnership, and the diminution of the Partnership's revenues, would be material, although not quantifiable at this time. The Partnership will continue to monitor business conditions with the aim of assessing and quantifying material adverse effects, if any, that result or may result from the Year 2000 problem. Information Regarding Forward Looking Statements Statements in this Annual 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 under "Business-Future Demand and Competition" and elsewhere regarding Northern Border Pipeline's efforts to pursue opportunities to further increase its capacity, 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 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, 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, developments relating to the renewal of the pipeline right-of-way lease within the Fort Peck Indian Reservation and right-of-way grants involving allotted lands of the reservation, competitive developments by Canadian and U.S. natural gas transmission peers, political and regulatory developments in Canada, conditions of the capital markets and equity markets, and the Partnership's ability to successfully implement the Year 2000 Plan during the periods covered by the forward looking statements. Item 7a. Quantitative and Qualitative Disclosures About Market Risk The Partnership's interest rate exposure results from its variable rate borrowings from commercial banks. 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 increase the portion of its fixed rate debt and uses interest rate forward agreements to establish an approximate effective borrowing rate for anticipated long-term debt issuances. If interest rates average one percentage point more than rates in effect as of December 31, 1998, the Partnership's consolidated annual interest expense would increase by approximately $6.2 million. This amount has been determined by considering the impact of the hypothetical interest rates on the Partnership's variable rate borrowings and interest rate swap agreements outstanding as of December 31, 1998. Approximately $5.2 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 Northern Border Pipeline would be allowed to recover the increase in its interest expense, if it were to occur. Thus, the estimated impact on the Partnership's annual earnings and cash flow from a hypothetical one percentage point increase in interest rates would be a reduction of approximately $1.0 million related to interest expense on borrowings other than by Northern Border Pipeline. Item 8. Financial Statements and Supplementary Data The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. Item 9. Disagreements on Accounting and Financial Disclosure None. Item 10. Partnership Management The Partnership is 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 the Partnership's independent public accountants, reviewing the Partnership's 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 the Partnership. As is commonly the case with publicly-traded partnerships, the Partnership does 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. The Partnership has entered into an agreement (the "Administrative Services Agreement") with NBP Services Corporation ("NBP Services"), 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, the Partnership's representatives on the Northern Border Management Committee and the persons designated by the Partnership Policy Committee as executive officers of the Partnership and as Audit Committee members. All members of the Partnership Policy Committee and the Partnership's representatives on the Northern Border Management Committee serve at the discretion of the General Partner that appointed them, and the persons designated as executive officers serve in that capacity at the discretion of the Partnership Policy Committee. Effective December 22, 1998, Stanley C. Horton replaced George L. Mazanec as a member of the Partnership Policy Committee and the representative on the Northern Border Management Committee designated by Pan 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 57 Chief Executive Officer Jerry L. Peters 41 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: Larry L. DeRoin 57 Chairman Stanley C. Horton 49 Member Brian E. O'Neill 61 Member Members of Audit Committee: Daniel P. Whitty 67 Chairman Gerald B. Smith 48 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 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 Operating Officer of Enron Operations Corp. From June 1993 to February 1996, he was President and Chief Operating Officer of Enron Pipeline and Liquids Group. He is a director of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P. Brian E. O'Neill was appointed to the Partnership Policy Committee in July 1993. Mr. O'Neill is President and Chairman of the Board of Williams Gas Pipelines, Inc. He is President and Chief Executive Officer of Kern River Acquisition Corporation, Northwest Pipeline Corporation, Williams Western Pipeline Company, Williams Natural Gas Company, Transco and Texas Gas Transmission Corporation. He was elected to his position at Kern River Acquisition Corporation in 1996. He was elected to his position at Transco and Texas Gas Transmission Corporation in 1995. He was elected to his positions at Northwest Pipeline Corporation and Williams Western Pipeline Company effective January 1, 1994. He was elected President of Williams Natural Gas Company in 1988. He is a director of Daniel Industries, Inc. He has served on the Northern Border Management Committee since April 1993. Jerry L. Peters was named Chief Financial and Accounting Officer in July 1994. Mr. Peters has held several management positions with Northern Plains since 1985 and was elected Treasurer for Northern Plains in October 1998, Vice President of Finance for Northern Plains in July 1994, and director of Northern Plains in August 1994. Prior to joining Northern Plains in 1985, Mr. Peters was employed as a Certified Public Accountant by KPMG Peat Marwick, LLP. Daniel P. Whitty was appointed to the Audit Committee in December 1993. Mr. Whitty is an independent financial consultant. He is a director of Enron Equity Corp. and of EOTT Energy Corp., both subsidiaries of Enron, and the latter of which is the general partner of EOTT Energy Partners, L.P. He has served as a member of the Board of Directors of Methodist Retirement Communities Inc., and a Trustee of the Methodist Retirement Trust. Mr. Whitty was a partner at Arthur Andersen & Co. until his retirement on January 31, 1988. Gerald B. Smith was appointed to the Audit Committee in April 1994. He is Chief Executive Officer and co-founder of Smith, Graham & Co., a fixed income investment management firm, which was founded in 1990. He is a director of Pennzoil Quaker State Co., Alliance Capital, Community Partners and First Interstate Bank of Texas, N.A. From 1988 to 1990, he served as Senior Vice President and Director of Fixed Income and Chairman of the Executive Committee of Underwood Neuhaus & Co. Item 11. Executive Compensation The following table summarizes certain information regarding compensation paid or accrued during each of Northern Plains' last three fiscal years to the executive officers of the Partnership (the "Named Officers") for services performed in their capacities as executive officers of Northern Plains: Summary Compensation Table
