-----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, EcHWv+CKxI/xwKq2AWkeiJsMXuP6kOqW2GT9J2Ce2e9Qluwjquh6/zswjSqwXIe1 gZf/C0sMxg2RD2Mvnbabpg== 0000909281-97-000001.txt : 19970329 0000909281-97-000001.hdr.sgml : 19970329 ACCESSION NUMBER: 0000909281-97-000001 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NYSE 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: 1934 Act SEC FILE NUMBER: 001-12202 FILM NUMBER: 97566554 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, 1996 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 4, 1997, was approximately $560,865,925. NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS Page No. Part I Item 1. Business 1 Item 2. Properties 12 Item 3. Litigation 13 Item 4. Submission of Matters to a Vote of Security Holders 13 Part II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 14 Item 6. Selected Financial Data (Unaudited) 15 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 16 Item 8. Financial Statements 18 Item 9. Disagreements on Accounting and Financial Disclosure 18 Part III Item 10. Partnership Management 19 Item 11. Executive Compensation 22 Item 12. Security Ownership of Certain Beneficial Owners and Management 29 Item 13. Certain Relationships and Related Transactions 29 Part IV Item 14. Exhibits, Financial Statements and Reports on Form 8-K. 31 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"), Pan Border is a wholly-owned subsidiary of PanEnergy Corp. ("PanEnergy") and Northwest Border is a wholly- owned subsidiary of The Williams Companies, Inc. ("Williams"). The General Partners hold an aggregate 2% general partner interest in the Partnership. The General Partners also own in the aggregate an effective 24% subordinated limited partner interest ("Subordinated Units") in the Partnership. The combined general and limited partner interests in the Partnership of Northern Plains, Pan Border and Northwest Border are 13%, 8.5% and 4.5%, respectively (See "Certain Relationships and Related Transactions"). Northern Border Pipeline owns a 969-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 in the State of Iowa. The Pipeline System has pipeline access to natural gas reserves in the 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 ("syngas") from the Great Plains Coal Gasification Project in North Dakota. Interconnecting pipeline facilities provide Northern Border Pipeline shippers access to markets in the Midwest, as well as other markets throughout the U.S. by transportation, displacement and exchange arrangements. Management of Northern Border Pipeline is overseen by the Northern Border Management Committee, which is comprised of three representatives from the Partnership (one selected 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 170 individuals to operate the Pipeline System. These employees are located at the operating headquarters in Omaha, Nebraska, at locations along the pipeline route and at gas control operations in Houston, Texas. Northern Plains' employees are not represented by any labor union and are not covered by any collective bargaining agreements. 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 transports gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission ("FERC") that allows it to recover operations and maintenance costs of the Pipeline System, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Northern Border Pipeline does not own the gas that it transports and therefore it does not assume any gas commodity price risk. As a result of an acquisition during 1996, the Partnership has a non-controlling ownership position of 60.5% in Black Mesa Pipeline Holdings, Inc. ("Black Mesa"). Black Mesa, through a wholly-owned subsidiary, owns a 273-mile, 18-inch diameter coal slurry pipeline (the "Black Mesa Pipeline") which originates at a coal mine in Kayenta, Arizona. The pipeline traverses westward through northern Arizona to the 1,500 megawatt Mohave Power Station located in Laughlin, Nevada. Black Mesa Pipeline is the sole source of fuel for the Mohave plant, which consumes an average of 4.8 million tons of coal annually. The capacity of Black Mesa Pipeline is fully contracted to the Mohave Power Station coal supplier through the year 2005. Black Mesa Pipeline is operated by Williams Technologies, Inc. of Tulsa, Oklahoma, which is not affiliated with Williams. The Pipeline System The 822-mile portion of the Pipeline System from the Canadian border to Ventura, Iowa, was completed and placed in service in 1982. It was built to transport large quantities of natural gas through large diameter, high operating pressure pipe. Northern Border Pipeline's early operations were, and its current operations continue to be, supported by significant supplies of natural gas in Canada. In addition, the Pipeline System gained access to additional gas supplies from the Williston Basin and Great Plains Coal Gasification Project in the early 1980s. At its northern end, the Pipeline System is connected to the Foothills Pipe Lines (Sask.) Ltd. system in Canada, which in turn is connected to the gathering 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. In the Pipeline System's southern portion, it interconnects with the pipeline facilities of an Enron subsidiary, Northern Natural Gas Company ("Northern Natural"), near Ventura, Iowa, and of Natural Gas Pipeline Company of America ("NGPL") near Harper, Iowa. The Ventura, Iowa interconnect functions as a large market center, where gas volumes transported on the Pipeline System are sold, traded and received for transport to significant consuming markets in the Midwest and to interconnecting pipeline facilities destined for other markets. The Harper, Iowa interconnect with NGPL also provides gas transported through the Pipeline System access to Chicago and other Midwest markets and to interconnecting pipeline facilities destined for other markets. There are seven existing compressor stations on the Pipeline System, and Northern Border Pipeline owns another six sites for compressor stations that may be constructed in the future (See "Demand For Transportation Capacity"). Other facilities include three pipeline field offices and warehouses, five measurement stations and 39 microwave tower sites. There have been two expansions of the Pipeline System since it was placed in service in 1982. An additional compressor station was added in 1991 and an expansion and extension project was completed and placed in service on November 1, 1992. This 1992 project entailed the construction of four compressor stations and the acquisition of approximately 147 miles of a 30-inch diameter pipeline beginning at an interconnect with the original system near Ventura, Iowa and terminating near Harper, Iowa where it interconnects with the facilities of NGPL. As a result of the two expansions, the throughput capacity of the Pipeline System increased by 463 million cubic feet per day ("MMCFD") to 1,675 MMCFD. The 822-mile, 42-inch diameter segment of the Pipeline System was designed (with maximum compression before looping) to transport up to 2,400 MMCFD. The 147-mile, 30-inch diameter segment was designed (with maximum compression before looping) to transport up to 750 MMCFD. The existing compression on the line allows the transportation of 1,675 MMCFD through the 42-inch segment and 386 MMCFD through the 30-inch segment. As a result, an increase in transportation capacity could be achieved through the use of additional compression, which is a cost-effective method of adding capacity to the Pipeline System. Shippers Based upon existing contracts and capacity, 100% of the Pipeline System's firm capacity (at current compression) is contractually committed through October 2001. The Pipeline System serves a number of shippers with diverse financial and market profiles. At the present time, 6% of the firm capacity (based on annual cost of service obligations) is contracted by interstate pipelines. Each of the interstate pipelines is subject to Order 636 (described in greater detail under "FERC Regulation"), and as a result of each of their restructuring proceedings, capacity on the Pipeline System has been retained or may be assigned to that interstate pipeline's suppliers or customers. The remaining firm capacity is contracted to producers, marketers and local distribution companies. Four of the firm shippers are affiliated with general partners of the Partnership or Northern Border Pipeline: Enron Capital & Trade Resources Corp., a subsidiary of Enron; Mobil Natural Gas Inc. through its marketing arrangement with an affiliate of PanEnergy; 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 hold 11% of the firm capacity. Northern Border Pipeline's largest shipper, Pan- Alberta Gas (U.S.) Inc. ("PAGUS"), currently holds 49% of the firm capacity. Affiliates of PanEnergy and Enron provide guaranties for 350 MMCFD (150 MMCFD and 200 MMCFD, respectively) of PAGUS' contractual obligations. The contractual obligation related to PAGUS' remaining 450 MMCFD of capacity is supported by various credit support arrangements including, among others, a letter of credit, an additional guaranty from Northern Natural for 100 MMCFD, an escrow account and an upstream capacity transfer agreement. At the request of PAGUS, in February 1997 Northern Border Pipeline filed an application with the FERC to convert the authority for PAGUS transportation contracts from individually certificated transactions to Northern Border Pipeline's blanket certificate under the FERC regulations. PAGUS requested this conversion for increased operational flexibility and to more fully utilize capacity release provisions. Panhandle Eastern Pipe Line Company, the affiliate of PanEnergy that has provided a guaranty, filed a motion to intervene and protest requesting the FERC to convene a technical conference to determine the effect of the conversion on its obligations and the appropriate credit support for the contract covering 150 MMCFD. This matter is pending before the FERC. Order 636 has created a secondary market in existing Northern Border Pipeline capacity. There have been temporary releases of capacity where the releasing party (which is not relieved of its obligations under its contract) receives credit against its firm transportation contract for revenues received as a result of the temporary release. In addition to the temporary releases, several shippers have permanently released a portion of their capacity to new shippers who have agreed to comply with the underlying contractual and regulatory obligations associated with such capacity. The following table identifies, as of December 31, 1996, Northern Border Pipeline's firm transportation shippers (other than those under temporary releases), the contracted volumes and the current termination dates: FIRM TRANSPORTATION SHIPPERS
SHIPPER MCFD(1) TERMINATION DATE Producer/Marketer Amerada Hess Corporation 40,000 10/31/12 AEC West Ltd 15,073 10/31/04 Enron Capital & Trade Resources Corp. 20,090 10/31/07 Husky Gas Marketing, Inc. 80,000 10/31/10 Mobil Natural Gas, Inc. 30,000 10/31/07 North Canadian Resources Inc. 30,000 10/31/03 Numac Energy (U.S.) Inc. 20,000 10/31/03 9,910 10/31/07 Pan-Alberta Gas (U.S.) Inc. 800,000 10/31/01 Pan Canadian Petroleum Company 13,000 09/19/03 12,000 10/31/03 37,000 10/31/04 Poco Petroleums Ltd. 10,000 10/31/01 5,000 10/31/04 ProGas U.S.A., Inc. 50,000 10/31/01 1,960 09/19/03 Renaissance Energy (U.S.) Inc. 9,942 09/19/03 27,927 10/31/04 12,000 10/31/09 20,000 10/31/10 Salmon Resources Ltd. 30,000 10/31/06 Suncor, Inc. 38,000 10/31/03 15,000 10/31/04 TransCanada Gas Services Inc., agent for TransCanada PipeLines Limited 120,000 10/31/05 Wascana Energy Marketing (U.S.) Inc. 25,000 10/31/04 Westcoast Gas Services Inc. 27,024 09/19/03 10,000 10/31/01 Total Producers/Marketers 1,508,926 Interstate Pipeline ANR Pipeline Company 34,375 07/31/09(2) 1,789 09/19/03 Natural Gas Pipeline Company of America 27,500 12/31/08(2) 5,000 10/31/01 Tennessee Gas Pipeline Company 47,000 12/31/08(2) Transcontinental Gas Pipe Line Corporation 34,375 12/31/08(2) Total Interstate Pipelines 150,039 Local Distribution Company City of Duluth 1,209 09/19/03 Interstate Power Company 1,072 09/19/03 Metropolitan Utilities District 3,712 09/19/03 MidAmerica Energy Company 6,536 09/19/03 Minnegasco 14,928 09/19/03 Northern States Power (MN) 6,347 09/19/03 Northern States Power (WI) 1,182 09/19/03 UtiliCorp United Inc. 7,926 09/19/03 Wisconsin Gas Company 2,431 09/19/03 Wisconsin Power & Light 942 09/19/03 Total Local Distribution Companies 46,285 Total 1,705,250(3) _______________ (1) Based on total maximum receipt quantity committed per shipper expressed as thousand cubic feet per day ("MCFD"). (2) These contracts may be terminated by shippers if the production of syngas is abandoned by Dakota Gasification Company under its gas purchase agreements with these shippers. (3) Total pipeline maximum receipt quantity, based on a summer design capacity, is 1,675,250 MCFD. The total of 1,705,250 MCFD includes inline transfers of 30,000 MCFD.