All Other Annual Compensation Long-Term Compensation Compensation Other Securities Annual Restricted Underlying LTIP Compensation Stock Options/ Payouts Name & Position Year Salary Bonus (1) (2) Awards (3) SARs (#) (4) (5) Larry L. DeRoin 1998 $256,067 $250,000 $ 7,200 $125,024 9,510 $ - $6,380 Chief Executive 1997 $247,333 $200,000 $11,908 $ - 15,285 $ - $ - Officer 1996 $239,667 $144,000 $ 6,900 $ - 18,220 $56,250 $1,102 Jerry L. Peters 1998 $123,225 $110,000 $ 1,214 $ 60,030 10,000 $ - $1,956 Chief Financial and 1997 $118,750 $ 47,500 $ 1,200 $ - 5,715 $ - $ - Accounting Officer 1996 $114,525 $ 28,000 $ - $ - 5,045 $ - $ 767 (1) For 1996 and 1997, Mr. Peters' bonus awards were $48,000 and $80,000, respectively. The bonuses detailed exclude amounts deferred into the Bonus Stock Option Program. Mr. Peters received a grant of 3,215 options during 1997 in lieu of a $20,000 cash bonus payment for 1996 and 4,435 options during 1998 in lieu of a $32,500 cash bonus payment for 1997. The 1998 amount reflects the full bonus earned, including deferrals. (2) Includes "Perquisites and Other Personal Benefits" if value is greater than the lesser of $50,000 or 10% of reported salary and bonus. Also, under Enron's 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 1996, 1997 and 1998 was the minimum rate of 12%. No interest has been reported as Other Annual Compensation under Enron's 1985 Deferral Plan for participating Named Officers because the crediting rates during 1996, 1997 and 1998, did not exceed 120% of the long-term Applicable Federal Rate ("AFR") of 14.38% in effect at the time the 1985 Deferral Plan was implemented. Interest has been reported as Other Annual Compensation under Enron's 1994 Deferral Plan during 1996 for the participating Named Officers because the crediting rate of 9% exceeded 120% of the AFR of 7.29% in effect at the time the 1994 Deferral Plan was implemented. Beginning January 1, 1996, Enron's 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 Enron's 1994 Deferral Plan during 1996, 1997 and 1998. Other Annual Compensation also includes cash perquisite allowances. (3) The aggregate total of shares in unreleased Enron restricted stock holdings and their values as of December 31, 1998, for each of the Named Officers is: Mr. DeRoin, 2,191 shares valued at $125,024; Mr. Peters, 1,052 shares valued at $60,030. This represents performance based restricted stock which was granted in lieu of performance units for the 1999-2002 performance period. Assuming continuous employment with Enron or an Affiliate, the Award will become vested and will be released January 31, 2002 as follows: (a) 33-1/3% of the total number of shares granted will vest and be released if earnings targets, as set by the Board of Directors of Enron in its sole discretion, are met in any one year of the three year period 1999, 2000 and 2001, (b) 66-2/3% of the total number of shares granted will vest and be released if earnings targets, as set by the Board of Directors of Enron in its sole discretion, are met in any two years of the three year period 1999, 2000 and 2001, and (c) 100% of the Total Number of Shares Granted will vest and be released if earnings targets, as set by the Board of Directors of Enron in its sole discretion, are met in each of the three years or cumulatively over the three year period 1999, 2000 and 2001. Shares of Restricted Stock which do not become vested according to the above provisions will be canceled. (4) The amount shown for 1996 for Mr. DeRoin represent payouts made under Enron's Performance Unit Plan account. (5) The amounts shown include the value, as of year-end 1996 and 1998, of Enron Common Stock allocated during those years to employees' special subaccounts under Enron's Employee Stock Ownership Plan, and 1998 matching contributions to employees' Enron Corp. Savings Plan.
Stock Option Grants During 1998 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 1998.
Individual Grants % of Total Potential Realizable Value at Options/ Options/SARs Exercise Assumed Annual Rates of SARs Granted to or Base Stock Price Appreciation Granted Employees in Price Expiration For Option Term (6) Name (#) (1) Fiscal Year ($/Sh) Date 0%(5) 5% 10% Larry L DeRoin 9,510 (2) 0.12% $57.0625 12/31/05 $ - $ 220,920 $ 514,835 Jerry L. Peters 4,435 (3) 0.06% $40.1250 01/19/05 $ - $ 72,446 $ 168,829 1,000 (4) 0.01% $50.9375 10/12/08 $ - $ 32,035 $ 81,182 4,565 (2) 0.06% $57.0625 12/31/05 $ - $ 106,046 $ 247,132 All Employee and Director Optionees 7,854,054 (7) 100% $49.9120 (8) N/A $ - $ 246,534,043(9) $ 624,765,648 (9) All Stockholders N/A N/A N/A N/A $ - $10,386,143,976(9) $26,320,527,193 (9) Optionee Gain as % of All Stockholders Gain N/A N/A N/A N/A N/A 2.37% 2.37% (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) Represents stock options awarded under the Long-Term Incentive Program for 1999. Grants under this program are granted on the last trading day of the prior year, due to regulations under Section 162(m) of the Internal Revenue Code. Options have a seven year term, and are 25% vested on the date of grant with an additional 25% vesting on the anniversary of the date of grant through December 31, 2001. (3) Represents stock options in lieu of 1997 bonus payment in January 1998. Options have a seven year term and immediate vesting. (4) Represents stock options awarded for retention purposes. Options have a ten year term, and are 20% vested on the date of grant with an additional 20% vesting on each anniversary of the date of grant through October 12, 2002. (5) 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. (6) 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. (7) Includes shares issued on December 31, 1998 under the All Employee Stock Option Program to employees hired during 1998. (8) Weighted average exercise price of all Enron stock options granted to employees in 1998. (9) Appreciation for All Employee and Director Optionees is calculated using the maximum allowable option term of 10 years, even though in some cases the actual option term is less than 10 years. Appreciation for all stockholders is calculated using an assumed ten-year option term, the weighted average exercise price for All Employee and Director Optionees ($49.9120) and the number of shares of Common Stock issued and outstanding on December 31, 1998.