Demand For Transportation Capacity In 1996, approximately 87% of the natural gas transported by the Pipeline System was produced in the Western Canadian Sedimentary Basin located in the provinces of Alberta, British Columbia and Saskatchewan. The Pipeline System's share of Canadian gas exported to the United States was approximately 20% in 1995. With the existing interconnecting pipeline facilities, Northern Border Pipeline's transportation of natural gas produced in Canada primarily reaches gas consuming markets located in the upper Midwestern portion of the United States. There are two other interstate pipelines that transport Canadian gas into the upper Midwest, Great Lakes Gas Transmission and Viking Gas Transmission, whose combined share of Canadian gas exported to the United States was approximately 14% in 1995. To meet the increasing needs of its shippers, the Pipeline System was upgraded, expanded and extended in 1991 and 1992 (See "The Pipeline System"). These capital improvements increased its capacity from 1,212 MMCFD to 1,675 MMCFD. Since these expansions, Northern Border Pipeline's capacity utilization has increased from an average of 95% of summer design capacity during 1993 to an average of 103% in 1996. Northern Border Pipeline is currently pursuing opportunities to further increase its capacity. On October 13, 1995, Northern Border Pipeline filed with FERC its application, which amended the application previously filed on February 2, 1995, seeking a certificate of public convenience and necessity to extend and expand its existing system by installing approximately (a) 224 miles of 36-inch pipeline from Northern Border Pipeline's current terminus near Harper, Iowa, to a point near Manhattan, Illinois (Chicago area); (b) 19 miles of 30-inch pipeline from the end of the proposed 36-inch pipeline extension to two points of interconnection with the facilities of the Peoples Gas Light and Coke Company (Chicago area); (c) 35 miles of 42- inch and 147 miles of 36-inch pipeline loop; (d) a total of 293,000 horsepower of compression at twelve compressor stations; and (e) nine meter stations and one meter station upgrade (collectively referred to as "The Chicago Project"). The estimated cost of the facilities proposed to be constructed was approximately $800 million in 1995 dollars. New receipts into the Pipeline System are proposed to be 700 MMCFD with 648 MMCFD proposed to be transported through the pipeline extension and 516 MMCFD proposed to be delivered at Harper, Iowa for transport by NGPL on its pipeline. The application sought FERC authorization for a projected in- service date of the facilities in the spring of 1998. Northern Border Pipeline's filing included executed precedent agreements with twenty-one shippers for the proposed capacity and support for "rolled-in" ratemaking treatment which involves the determination that the rates and charges are based on all the facilities' costs combined with the existing facilities, and the proposed and contracted capacity. NGPL filed on October 18, 1995 a companion application with the FERC requesting authority to construct and operate certain facilities needed to increase its pipeline system capacity to accommodate the new deliveries at Harper, Iowa from Northern Border Pipeline. On August 1, 1996, the FERC issued orders which contained preliminary determinations favorable to Northern Border Pipeline and NGPL. The preliminary determinations found that The Chicago Project and NGPL's proposed facilities are required by the public convenience and necessity and Northern Border Pipeline's order authorizes the requested "rolled-in" ratemaking determination. The preliminary determinations contemplate issuance of a final order by the FERC, subject to completion of the environmental review. There are pending rehearing requests of Northern Border Pipeline's order filed by three intervenors which claim that the FERC should not have authorized the construction of the Harper, Iowa to Manhattan, Illinois extension based upon rolling in those costs with the other facility costs. On September 4, 1996, Northern Border Pipeline filed an amendment to its application to reflect limited facility modifications which among other things, reduced environmental impacts and project costs. The Chicago Project facilities proposed to be constructed are the same facilities previously described except for the elimination of the 35 miles of 42-inch pipeline loop and for the change in total compression to 303,500 horsepower. Compression facilities involve the installation of 228,500 horsepower at eight new stations and upgrades at five existing stations by the removal from service of units producing 100,000 horsepower with replacements of units producing 175,000 horsepower. With this amendment, The Chicago Project costs are expected to be approximately $793 million in 1995 dollars ($837 million as estimated with projected inflation), and subject to timely regulatory approvals, The Chicago Project is expected to be ready for service in November 1998. On December 26, 1996, the FERC issued a Notice of Availability of the Draft Environmental Impact Statement ("DEIS") for The Chicago Project and related downstream facilities to be constructed by NGPL to accept and transport deliveries of gas into its pipeline at Harper, Iowa. The DEIS found that The Chicago Project and related downstream facilities of NGPL would have limited adverse environmental impact and with the adoption of certain mitigative measures, would be an environmentally acceptable action. The DEIS also sought additional comments on its analysis of potential system alternatives. The FERC environmental staff stated that a single pipeline from the Harper, Iowa to Chicago, Illinois area would be environmentally preferred but also recognized that there are a number of other factors to be considered. Comments on the DEIS were received through public meetings held in early February, 1997, in Illinois and Iowa and written comments filed by February 18, 1997. Northern Border Pipeline filed comments stating that a single system alternative was not feasible because of the operational, economic and competitive underpinnings of the shippers' contractual commitments to The Chicago Project and any such alternative would cause unacceptable delay. Several shippers also filed comments supporting The Chicago Project. NGPL filed comments alleging that, with modifications it is proposing, the single system alternative of expanding NGPL's facilities would be environmentally preferred. NGPL also filed an application for a certificate of public convenience and necessity on March 19, 1997 proposing to construct additional facilities to transport 663 MMCFD east of Harper, Iowa into the Chicago area and proposing that Northern Border Pipeline enter into a transportation contract to serve its proposed shippers and also those that contracted with NGPL. In response to NGPL's filings, Northern Border Pipeline filed comments opposing NGPL's proposal and supporting the approval of the previous finding that construction and operation of The Chicago Project and NGPL's related downstream facilities as originally proposed is an environmentally acceptable action with certain mitigation measures. Based upon the comments received, a final Environmental Impact Statement will be issued whereupon FERC will be in a position to issue its final certificate resolving these issues. Environmental and Safety Matters The operations of Northern Border Pipeline 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, Natural Gas Pipeline Safety Act of 1969, as amended, and the Pipeline Safety Act of 1992. Northern Border Pipeline has ongoing environmental and safety audit programs. Northern Border Pipeline believes that its operations and facilities are in general compliance with applicable environmental regulations. FERC Regulation General Northern Border Pipeline is subject to extensive regulation by the FERC as a "natural gas company" under the Natural Gas Act (the "NGA"). Under the NGA and the Natural Gas Policy Act ("NGPA"), 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. Northern Border Pipeline's rates and charges for transportation in interstate commerce are subject to regulation by the FERC. FERC regulations and Northern Border Pipeline's tariff (approved by the FERC) have allowed it to recover operations and maintenance costs of the Pipeline System, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Rates charged by natural gas companies may not exceed the just and reasonable rates approved by the FERC. In addition, natural gas companies are prohibited 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. 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. In May 1996, the FERC Staff issued its final audit report on its examination of Northern Border Pipeline's books and records for the period from January 1, 1990 to December 31, 1992. The report required Northern Border Pipeline to record certain adjustments to its accounts including the reclassification of $3.9 million of costs from utility plant in service to a regulatory asset. While this regulatory asset is includable in rate base, Northern Border Pipeline must file with the FERC for the future recovery of this asset through amortization in cost of service. The General Partners indemnified the Partnership with respect to any negative impact on distributions received from Northern Border Pipeline, as a result of this audit, attributable to periods prior to October 1, 1993. The adjustments made to Northern Border Pipeline's accounts and the indemnification received as a result of this audit did not materially affect the Partnership's financial position or results of operations. In December 1991, the FERC staff issued its audit report on its examination of Northern Border Pipeline's books and records for the period January 1, 1987 through December 31, 1989. The report took exception to Northern Border Pipeline's established method of accounting for Alternative Minimum Tax ("AMT") for purposes of calculating rates and charges subject to FERC approval. Northern Border Pipeline's tariff specifies that Northern Border Pipeline calculate the income tax component of its cost of service as if Northern Border Pipeline were a corporation, which Northern Border Pipeline has done since inception. Consequently, the particular income tax circumstances of each Northern Border Pipeline partner have not been utilized to calculate the cost of service. However, the FERC staff asserted that the AMT component of Northern Border Pipeline's rate base should reflect the particular tax circumstances of each individual partner. Northern Border Pipeline did not agree with the position taken by the FERC staff regarding AMT, and a hearing was conducted before an Administrative Law Judge (the "ALJ") on this issue at which Northern Border Pipeline argued that such a result would be contrary to FERC policy and precedent, as well as Northern Border Pipeline's tariff. A decision from the ALJ was received on April 15, 1993, which affirmed Northern Border Pipeline's accounting treatment for AMT. On May 17, 1994, the FERC issued its order reversing that part of the ALJ's decision which held that the AMT component of Northern Border Pipeline's rate base need not reflect the particular tax circumstances of each Northern Border Pipeline partner. Northern Border Pipeline filed a request for rehearing of the May 17, 1994 order. On May 20, 1996, FERC granted rehearing of this order, accepted the ALJ's conclusions and vacated the findings in the May 17, 1994 order. As a result, there were no accounting adjustments or rate refunds required. Firm transportation shippers, ANR Pipeline, NGPL, Tennessee Gas Pipeline Company and Transco, purchase the production of syngas from the plant now owned by Dakota Gasification Company. These shippers may terminate their firm transportation contracts covering contracted volumes of 143,250 MCFD if the production of syngas is abandoned by Dakota Gasification Company under its gas purchase agreements with these shippers. Settlements of disputes between the plant owner and the pipelines were reached in 1993 which modified, inter alia, pricing, volume and term provisions of the pre-existing syngas purchase agreements. In a FERC proceeding, approval of these settlements was sought. NGPL reached an uncontested agreement with its customers regarding its settlement which was approved by the FERC on January 23, 1995. On December 29, 1995, an ALJ issued an initial decision on the three remaining settlements which found, among other things, that the pricing formula proposed under the settlements should be modified and that the customers should only be responsible for costs associated with 137,500 MCFD. In its brief on exceptions to the initial decision, Dakota Gasification Company argued that the price and volume changes ordered by the ALJ could threaten the survival of the plant. The three affected pipelines and the Department of Energy also filed briefs excepting to the initial decision. The FERC issued on December 18, 1996, its order which reversed the ALJ's initial decision. The FERC found the settlements to be just and reasonable and did not limit the volume to 137,500 MCFD. Therefore, the resolution of the disputes are final with no adverse impact to Northern Border Pipeline. Cost of Service Tariff Northern Border Pipeline's firm transportation shippers contract to pay for an allocable share of the Pipeline System's capacity. During any given month, all such shippers pay a uniform charge per dekatherm-mile of capacity contracted, calculated under a cost of service tariff. The shippers' obligations to pay their allocable share of the cost of service is not dependent upon the volumes actually shipped. That is, the cost of service payment obligation is a function of the shippers' contracted capacity. This 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 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 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. Northern Border Pipeline also provides interruptible transportation service. The maximum rate charged to interruptible shippers is calculated from the cost of service estimate on the basis of contracted capacity. Except for any period when the risk conditions described in the next paragraph are applicable, all revenue from the interruptible transportation service is credited back to the firm shippers' accounts. Northern Border Pipeline is at risk for the recovery of the annual cost of service associated with the capacity from both the 1991 and the 1992 expansion projects (See "The Pipeline System"). In the event that a portion of that capacity were to become uncontracted, or the government authorizations to export or import natural gas from Canada were to lapse, FERC has stated that Northern Border Pipeline would not be allowed to recover from the remaining firm shippers on the system that portion of its cost of service related to those facilities and the uncontracted capacity associated with these projects. The cost of service has been levelized due primarily to annual depreciation changes. This means that the annual cost of service, since the effective date of Northern Border Pipeline's 1992 rate case, is designed to be generally level until January 1, 1997 when a higher levelized cost of service was to be effective through 2001. In the 1992 rate case, Northern Border Pipeline committed to make a filing no later than January 1, 1997 to adjust the depreciation rate to reflect the circumstances existing on the Pipeline System at that time. An integral component of The Chicago Project is a proposed change in the depreciation schedule which, if implemented, would extend the Pipeline System's depreciable life for ratemaking purposes. FERC authority to implement a new depreciation schedule, both prior to and after the targeted in-service date of The Chicago Project, has been requested in Northern Border Pipeline's November 1995 rate case proceeding discussed below. In November 1995, Northern Border Pipeline filed a rate case in compliance with its FERC tariff for the determination of its allowed equity rate of return. In this proceeding, Northern Border Pipeline proposed, among other items, to increase its allowed equity rate of return from 12.75% to 14.25%. Pursuant to a December 1995 FERC order, Northern Border Pipeline began collecting the proposed increase in rate of return on equity effective June 1, 1996, subject to refund. After reaching a settlement accord with a majority of its shippers, on October 15, 1996, Northern Border Pipeline filed for FERC approval of a Stipulation and Agreement ("Stipulation") to settle its rate case. The Stipulation would allow Northern Border Pipeline a 12.75% equity rate of return from June 1, 1996 to September 30, 1996, and a 12% rate beginning October 1, 1996. In addition, the depreciation rates applied to Northern Border Pipeline's gross transmission plant would be reduced effective June 1, 1996, from 3.6% to 2.7% thereby fulfilling the requirement in Northern Border Pipeline's 1992 rate case. Another issue addressed in the Stipulation was the allowance for income taxes. The FERC had previously ruled in a case involving Lakehead Pipe Line Company L.P. that an income tax allowance would not be allowed with respect to income attributable to the limited partnership interests held by individuals. During the rate case