Aggregated Stock Option/SAR Exercises During 1998 and Stock Option/SAR Values as of December 31, 1998 The following table sets forth information with respect to the Named Officers concerning the exercise of Enron SARs and options during the last fiscal year and unexercised Enron options and SARs held as of the end of the fiscal year:
Number of Securities Underlying Unexercised Value of Unexercised Shares Options/SARs at In-the-Money Options/ Acquired on Value December 31, 1998 SARs at December 31, 1998 Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable Larry L. DeRoin 96,745 $2,901,089 51,438 19,827 $995,040 $218,105 Jerry L. Peters 3,145 $ 77,736 21,450 6,795 $410,704 $ 51,864
Long-Term Incentive Plan - Awards in 1998 The following table provides information concerning Long-Term Incentive Plan awards under the Performance Unit Plan of Enron for the 1998-2001 performance period. Grants are made at the beginning of each fiscal year and each unit is assigned a value of $1.00. The units are subject to a four-year performance period, at the end of which Enron's total shareholder return is compared to that of the 11 peer companies included in the Current Peer Group. At that time, the units are assigned a value ranging from $0 to $2.00 based on the rank of Enron's shareholder return within the Current Peer Group. To be valued at the maximum of $2.00, Enron must rank first, and to be valued at the target of $1.00, Enron must rank third. Regardless of Enron's rank, Enron's shareholder return must be above the return on 90-day U.S. Treasury Bills over the same performance period in order for any value to be assigned.
Number of Shares, Performance or Estimated Future Payouts Units or Other Other Period Until Under Non-Stock Price-Based Plans Name Rights (#) Maturation Payout Threshold ($) Target ($) Maximum ($) Larry L.DeRoin 100,000 4 years $ - $100,000 $200,000
Retirement and Supplemental Benefit Plans Enron maintains the Enron Corp. Cash Balance Plan (the "Cash Balance Plan") which is a noncontributory defined benefit 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. December 31, 1993, was the final date on which ESOP allocations were made to employees' retirement accounts. In addition, Enron has a Supplemental Retirement Plan that is designed to assure payments to certain employees of that retirement income that would be provided under the Cash Balance Plan except for the dollar limitation on accrued benefits imposed by the Internal Revenue Code of 1986, as amended, and a Pension Program for Deferral Plan Participants that provides supplemental retirement benefits equal to any reduction in benefits due to deferral of salary into Enron's Deferral Plan. The following table sets forth the estimated annual benefits payable under normal retirement at age 65, assuming current remuneration levels without any salary or bonus projections and participation until normal retirement at age 65, with respect to the named officers under the provisions of the foregoing retirement plans.
Estimated Current Credited Current Estimated Credited Years of Compensation Annual Benefit Years of Service Covered Payable Upon Service at Age 65 By Plans Retirement Mr. DeRoin 31.3 39.0 $256,067 $138,009 Mr. Peters 13.9 37.8 $123,225 $ 71,933 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 10, 1999 by the Partnership's executive officers, members of the Partnership Policy Committee and the Audit Committee and certain beneficial owners. Other than as set forth below, no person is known by the General Partners to own beneficially more than 5% of the voting securities.
Amount and Nature of Beneficial Ownership Common Units Number Percent of Units1/ of Class Larry L. DeRoin 10,000 * 1111 South 103rd Street Omaha, NE 68124-1000 Jerry L. Peters 1,300 * 1111 South 103rd Street Omaha, NE 68124-1000 The Williams Companies, Inc.2/ 1,123,500 3.8 One Williams Center Tulsa, OK 74101-3288 Enron Corp.2/ 3,210,000 10.9 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.
Item 13. Certain Relationships and Related Transactions The Partnership has 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, in which the Partnership owns a 70% general partner interest, 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 or Enron, provided project management for the construction of The Chicago Project pursuant to a Project Management Agreement between Northern Plains and EE&CC. In addition, as of February 1, 1999, (i) ECT, an affiliate of Enron, is a transportation customer of Northern Border Pipeline, which is obligated to pay 5% of Northern Border Pipeline's annual cost of service; (ii) Northern Natural, an affiliate of Enron, provides a financial guaranty for a portion (300 MMCFD) of the transportation capacity held by PAGUS, which represents 11% of Northern Border Pipeline's annual cost of service; (iii) TransCanada Gas Services Inc. ("TransCanada Gas Services"), an affiliate of TransCanada, is a transportation customer of Northern Border Pipeline which is obligated to pay 11% of Northern Border Pipeline's annual cost of service pursuant to a transportation contract with Northern Border Pipeline wherein TransCanada Gas Services acts as the agent of its parent, TransCanada and (vi) Transco, an affiliate of Williams, is a transportation customer of Northern Border Pipeline which is obligated to pay 1% of Northern Border Pipeline's annual cost of service. The Partnership Policy Committee, whose members are designated by the three General Partners, establishes the business policies of the Partnership. The Partnership has 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 the General Partners. The Partnership's interests could conflict with the interests of the 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 the Partnership's best interest. Northern Border Pipeline's interests could conflict with the Partnership's interest or the interest of TransCanada and their affiliates, and in such case the Partnership's 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. The Partnership's fiduciary duty as a general partner of Northern Border Pipeline may restrict the Partnership from taking actions that might be in the Partnership's best interest but in conflict with the fiduciary duty that the Partnership's representatives or the Partnership 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, the Partnership's 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 the Partnership's 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 the Partnership or its unitholders if the resolution of a conflict is fair and reasonable to the Partnership. 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. * The Partnership's 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 the Partnership, on the other. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to the Partnership. * The Partnership has proposed to enter into an amendment to the partnership agreement for Northern Border Pipeline that relieves TransCanada, its affiliates and their transferees from any duty to offer business opportunities to Northern Border Pipeline, with certain exceptions. The proposed amendment would also relieve the Partnership from any duty to offer to Northern Border Pipeline certain business opportunities that come to the Partnership's attention. The Partnership is required to indemnify the members of the Partnership Policy Committee and General Partners, their affiliates and their respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than one of the General Partners) not opposed to, the Partnership's best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful. PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a)(1) and (2) Financial Statements and Financial Statement Schedules See "Index to Financial Statements" set forth on page F-1. (a)(3) Exhibits * 3.1 Form of Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (Exhibit 3.1 No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *10.1 Form of Amended and Restated Agreement of Limited Partnership For Northern Border Intermediate Limited Partnership (Exhibit 10.1 to Form S-1). *10.2 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (Exhibit 10.2 to Form S-1). *10.3 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.4 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (Exhibit 10.4 to Form S-1). *10.5 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.5.1 Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K")). *10.6 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *10.7 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., dated June 22, 1990 (Exhibit 10.10 to Form S-1). *10.7.1 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc. (Exhibit 10.10.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")). *10.7.2 Amended Exhibit A to Northern Border Pipeline U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., effective November 1, 1994 (Exhibit 10.10.2 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1994). *10.7.3 Amended Exhibit A's to Northern Border Pipeline Company U.S. Shipper Service Agreement effective, August 1, 1995 and November 1, 1995 (Exhibit 10.10.3 to 1995 10-K). *10.7.4 Amended Exhibit A to Northern Border Pipeline Company U.S. Shipper Service Agreement effective April l, 1998 (Exhibit 10.10.4 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1997 ("1997 10-K")). *10.8 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.9 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K) *10.10 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Western Gas Marketing Limited, as agent for TransCanada PipeLines Limited, dated December 15, 1980 (Exhibit 10.13 to Form S-1). *10.10.1 Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.11 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.12 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Transcontinental Gas Pipe Line Corporation, dated July 14, 1983, with Amended Exhibit A effective February 11, 1994 (Exhibit 10.17 to 1995 10-K). *10.13 Form of Credit Agreement among Northern Border Pipeline Company, The First National Bank of Chicago, as Administrative Agent, The First National Bank of Chicago, Royal Bank of Canada, and Bank of America National Trust and Savings Association, as Syndication Agents, First Chicago Capital Markets, Inc., Royal Bank of Canada, and BancAmerica Securities, Inc, as Joint Arrangers and Lenders (as defined therein) dated as of June 16, 1997 (Exhibit 10(c) to Amendment No. 1 to Form S-3, Registration Statement No. 333-40601 ("Form S-3")). *10.14 Form of Credit Agreement among Northern Border Partners, L.P., Canadian Imperial Bank of Commerce, as Agent and Lenders (as defined therein) dated as of November 6, 1997 (Exhibit 10(d) to Amendment No. 1 to Form S-3). *10.15 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.21 to 1997 10-K). *10.16 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.22 to 1997 10-K). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 with Amendment dated September 25, 1997 (Exhibit 10.25 to 1997 10-K). *10.18 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 (Exhibit 10.26 to 1997 10-K). *10.19 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.27 to 1997 10-K). *10.20 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.28 to 1997 10-K). 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership, Northern Border Pipeline Company, Black Mesa Holdings, Inc., Black Mesa Pipeline, Inc., Black Mesa Pipeline Operations L.L.C. Williams Technologies, Inc. and Williams Technologies L.L.C. 23.01 Consent of Arthur Andersen LLP. *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 1998. 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 18th day of March, 1999. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) By: LARRY L. DEROIN Larry L. DeRoin Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. Signature Title Date LARRY L. DEROIN Chief Executive Officer and March 18, 1999 Larry L. DeRoin Chairman of the Partnership Policy Committee (Principal Executive Officer) STANLEY C. HORTON Member of Partnership Policy March 18, 1999 Stanley C. Horton Committee BRIAN E. O'NEILL Member of Partnership Policy March 18, 1999 Brian E. O'Neill Committee JERRY L. PETERS Chief Financial and March 18, 1999 Jerry L. Peters Accounting Officer NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS Page No. Consolidated Financial Statements Report of Independent Public Accountants F-2 Consolidated Balance Sheet - December 31, 1998 and 1997 F-3 Consolidated Statement of Income - Years Ended F-4 December 31, 1998, 1997 and 1996 Consolidated Statement of Cash Flows - Years Ended F-5 December 31, 1998, 1997 and 1996 Consolidated Statement of Changes in Partners' Capital - F-6 Years Ended December 31, 1998, 1997 and 1996 Notes to Consolidated Financial Statements F-7 through F-18 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 sheets of Northern Border Partners, L.P., a Delaware limited partnership, and Subsidiaries as of December 31, 1998 and 1997, 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, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern Border Partners, L.P. and Subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Omaha, Nebraska, January 19, 1999 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (In Thousands)
December 31, 1998 1997 1998 1997 ASSETS CURRENT ASSETS Cash and cash equivalents $ 41,042 $ 106,757 Accounts receivable 19,077 18,139 Related party receivables 2,470 1,780 Materials and supplies, at cost 4,189 4,458 Under recovered cost of service 2,781 -- Total current assets 69,559 131,134 TRANSMISSION PLANT Property, plant and equipment 2,345,700 1,749,862 Less: Accumulated provision for depreciation and amortization 615,224 631,498 Net property, plant and equipment 1,730,476 1,118,364 OTHER ASSETS 25,731 17,419 Total assets $1,825,766 $1,266,917 LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Current maturities of long-term debt $ 2,805 $ 2,523 Accounts payable 46,032 64,668 Accrued taxes other than income 20,140 20,508 Accrued interest 12,462 10,766 Over recovered cost of service -- 4,601 Total current liabilities 81,439 103,066 LONG-TERM DEBT, net of current maturities 974,027 478,832 MINORITY INTERESTS IN PARTNERS' CAPITAL 253,031 174,424 RESERVES AND DEFERRED CREDITS 9,843 9,867 COMMITMENTS AND CONTINGENCIES (NOTE 7) PARTNERS' CAPITAL General Partners 10,148 10,015 Common Units 401,388 394,587 Subordinated Units 95,890 96,126 Total partners' capital 507,426 500,728 Total liabilities and partners' capital $1,825,766 $1,266,917 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, 1998 1997 1996 OPERATING REVENUE $217,592 $198,574 $201,943 OPERATING EXPENSES Operations and maintenance 44,770 37,418 28,366 Depreciation and amortization 43,536 40,172 46,979 Taxes other than income 22,012 22,836 24,390 Regulatory credit (8,878) -- -- Operating expenses 101,440 100,426 99,735 OPERATING INCOME 116,152 98,148 102,208 INTEREST EXPENSE Interest expense 49,923 34,520 33,117 Interest expense capitalized (19,001) (3,660) (447) Interest expense, net 30,922 30,860 32,670 OTHER INCOME Allowance for equity funds used during construction 10,237 1,400 396 Other income, net 2,622 6,589 2,504 Other income 12,859 7,989 2,900 MINORITY INTERESTS IN NET INCOME 30,069 22,253 22,153 NET INCOME TO PARTNERS $ 68,020 $ 53,024 $ 50,285 NET INCOME PER UNIT $ 2.27 $ 1.97 $ 1.88 NUMBER OF UNITS USED IN COMPUTATION 29,345 26,392 26,200 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, 1998 1997 1996 CASH FLOWS FROM OPERATING ACTIVITIES: Net income to partners $ 68,020 $ 53,024 $ 50,285 Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 43,551 40,179 47,010 Minority interests in net income 30,069 22,253 22,153 Provision for billings subject to refund -- 40,403 12,227 Refunds to shippers -- (52,630) -- Allowance for equity funds used during construction (10,237) (1,400) (396) Regulatory credit (9,105) -- -- Changes in other current assets and liabilities (19,243) 17,101 7,749 Other 794 691 (1,494) Total adjustments 35,829 66,597 87,249 Net cash provided by operating activities 103,849 119,621 137,534 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (652,194) (152,658) (18,597) Acquisition and consolidation of businesses -- 3,374 -- Other -- (586) (4,796) Net cash used in investing activities (652,194) (149,870) (23,393) CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions General and limited partners (68,876) (58,957) (58,816) Minority Interests (18,362) (30,080) (30,853) Contributions received from Minority Interests 66,900 24,300 -- Issuance of partnership interests, net 7,554 90,987 -- Issuance of long-term debt 498,000 209,000 -- Long-term debt financing costs (63) (969) -- Retirement of long-term debt (2,523) (128,665) (32,500) Borrowings on (repayment of) note payable -- (10,000) 10,000 Net cash provided by (used in) financing activities 482,630 95,616 (112,169) NET CHANGE IN CASH AND CASH EQUIVALENTS (65,715) 65,367 1,972 Cash and cash equivalents-beginning of period 106,757 41,390 39,418 Cash and cash equivalents-end of period $ 41,042 $ 106,757 $ 41,390 The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (In Thousands)
Total General Common Subordinated Partners' Partners Units Units Capital Partners' Capital at December 31, 1995 $ 8,382 $310,089 $100,646 $419,117 Net income to partners 1,006 37,204 12,075 50,285 Distributions paid (1,176) (43,516) (14,124) (58,816) 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 The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Partners, L.P., a Delaware limited partnership, through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, a Delaware limited partnership, collectively referred to herein as the Partnership, owns a 70% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline). The remaining 30% general partner interests in Northern Border Pipeline are owned by TransCanada Border PipeLine Ltd. (6%) and TransCan Northern Ltd. (24%), both of which are wholly-owned subsidiaries of TransCanada PipeLines Limited (TransCanada). Black Mesa Holdings, Inc. and Black Mesa Pipeline Operations, L.L.C. (collectively Black Mesa) and Williams Technologies, Inc. (WTI) are wholly-owned subsidiaries of the Partnership (see Note 3). 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 nergy Corporation. At the closing, Pan Border's sole asset consisted of its general partner interest in the Partnership. The General Partners or their affiliates also own Subordinated Units representing, in the aggregate, an effective 14.5% limited partner interest in the Partnership at December 31, 1998 (see Note 6). The Partnership is managed by or 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 March 9, 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 the TransCanada subsidiaries. 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 TransCanada votes the remaining 30% interest. The day-to-day management of Northern Border Pipeline's affairs is the responsibility of Northern Plains (the Operator), as defined by the operating agreement between Northern Border Pipeline and Northern Plains. Northern Border Pipeline is charged for the salaries, benefits and expenses of the Operator. Substantially all of the operations and maintenance expenses are paid to the Operator and other Enron affiliates. Additionally, an Enron affiliate was responsible for project management on Norther Border Pipeline's expansion and extension of its pipeline from near Harper, Iowa to a point near Manhattan, Illinois (The Chicago Project) (see Note 7). 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. A subsidiary of the Partnership is the operator of Black Mesa, pursuant to a management agreement. 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 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 Regulations Northern Border Pipeline is subject to regulation by the Federal Energy Regulatory Commission (FERC). Northern Border Pipeline's accounting policies conform to generally accepted accounting principles, as applied in the case of regulated entities. (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 $300 million at both December 31, 1998 and 1997, and are primarily related to accelerated depreciation and other plant-related differences. (E) Property, Plant and Equipment and Related Depreciation and Amortization Property, plant and equipment is stated at original cost. Balances at December 31, 1998 and 1997 include construction work in progress of approximately $1.5 million and $211.4 million, respectively. Approximately $197.9 million of construction work in progress at December 31, 1997, represented project-to-date costs on The Chicago Project. In December 1998, Northern Border Pipeline placed into service the facilities for The Chicago Project. At December 31, 1998 and 1997, respectively, approximately $37.4 million and $44.2 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 changes in other current assets and liabilities 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 gross transmission plant in 1998, 1997, and 1996 was 2.5%, 2.5%, and 3.1%, respectively (see Note 7). At the time The Chicago Project was placed into service, Northern Border Pipeline's depreciation rate was reduced to 2.0%. Beginning in the year 2000, the depreciation rate is scheduled 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 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. (F) Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments. (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 by Northern Border Pipeline in the management of its interest rate exposure. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. As a result, Northern Border Pipeline has entered into various interest rate swap agreements with major financial institutions which hedge interest rate risk by effectively converting certain of its floating rate debt to fixed rate debt. Additionally, Northern Border Pipeline has entered into interest rate forward agreements to hedge the interest rates on a planned issuance of 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. No cost or benefit is currently associated with the interest rate forward agreements. (I) Reclassifications Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation. 3. ACQUISITIONS On May 31, 1997, the Partnership exchanged 125,357 Common Units for all of the outstanding common stock of WTI. Effective with the acquisition of WTI, 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 WTI 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
4. SHIPPER SERVICE AGREEMENTS Operating revenues are collected pursuant to the FERC tariff which directs that Northern Border Pipeline collect its cost of service through firm transportation service agreements (firm service agreements). Northern Border Pipeline's FERC tariff provides an opportunity to recover all operations and maintenance costs of the pipeline, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Billings for the firm service agreements are based on contracted volumes to determine the allocable share of the cost of service and are not dependent upon the percentage of available capacity actually used. Northern Border Pipeline's firm service agreements extend for various terms with termination dates that range from October 2001 to December 2013. Northern Border Pipeline also has interruptible service contracts with numerous other shippers as a result of its self-implementing blanket transportation authority. Revenues received from the interruptible service contracts are credited to the cost of service reducing the billings for the firm service agreements. Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.) Inc. (PAGUS), is presently obligated for approximately 26.5% of the cost of service through three firm service agreements which expire in October 2003. FERC approval is required for the extension of one of the firm service agreements, relating to approximately 6.5% of the cost of service, beyond October 2001. Financial guarantees exist through October 2001 for approximately 17.0% 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, 1998, 1997 and 1996 were $87.3 million, $86.8 million and $95.7 million, respectively. Shippers affiliated with the partners of Northern Border Pipeline have firm service agreements representing approximately 16.9% 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, 1998, 1997 and 1996 were $22.4 million, $20.2 million and $21.4 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, the pipeline receives a monthly demand payment, a per ton commodity payment and a reimbursement for certain other expenses. 5. CREDIT FACILITIES AND LONG-TERM DEBT Detailed information on long-term debt is as follows:
December 31, (In thousands) 1998 1997 Northern Border Pipeline Senior notes - average 8.43%, due from 2000 to 2003 $250,000 $250,000 Pipeline Credit Agreement Five-year revolving credit facility 127,500 127,500 Three-year revolving credit facility 484,500 81,500 Northern Border Partners, L.P. Partnership Credit Agreement - due 2000 95,000 -- Black Mesa 10.7% Note agreement, due quarterly to 2004 19,832 22,355 Total 976,832 481,355 Less: Current maturities of long-term debt 2,805 2,523 Long-term debt $974,027 $478,832
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 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. The three-year revolving credit facility may be converted to a term loan maturing in June 2002 once certain conditions are met. 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 aggregate principal amount of $750 million. At both December 31, 1998 and 1997, Northern Border Pipeline had outstanding interest rate swap agreements with notional amounts of $90 million. Under the agreements, which have a remaining average maturity of approximately one year as of December 31, 1998, 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 both December 31, 1998 and 1997, 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 6.17% and 7.09% at December 31, 1998 and 1997, respectively. During September 1998, Northern Border Pipeline executed interest rate forward agreements with an aggregate notional amount of $150 million to hedge the interest rate for a planned issuance of fixed rate debt during 1999. The average reference interest rate on the agreements, based on ten-year U.S. Treasury Notes, is 4.90%. 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 at December 31, 1998. The maturity date of the Partnership Credit Agreement will be November 2000 if Northern Border Pipeline converts the $550 million three-year revolving credit facility to a term loan; otherwise the maturity date is June 2000. The Partnership Credit Agreement permits 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 facility. At December 31, 1998, the average interest rate on the Partnership Credit Agreement was 6.04%. Interest paid, net of amounts capitalized, during the years ended December 31, 1998, 1997 and 1996 was $28.7 million, $31.6 million and $31.9 million, respectively. Aggregate repayments of long-term debt required for the next five years are as follows: $3 million, $164 million, $44 million, $694 million and $69 million for 1999, 2000, 2001, 2002 and 2003, respectively. The aggregate repayments reflect Northern Border Pipeline's intent and ability to convert the three-year revolving credit facility to a term loan. 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, 1998 and 1997, respectively, $173 million and $81 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. Black Mesa's note agreement is secured by the common stock of Black Mesa and by a guarantee by the Partnership of up to $1.0 million. In addition, the note agreement requires Black Mesa to maintain a deposit of $2.0 million, invested in Treasury bills, in escrow until the debt is retired. The deposit is reflected in other assets on the consolidated balance sheet at December 31, 1998 and 1997. The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the senior notes was approximately $287 million and $276 million at December 31, 1998 and 1997, respectively. The estimated fair value of the Black Mesa note agreement was approximately $23 million and $25 million at December 31, 1998 and 1997, respectively. At both December 31, 1998 and 1997, the estimated fair value which would be payable to terminate the interest rate swap agreements, taking into account current interest rates, was approximately $3 million. The estimated fair value which would be payable to terminate the interest rate forward agreements, taking into account current interest rates, was approximately $3 million at December 31, 1998. 