proceeding, Northern Border Pipeline filed testimony regarding what it believed to be the proper application of this FERC ruling to its circumstances. The Partnership believes the Stipulation, if approved, effectively resolves the income tax issue for the Shippers at least through 2005 and Northern Border Pipeline can continue to include an allowance for income taxes at the current level in its cost of service. Under the Stipulation, in connection with the completion of The Chicago Project, Northern Border Pipeline would implement a new depreciation schedule with an extended depreciable life, a capital project cost containment mechanism and a $31 million settlement adjustment mechanism. The capital project cost containment mechanism would allocate variances in actual construction costs between Northern Border Pipeline and its Shippers through adjustments to rate base. The settlement adjustment mechanism would effectively reduce the allowed return on rate base. One participant, NGPL, who as a firm shipper is responsible for 1.6% of the annual cost of service cost has filed comments alleging that the Stipulation is contrary to FERC policy. On November 19, 1996, the Stipulation was certified by an ALJ to the FERC for review and approval. Northern Border Pipeline must receive FERC approval of the Stipulation before it can implement all of the filed for terms and any associated refunds. The Partnership is unable to predict if or when the Stipulation will be approved as filed and thus the effect of this rate proceeding on future operating results of Northern Border Pipeline cannot be determined at this time. Open Access Regulation The FERC issued Order No. 636 on April 8, 1992, Order No. 636-A, an order on rehearing of Order 636, on August 3, 1992, and a further order on rehearing, Order No. 636-B, on November 27, 1992 (together, "Order 636"). Among other things, Order 636 required companies to unbundle their services and offer sales, transportation, storage, gathering and other services separately; to permanently assign their firm capacity on upstream pipelines to firm shippers wanting such capacity; and to provide all transportation services on a basis that is equal in quality for all shippers. Order 636 was substantially affirmed by the United States Court of Appeals for the District of Columbia. With respect to the limited aspects of Order 636 that the court remanded to the FERC, only one issue, the "right of first refusal" ("ROFR") procedures (imposed by FERC as a condition to the pipeline's right to abandon long-term transportation service), is relevant to Northern Border Pipeline operations. The ROFR procedures required existing shippers to match any bid of up to twenty years in order to retain their capacity. The court upheld the basic structure of FERC's rules, but remanded the ROFR mechanism for further explanation of why a twenty-year term-matching cap was adopted. The FERC, on remand, adopted a five-year matching cap. The effect of this ruling on Northern Border Pipeline's ability to renew or recontract firm capacity under long-term service agreements once existing agreements expire cannot be quantified at this time. On July 17, 1996, the FERC issued Order No. 587 amending its open access regulations to standardize certain business practices and procedures governing transactions between interstate natural gas pipelines, their customers, and others doing business with the pipelines. These initial business standards, developed by the Gas Industry Standards Board, govern important business practices such as shipper supplied service nominations, allocation of available capacity, accounting and invoicing of transportation service, and capacity release. Northern Border Pipeline is in the process of implementing changes to its tariff and internal systems so it can fully comply with the initial business standards by April 1, 1997, as required by Order No. 587. 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 and pipeline field office 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 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. Northern Border Pipeline has been preliminarily advised by the attorneys retained by the Fort Peck Tribes that Northern Border Pipeline may not have valid pipeline rights on tribal lands. Northern Border Pipeline has been supplied with a letter explaining this conclusion, but Northern Border Pipeline's initial analysis of the explanation does not appear to support this conclusion. However, the Partnership is unable to predict at this time the outcome of this issue. 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 rights-of-way across those tracts of allotted lands where a sufficient number of consents from the owners had been obtained. Also, a condemnation action was filed in Federal Court concerning those remaining tracts of allotted land for which a majority of consents were not 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 of the right-of-way on the tracts in question. Item 3. Litigation In addition to the condemnation action (See "Item 2. Properties") and matters related to the FERC regulation, various legal actions which have arisen in the ordinary course of business are pending with respect to Northern Border Pipeline. The Partnership is not currently a party to any legal proceedings, of which, 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 1996. 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 paid per Common Unit:
Price Range Cash High Low Distributions 1996 First Quarter $25.875 $23.500 $0.55 Second Quarter 24.875 22.875 0.55 Third Quarter 26.125 23.875 0.55 Fourth Quarter 27.375 25.500 0.55 1995 First Quarter $24.125 $20.875 $0.55 Second Quarter 25.625 21.875 0.55 Third Quarter 25.500 24.000 0.55 Fourth Quarter 25.250 23.250 0.55
As of January 31, 1997, there were approximately 1,900 record holders of the Partnership's Common Units. There is no established public trading market for the Partnership's Subordinated Units held by the General Partners. Cash distributions of $0.55 per Unit have been paid on all Common and Subordinated Units for all quarters since inception of the Partnership. The Partnership distributes 100% of its Available Cash (defined below) within 45 days after the end of each quarter to Unitholders of record and the General Partners. During a specified period that will not end earlier than December 31, 1998 (the "Subordination Period"), distributions of Available Cash on Subordinated Units are subordinated to the rights of the holders of the Common Units to receive $0.55 per Common Unit per quarter. "Available Cash" consists generally of all of the cash receipts of the Partnership adjusted for its cash disbursements and net changes to reserves. A full definition of Available Cash and the Subordination Period is set forth in the Partnership Agreement, a form of which is filed as an Exhibit hereto. Item 6. Selected Financial Data (Unaudited) (in thousands, except per Unit and operating data) On October 1, 1993, the Partnership acquired a 70% general partner interest in Northern Border Pipeline. Prior to October 1, 1993, the Partnership had no financial statements. The following selected financial data labeled "Historical (Predecessor)" represent the income data, cash flow data, balance sheet data and operating data of Northern Border Pipeline, the Partnership's predecessor company as defined under the regulations of the Securities and Exchange Commission ("SEC").
Partnership Historical (Predecessor) Pro Forma Three Nine Year Months Months Year Ended Ended Ended Ended Year Ended December 31, December 31, December 31, September 30, December 31, 1996 1995 1994 1993 1993 1993 1992 INCOME DATA: Operating revenue $ 201,943 $ 206,497 $ 211,580 $205,241 $ 53,148 $ 152,093 $ 166,928 Operations and maintenance 28,366 26,730 28,919 27,210 7,424 18,661 22,052 Depreciation and amortization 46,979 47,081 41,959 39,539 10,489 29,050 27,287 Taxes other than income 24,390 23,886 24,438 21,393 5,582 15,811 20,788 Operating income 102,208 108,800 116,264 117,099 29,653 88,571 96,801 Interest expense 33,117 35,205 38,424 40,671 10,054 30,617 33,187 Other income (expense) 3,347 568 (1,340) (784) (1,209) 425 5,835 Minority interests in net income 22,153 22,360 23,147 22,622 5,108 -- -- Net income to partners $ 50,285 $ 51,803 $ 53,353 $ 53,022 $ 13,282 $ 58,379 $ 69,449 Net income per Unit $ 1.88 $ 1.94 $ 2.00 $ 1.98 $ .50 -- -- CASH FLOW DATA: Net cash provided by operating activities $ 137,534 $ 127,078 $ 121,088 $116,530 $ 35,184 $ 82,471 $ 86,132 Capital expenditures 18,597 8,411 2,985 1,268 528 739 135,990 BALANCE SHEET DATA (AT END OF PERIOD): Net property, plant and equipment $ 937,859 $ 957,587 $ 983,842 $ -- $1,015,567 $1,023,725 $1,049,023 Total assets 1,016,484 1,041,339 1,083,468 -- 1,115,768 1,096,099 1,129,200 Long-term debt, including current maturities 377,500 410,000 445,000 -- 470,000 470,000 492,500 Minority interests in partners' capital 158,089 166,789 173,984 -- 177,089 -- -- Partners' capital 410,586 419,117 426,130 -- 431,593 597,587 604,927 OPERATING DATA: MMCF of gas delivered 633,908 615,133 597,898 570,469 142,040 428,429 515,215 Average throughput (MMCFD) 1,764 1,720 1,663 1,592 1,581 1,596 1,418