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 approximates the fair value since the interest rates are periodically adjusted to current market conditions. 6. PARTNERS' CAPITAL 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 the 14.5% held collectively by the General Partners or their affiliates); and a 2% general partner interest. At December 31, 1997, partners' capital consisted of 22,702,313 Common Units representing an effective 76.4% limited partner interest in the Partnership; 6,420,000 Subordinated Units representing an effective 21.6% limited partner interest in the Partnership; and a 2% general partner interest. In January 1998 and December 1997, the Partnership sold, through an underwritten public offering, 225,000 Common Units and 2,750,000 Common Units, respectively. The units sold in 1998 resulted from the underwriters exercise of an over-allotment option to purchase a limited number of additional Common Units. In conjunction with the issuance of the additional Common Units, the Partnership's general partners made capital contributions to the Partnership to maintain a 2% general partner interest in accordance with the partnership agreements. The net proceeds, of the public offering and the general partners' capital contributions, of approximately $7.6 million and $90.9 million in 1998 and 1997, respectively, were used by the Partnership to fund a portion of the capital contributions to Northern Border Pipeline for construction of The Chicago Project. The Partnership will make distributions to its partners with respect to each calendar quarter in an amount equal to 100% of its Available Cash. "Available Cash" generally consists of all of the cash receipts of the Partnership adjusted for its cash disbursements and net changes to cash reserves. Available Cash will generally be distributed 98% to the Unitholders and 2% to the General Partners. The holders of Units are entitled to receive the minimum quarterly distribution of $0.55 per Unit per quarter if and to the extent there is sufficient Available Cash. Distributions of Available Cash to the holders of Subordinated Units are subject, while the Subordinated Units remain outstanding, to the rights of the holders of the Common Units to receive the minimum quarterly distribution. The Partnership Policy Committee determined the subordination period ended as a result of satisfying the criteria set forth in the partnership agreement. The holders of Subordinated Units are no longer subordinated to the rights of the holders of Common Units to receive quarterly distributions and the 6,420,000 outstanding Subordinated Units have been converted into an equal number of Common Units effective January 19, 1999. 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. 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 (see Note 11). 7. COMMITMENTS AND CONTINGENCIES Regulatory Proceedings 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 by November 2000 (Project 2000). Project 2000 would afford shippers on the extended pipeline system access to industrial gas consumers in northern Indiana. Project 2000 capital expenditures are estimated at $130 million. 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. Northern Border Pipeline filed the rate case, in compliance with its FERC tariff, for the determination of its allowed equity rate of return and was permitted, pursuant to a December 1995 FERC order, to begin collecting the requested increase in the equity rate of return effective June 1, 1996, subject to refund. 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, the Stipulation reduced the effective depreciation rate applied to Northern Border Pipeline's gross transmission plant from 3.6% to 2.7% for the period June 1, 1996 to December 31, 1996, which resulted in an average effective depreciation rate of 3.1% for the year ended December 31, 1996. Beginning January 1, 1997, the depreciation rate was reduced to 2.5%. 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. Under the terms of the Stipulation, Northern Border Pipeline agreed to further reduce its depreciation rate to 2.0% 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. 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 has been estimated as of the in service date to be $889 million, with the final construction cost estimated to be $892 million. Thus, Northern Border Pipeline's report to the FERC and its shippers in late December 1998, reflected the conclusion that, based on information as of that date, once the budgeted cost has been established, there would be no adjustment to rate base as a result of the PCCM. Northern Border Pipeline is obligated by the Stipulation to update its calculation of the PCCM six months after the in service date of The Chicago Project. The Stipulation requires the calculation of the PCCM to be reviewed by an independent national accounting firm. Several parties to the Stipulation advised the FERC that they may have questions and desire further information about the report, and may possibly wish to test it (or the final report) and its conclusions in an appropriate proceeding in the future. The parties also stated that if it is determined that Northern Border Pipeline is not permitted to include certain claimed costs for The Chicago Project in its rate base, they reserve their rights to seek refunds, with interest, of any overcollections. Although the Partnership believes the initial computation has been made in accordance with the terms of the Stipulation, it is unable to make a definitive determination at this time whether any adjustments will be required. Should subsequent developments cause costs not to be recovered pursuant to the PCCM, a non-cash charge to write down transmission plant may result and such charge could be material to the operating results of the Partnership. During the construction of The Chicago Project, Northern Border Pipeline placed certain new facilities into service in advance of the December 1998 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 is reflected on the consolidated statement of income. The regulatory credit results in a deferral of the cost of service of these new facilities. The regulatory asset that resulted from the cost of service deferral is included in Other Assets on the consolidated balance sheet. Northern Border Pipeline is allowed to recover the regulatory asset from its shippers over a ten-year period commencing with the in service date of The Chicago Project. 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 PROGRAM Total capital expenditures for 1999 are estimated to be $131 million. This includes approximately $30 million for Project 2000 (see Note 7), approximately $85 million for The Chicago Project and approximately $16 million for renewals and replacements of the existing facilities. Approximately $37 million of the capital expenditures for The Chicago Project is for construction completed in 1998. Funds required to meet the 1999 capital expenditures are anticipated to be provided primarily from debt borrowings and internal sources. 9. NET INCOME PER UNIT The General Partners' allocation of net income is based on their combined 2% interest in the Partnership which has been deducted before calculating net income per Unit. The computation of net income per Unit is based on the weighted average number of outstanding Common Units and Subordinated Units. 10. QUARTERLY FINANCIAL DATA (Unaudited)