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Year Ended December 31, 1996 Compared With the Year Ended December 31, 1995 Operating revenue decreased $4.6 million (2%) for the year ended December 31, 1996, as compared to the results for the comparable period in 1995, due primarily to equity returns on a lower rate base and lower interest expense. These lower recoveries were partially offset by higher operations and maintenance expense recoveries. 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 may collect from its shippers declines as the rate base is recovered. Operating revenue for 1996 reflect the terms of the Stipulation filed by Northern Border Pipeline for FERC approval to settle its rate case (See "Business-FERC Regulation"). Operations and maintenance expense increased $1.6 million (6%) for the year ended December 31, 1996, from the comparable period in 1995 due primarily to expenses incurred in conjunction with Northern Border Pipeline's rate case proceeding as well as higher administrative expenses. Depreciation and amortization expense remained constant for the year ended December 31, 1996, as compared to the results for the same period in 1995. Depreciation and amortization expense for 1996 is reduced approximately $7.4 million from the level authorized in Northern Border Pipeline's FERC tariff to reflect the Stipulation discussed above, which results in an average depreciation rate for transmission plant of 3.1% for the year ended December 31, 1996 and matches the rate used in 1995. In accordance with the terms of the Stipulation, the depreciation rate applied to Northern Border Pipeline's gross transmission plant is reduced to 2.7% effective June 1996 from the 3.6% rate in its FERC tariff. Interest expense decreased $2.1 million (6%) for the year ended December 31, 1996, as compared to the results for the same period in 1995 due to a decrease in the average debt outstanding. Average debt outstanding has decreased between the two periods reflecting principal payments of $32.5 million made under the Northern Border Pipeline bank loan agreement. Other income (expense) increased $2.8 million for the year ended December 31, 1996, from results for the year ended December 31, 1995, primarily due to the reversal of previously established reserves for regulatory issues (See "Business-FERC Regulation"). Year Ended December 31, 1995 Compared With the Year Ended December 31, 1994 Operating revenue decreased $5.1 million (2%) for the year ended December 31, 1995, as compared to the results for the comparable period in 1994, due primarily to equity returns on a lower rate base, lower operations and maintenance expense and lower interest expense. These lower recoveries were partially offset by higher depreciation and amortization expense recoveries. Operations and maintenance expense decreased $2.2 million (8%) for the year ended December 31, 1995, from the comparable period in 1994 due to lower administrative expenses for Northern Border Pipeline. Depreciation and amortization expense increased $5.1 million (12%) for the year ended December 31, 1995, as compared to the results for the same period in 1994. The increase is due to an increase in the depreciation rate applied to Northern Border Pipeline's gross transmission plant from 2.8% for the year ended December 31, 1994 to 3.1% in 1995 as authorized in its FERC tariff. Interest expense decreased $3.2 million (8%) for the year ended December 31, 1995, as compared to the results for the same period in 1994 due to a decrease in the average debt outstanding and a decrease in the average interest rate from 8.5% to 8.3%. Average debt outstanding decreased approximately $31 million between the two periods reflecting principal payments made under the Northern Border Pipeline bank loan agreement. Other income (expense) increased $1.9 million for the year ended December 31, 1995, from results for the year ended December 31, 1994, primarily due to a $1.5 million increase in other income and a $0.7 million increase in interest income offset by a $0.3 million increase in other expenses. The increase in other income between 1994 and 1995 primarily reflects miscellaneous plant acquisition adjustments. Liquidity and Capital Resources General Short-term liquidity needs of the Partnership will be met by internal sources. In addition, the Partnership has the ability to establish lines of credit with one or more financial institutions. Long-term capital needs can be met by the Partnership's ability to issue additional limited partner interests in the Partnership. On October 4, 1996, Northern Border Pipeline entered into a one-year $50 million revolving credit agreement with a financial institution. Borrowings under the credit agreement are expected to be used by Northern Border Pipeline to fund working capital, construction and other general business purposes. Cash Flows From Operating Activities Cash flow from operations increased $10.5 million to $137.5 million for the year ended December 31, 1996 as compared to the same period in 1995, due primarily to amounts collected subject to refund by Northern Border Pipeline as a result of its current rate case (See "Business-FERC Regulation"). Cash flow from operations increased $6.0 million to $127.1 million for the year ended December 31, 1995 as compared to the same period in 1994 due primarily to an increase in Northern Border Pipeline's depreciation and amortization expense which is collected from its shippers. Cash Flows From Investing Activities Net plant additions of $18.6 million for the year ended December 31, 1996, include $11.8 million for The Chicago Project (See "Business-Demand for Transportation Capacity"). The remaining $6.8 million of net plant additions for 1996 are primarily related to renewals and replacements of the existing facilities. For the comparable period in 1995, net plant additions were $8.4 million which included $4.5 million for The Chicago Project and $3.9 million primarily related to renewals and replacements of the existing facilities. Total capital expenditures for 1997 are estimated to be $210 million for The Chicago Project. The Chicago Project is expected to be ready for service in November 1998, subject to timely regulatory approvals, and is estimated to cost $837 million, using certain construction cost escalation assumptions. An additional $14 million of 1997 capital expenditures is planned for renewals and replacements for the existing facilities. Funds required to meet the 1997 capital expenditures are anticipated to be provided from debt borrowings, internal sources and equity contributions from minority interest holders. Cash Flows From Financing Activities Cash used in financing activities of $112.2 million for the year ended December 31, 1996, reflects distributions made to partners and minority interests of $58.8 million and $30.9 million, respectively, and $22.5 million in net principal reductions under the Northern Border Pipeline bank loan and credit agreements. For the comparable period in 1995, cash used in financing activities totaled $123.4 million and reflected distributions made to partners and minority interests of $58.8 million and $29.6 million, respectively, and $35.0 million in principal payments under the Northern Border Pipeline bank loan agreement. Information Regarding Forward Looking Statements Within the Partnership's interpretation of the Private Securities Litigation Reform Act of 1995, 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-Demand for Transportation Capacity" and elsewhere regarding Northern Border Pipeline's efforts to pursue opportunities to further increase its capacity, the discussion under "Business-FERC Regulation" regarding pending and future proceedings before FERC and related matters 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 political and regulatory developments that impact FERC and state utility commission proceedings, Northern Border Pipeline's success in sustaining its positions in such proceedings or the success of intervenors in opposing Northern Border Pipeline's positions, developments relating to the renewal of the pipeline right-of-way lease with the Fort Peck Indian Reservation and the condemnation proceedings involving allotted lands of the reservation, competitive developments by Canadian and U.S. natural gas transmission peers, political and regulatory developments in Canada and conditions of the capital markets and equity markets during the periods covered by the forward looking statements. Item 8. Financial Statements 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. PART III 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 utilizes 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. 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 55 Chief Executive Officer Jerry L. Peters 39 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: Larry L. DeRoin 55 Chairman of Partnership (Northern Plains) Policy Committee and Northern Border Management Committee George L. Mazanec 61 Member of Partnership Policy (Pan Border) Committee and Northern Border Management Committee Brian E. O'Neill 61 Member of Partnership Policy (Northwest Border) Committee and Northern Border Management Committee Members of Audit Committee: Daniel P. Whitty 65 Chairman of Audit Committee Gerald B. Smith 46 Member of Audit Committee 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. George L. Mazanec was appointed to the Partnership Policy Committee in July, 1993. Mr. Mazanec is an Advisor to the Chief Executive Officer of PanEnergy. From December, 1993 to December, 1996 he was the Vice Chairman of the Board of Directors of PanEnergy and had been a director since December, 1992. He was a director of Texas Eastern Products Pipeline Company, the general partner of TEPPCO Partners, L.P. From March, 1991 to December, 1993, he was Executive Vice President of PanEnergy. From 1989 to 1991, he was Group Vice President of PanEnergy and from 1987 to 1989, he was Senior Vice President of Texas Eastern Corporation and Texas Eastern Transmission Company. He is a director of National Fuel Gas Company and Northern Trust Bank of Texas. He has served on the Northern Border Management Committee since 1991. Brian E. O'Neill was appointed to the Partnership Policy Committee in July, 1993. Mr. O'Neill is President and Chief Executive Officer of Northwest Pipeline Corporation, Williams Western Pipeline Company, Williams Natural Gas Company, Transco and Texas Gas Transmission Corporation. 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 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. 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 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 Year Salary Bonus (1) Awards (2) SARs (#) (3) (4) Larry L. DeRoin 1996 $239,667 $144,000 $25,665 $ - 18,220 $ - $ 1,102 Chief Executive 1995 $235,000 $128,500 $19,208 $ - 14,550 $150,000 $ 793 Officer 1994 $235,000 $112,000 $29,039 $7,035 30,445 $150,000 $31,572 Jerry L. Peters 1996 $114,525 $ 20,000 $ - $ - 5,045 $ - $ 767 Chief Financial and 1995 $104,900 $ 15,000 $ - $ - 2,655 $ - $ 552 Accounting Officer 1994 $ 92,270 $ 12,500 $ - $ - 5,475 $ - $18,609 (1) No Named Officer had "Perquisites and Other Personal Benefits" with a value greater than the lesser of $50,000 or 10% of reported salary and bonus. Enron maintains three deferral plans for key employees under which payment of base salary, annual bonus and long-term incentive awards may be deferred to a later specified date. Under the 1985 Deferral Plan, interest is credited on amounts deferred based on 150% of Moody's seasoned corporate bond yield index with a minimum rate of 12%, which for 1994 was the minimum rate of 12.0%, for 1995 was 12.39%, and for 1996 was the minimum rate of 12.0%. Interest in excess of 120% of the December, 1995 long- term Applicable Federal Rate ("AFR") (7.65%) has been reported as Other Annual Compensation for 1996, interest in excess of 120% of the December, 1994 long-term AFR (9.91%) has been reported as Other Annual Compensation for 1995, and interest in excess of 120% of the December, 1993 long-term AFR (7.29%) has been reported as Other Annual Compensation for 1994. No interest has been reported as Other Annual Compensation under the 1992 Deferral Plan, which credits interest at Enron's mid-term borrowing rate, since the crediting rates for 1994, 1995 and 1996 of 6.0%, 8.5%, and 6.5% respectively, did not exceed 120% of the AFR. Under the 1994 Deferral Plan interest was credited on amounts deferred at a fixed rate of 9% for 1994 and 1995. Interest in excess of 120% of the December, 1993 long-term AFR (7.29%) has been reported as Other Annual Compensation for 1994. Beginning January 1, 1996, the 1994 Deferral Plan credits interest based on fund elections chosen by participants. Since earnings on deferred compensation invested in third-party investment vehicles, comparable to mutual funds, need not be reported, no interest has been reported as Other Annual Compensation under the 1994 Deferral Plan during 1996. Other Annual Compensation also includes cash perquisite allowances. (2) Restricted stock awarded to Mr. DeRoin on February 7, 1994 became 50% vested on August 7, 1994, and 50% vested on February 7, 1995. Dividend equivalents accrued from date of grant and were paid upon vesting. The Named Officers had no unreleased restricted stock holdings as of December 31, 1996. (3) The amounts shown for 1994 and 1995, for Mr. DeRoin represent payouts made under Enron's Performance Unit Plan. (4) The amounts shown include the value, as of year-end 1994, 1995, and 1996 of Enron Common Stock allocated during those years to employees' savings and special subaccounts under Enron's Employee Stock Ownership Plan ("ESOP"). Included in 1994 is a special allocation made in February, 1994 to employees' savings subaccounts under the ESOP in lieu of a merit increase in 1994 and a special allocation made in December, 1994 to a special allocation subaccount. Included in 1995 and 1996, is a special allocation made in December of 1995 and 1996, to a special allocation subaccount under the ESOP.
Stock Option Grants During 1996 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 1996.
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 (5) Name (#) (1) Fiscal Year ($/Sh) Date 0% (4) 5% 10% Larry L. DeRoin 6,590 (2) 0.09% $36.7500 01/23/01 $- $ 66,911 $ 147,855 11,630 (3) 0.16% $43.1250 12/31/01 $- $ 138,567 $ 306,197 Jerry L. Peters 3,545 (2) 0.05% $36.7500 01/23/01 $- $ 35,994 $ 79,536 1,500 (3) 0.02% $43.1250 12/31/01 $- $ 17,872 $ 39,492 All Employee and Director Optionees 7,371,026 (6) 100% $39.7113 (7) N/A $- $ 184,085,478 (8) $ 466,509,287 (8) All Stockholders N/A N/A N/A N/A $- $6,160,902,605 (8) $15,612,955,030 (8) Optionee Gain as % of All Stockholders Gain N/A N/A N/A N/A N/A 2.99% 2.99% 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. Stock options awarded on January 23, 1996 became 100% vested on the date of grant. 3. Stock options awarded on December 31, 1996 became 25% vested on the date of grant with an additional 25% vested on the anniversary of the date of grant until December 31, 1999. 4. 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. 5. The dollar amounts under these columns represent the potential realizable value of each grant of options assuming that the market price of Enron 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 Enron Common Stock. 6. Includes shares issued on December 31, 1996 under the All- Employee Stock Option Program to employees hired during 1996. 7. Weighted average exercise price of all Enron stock options granted to employees in 1996. 8. 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 term, the weighted average exercise price for All Employee and Director Optionees ($39.7113) and the number of shares of Common Stock issued and outstanding on December 31, 1996 excluding shares held by the Enron Flexible Equity Trust.
Aggregated Stock Option/SAR Exercises During 1996 and Stock Option/SAR Values as of December 31, 1996 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, 1996 SARs at December 31, 1996 Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable Larry L. DeRoin - $ - 111,925 31,290 $2,222,215 $248,562 Jerry L. Peters 600 $21,113 13,362 3,413 $ 185,012 $ 29,286
Long-Term Incentive Plan - Awards in 1996 The following table provides information concerning awards of performance units under Enron's Performance Unit Plan during 1996 for the 1996 - 1999 performance period. Mr. Peters is not a participant in this plan. 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 stockholder return is compared to that of the 11 peer companies included in the Peer Group. At that time, the units are assigned a value ranging from $0 to $2.00 based on the rank of Enron's stockholder return within the 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 stockholder 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.