(In thousands, except Operating Operating Net Income Net Income per unit amounts) Revenue Income to Partners per Unit 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 1997 First Quarter $46,646 $23,818 $13,471 $0.50 Second Quarter 48,069 23,755 12,753 0.48 Third Quarter 52,738 25,737 12,729 0.47 Fourth Quarter 51,121 24,838 14,071 0.51
11. SUBSEQUENT EVENTS On January 19, 1999, the Partnership declared an increase in the quarterly cash distribution from $0.575 per Unit to $0.61 per Unit for the period October 1, 1998 through December 31, 1998. As described in Note 6, since the quarterly distribution amount exceeded $0.605 per Unit, the General Partners were entitled to receive an incentive distribution for the fourth quarter of 1998 of approximately $24 thousand. The distribution is payable February 12, 1999, to the General Partners and to the Unitholders of record at January 29, 1999. 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 19, 1999. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Partners, L.P. and Subsidiaries listed in Item 14 of Part IV of this Form 10-K is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Omaha, Nebraska, January 19, 1999 SCHEDULE II NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (In Thousands)
Column A Column B Column C Column D Column E Additions Deductions Balance at Charged to Charged For Purpose For Beginning Costs and to Other Which Reserves Balance at Description of Year Expenses Accounts Were Created End of Year Reserve for regulatory issues 1998 $6,726 $ -- $-- $ -- $6,726 1997 $5,953 $773 $-- $ -- $6,726 1996 $8,200 $ -- $-- $2,247 $5,953
UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _______________________ EXHIBITS TO F O R M 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 Commission file number: 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 93-1120873 (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 1400 Smith Street, Houston, Texas 77002-7369 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-853-6161 ___________________ EXHIBIT INDEX * 3.1 Form of Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (Exhibit 3.1 No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *10.1 Form of Amended and Restated Agreement of Limited Partnership For Northern Border Intermediate Limited Partnership (Exhibit 10.1 to Form S-1). *10.2 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (Exhibit 10.2 to Form S-1). *10.3 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.4 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (Exhibit 10.4 to Form S-1). *10.5 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.5.1 Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K")). *10.6 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *10.7 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., dated June 22, 1990 (Exhibit 10.10 to Form S-1). *10.7.1 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc. (Exhibit 10.10.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")). *10.7.2 Amended Exhibit A to Northern Border Pipeline U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., effective November 1, 1994 (Exhibit 10.10.2 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1994). *10.7.3 Amended Exhibit A's to Northern Border Pipeline Company U.S. Shipper Service Agreement effective, August 1, 1995 and November 1, 1995 (Exhibit 10.10.3 to 1995 10-K). *10.7.4 Amended Exhibit A to Northern Border Pipeline Company U.S. Shipper Service Agreement effective April l, 1998 (Exhibit 10.10.4 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1997 ("1997 10-K")). *10.8 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.9 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K) *10.10 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Western Gas Marketing Limited, as agent for TransCanada PipeLines Limited, dated December 15, 1980 (Exhibit 10.13 to Form S-1). *10.10.1 Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.11 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.12 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Transcontinental Gas Pipe Line Corporation, dated July 14, 1983, with Amended Exhibit A effective February 11, 1994 (Exhibit 10.17 to 1995 10-K). *10.13 Form of Credit Agreement among Northern Border Pipeline Company, The First National Bank of Chicago, as Administrative Agent, The First National Bank of Chicago, Royal Bank of Canada, and Bank of America National Trust and Savings Association, as Syndication Agents, First Chicago Capital Markets, Inc., Royal Bank of Canada, and BancAmerica Securities, Inc, as Joint Arrangers and Lenders (as defined therein) dated as of June 16, 1997 (Exhibit 10(c) to Amendment No. 1 to Form S-3, Registration Statement No. 333-40601 ("Form S-3")). *10.14 Form of Credit Agreement among Northern Border Partners, L.P., Canadian Imperial Bank of Commerce, as Agent and Lenders (as defined therein) dated as of November 6, 1997 (Exhibit 10(d) to Amendment No.1 to Form S-3). *10.15 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.21 to 1997 10-K). *10.16 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.22 to 1997 10-K). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 with Amendment dated September 25, 1997 (Exhibit 10.25 to 1997 10-K). *10.18 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 (Exhibit 10.26 to 1997 10-K). *10.19 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.27 to 1997 10-K). *10.20 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.28 to 1997 10-K). 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership, Northern Border Pipeline Company, Black Mesa Holdings, Inc., Black Mesa Pipeline, Inc., Black Mesa Pipeline Operations L.L.C. Williams Technologies, Inc. and Williams Technologies L.L.C. 23.01 Consent of Arthur Andersen LLP. *99.1 Northern Plains Natural Gas Company Phantom Unit Plan (Exhibit 99.1 to Form S-8, Registration No. 333-66949). __________ *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. EX-23 2 CONSENTS OF EXPERTS AND COUNSEL Exhibit 23.01 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included in this Annual Report on Form 10-K, into the Company's previously filed Registration Statement File No. 333-40601 and Registration Statement File No. 333-66949. Omaha, Nebraska, March 11, 1999 EX-27 3 ARTICLE 5 FDS FOR 10-K
5 1,000 12-MOS DEC-31-1998 DEC-31-1998 1,659 39,383 21,547 0 4,189 69,559 2,345,700 615,224 1,825,766 81,439 974,027 0 0 0 507,426 1,825,766 0 217,592 0 101,440 0 0 49,923 68,020 0 68,020 0 0 0 68,020 2.27 2.27
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