Performance or Estimated Future Payouts Number of Shares, Other Period Until Under Non-Stock Price Based Units or Other Maturation or Plans Name Rights (#) Payout Threshold Target Maximum Larry L. DeRoin 75,000 4 years $- $75,000 $150,000
Retirement and Supplemental Benefit Plans Enron maintains the Enron Corp. Retirement Plan (the "Retirement 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 Retirement 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 Retirement Plan changing the Plan's name to the Enron Corp. Cash Balance Plan (the "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 10-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. 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 Plans. The following table sets forth the estimated annual benefits payable under normal retirement at age 65, assuming current remuneration levels without any salary projection 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 Name Service at Age 65 By Plans Retirement Larry L. DeRoin 29.3 39.0 $242,000 $135,525 Jerry L. Peters 11.9 37.8 $114,900 $ 67,922 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 January 31, 1997 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 Subordinated Units Number Percent Number Percent of Units1/ of Class of Units of Class Larry L. DeRoin 10,000 * Jerry L. Peters 1,300 * George L. Mazanec 2,500 * Brian E. O'Neill - Daniel P. Whitty - Gerald B. Smith - The Williams Companies, Inc.2/ 1,123,500 17.5 One Williams Center Tulsa, OK 74101-3288 Enron Corp.3/ 3,210,000 50.0 1400 Smith Street Houston, TX 77002 PanEnergy Corp.4/ 2,086,500 32.5 5400 Westheimer Court Houston, TX 77056-5310 * Less than 1%. 1/ All units involve sole voting and investment power. 2/ Indirect ownership through its subsidiary, Northwest Border. 3/ Indirect ownership through its subsidiary, Northern Plains. 4/ Indirect ownership through its subsidiary, Pan Border.
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 an affiliate 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. In addition, as of March 1, 1997, (i) Enron Capital & Trade Resources Corp., an affiliate of Enron, is a transportation customer of Northern Border Pipeline, which is obligated to pay 0.2% 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 17.2% of Northern Border Pipeline's annual cost of service; (iii) PanEnergy Trading and Market Services LLC, a joint venture affiliate of PanEnergy is the agent for the transportation contract with Mobil Natural Gas Inc. which is obligated to pay 1.8% of Northern Border Pipeline's annual cost of service; (iv) Panhandle Eastern Pipe Line Company, an affiliate of PanEnergy, provides a financial guaranty for a portion (150 MMCFD) of the transportation capacity held by PAGUS, which in turn represents 10.7% of Northern Border Pipeline's annual cost of service; (v) TransCanada Gas Services Inc. ("TransCanada Gas Services"), an affiliate of TransCanada, is a transportation customer of Northern Border Pipeline which is obligated to pay 7.2% 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 1.2% of Northern Border Pipeline's annual cost of service. In addition, PanEnergy Trading and Market Services LLC and Cibola Energy Services Corporation, an affiliate of TransCanada are transportation customers under temporary releases from firm transportation shippers. The Partnership Policy Committee, whose members are appointed by the three General Partners, establishes the business policies of the Partnership, and each General Partner has a right to appoint a representative to the Northern Border Management Committee, each of which will vote a portion of the Partnership's voting interest on the Northern Border Management Committee. Certain conflicts of interest could arise as a result of the relationships among the General Partners, their respective parents and other affiliates, TransCanada, its affiliates, the Unitholders and Northern Border Pipeline. The directors and officers of Enron, PanEnergy, Williams and TransCanada have fiduciary duties to manage their respective companies, including their investments in their respective affiliates and subsidiaries, in a manner beneficial to their respective shareholders. In addition, (i) the members of the Partnership Policy Committee have a fiduciary duty to manage the Partnership in a manner beneficial to the Unitholders, (ii) the Partnership's representatives on the Northern Border Management Committee have a fiduciary duty to manage Northern Border Pipeline in a manner beneficial to the Partnership, and (iii) the Partnership has a fiduciary duty to the subsidiaries of TransCanada, as partners in Northern Border Pipeline, which duty is also owed by TransCanada to the Partnership. The Partnership Agreement contains provisions that allow the General Partners and the Partnership Policy Committee to take into account the interests of parties in addition to the Partnership in resolving conflicts of interest, thereby limiting their duties to the Partnership and the Unitholders, as well as provisions that may restrict the remedies available to Unitholders for actions taken that might, without such limitations, constitute breaches of duty. The 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 such General Partner and its affiliates (or the member of the Partnership Policy Committee designated by it), on the one hand, and the Partnership or the Unitholders, on the other. In addition, with respect to the fiduciary duties owed by the Partnership and the subsidiaries of TransCanada to each other as partners in Northern Border Pipeline, (i) the fiduciary duty owed by the Partnership to such subsidiaries of TransCanada may restrict the ability of the Partnership Policy Committee to cause the Partnership to take certain actions that might be in the best interests of the Partnership, but in conflict with the fiduciary duty owed by the Partnership to such subsidiaries of TransCanada and (ii) the duty of the directors and officers of each of the parent companies of such subsidiaries of TransCanada to its shareholders may conflict with the duty owed by such subsidiaries of TransCanada to the Partnership as a partner in Northern Border Pipeline. PART IV Item 14. Exhibits, Financial Statements, and Reports on Form 8-K (a)(1) and (2) Financial Statements 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 Amended and Restated Loan Agreement among Northern Border Pipeline Company, the Banks (as defined therein), Canadian Imperial Bank of Commerce, New York Agency and Bank of America National Trust & Savings Association, dated July 15, 1992 (Exhibit 10.5 to Form S-1). *10.5.1Letter Amendment to Amended and Restated Loan Agreement effective as of September 21, 1993 (Exhibit 10.5.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")). *10.5.2Letter Amendment to Amended and Restated Loan Agreement effective as of September 9, 1994 (Exhibit 10.5.2 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1994 ("1994 10-K")). *10.5.3Letter Amendment to Amended and Restated Loan Agreement dated May 18, 1995 (Exhibit 10.5.3 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K)). *10.6 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.6.1Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to 1995 10-K). *10.7 Consent and Agreement of the Partners among Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border PipeLine Ltd. and Canadian Imperial Bank of Commerce, New York Agency, dated February 28, 1990 (Exhibit 10.7 to Form S-1). *10.8 Consent and Agreement of the Partners among TransCanada Border PipeLine Ltd., TransCan Northern Ltd. and Canadian Imperial Bank of Commerce, New York Agency, dated April 19, 1991 (Exhibit 10.8 to Form S-1). *10.9 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *10.10 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). *10.10.1Amended 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 1993 10-K). *10.10.2Amended 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 1994 10-K). *10.10.3Amended 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). *10.11.1Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.11.2Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K). *10.12 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Northern Natural Gas Company, dated August 25, 1988 (Exhibit 10.12 to Form S- 1). *10.12.1Amendment to Northern Border Pipeline Company U.S. Shippers Service Agreement effective October 1, 1993. (Exhibit 10.12.1 to 1993 10-K). *10.12.2Amendment to Northern Border Pipeline Company U.S. Shippers Service Agreement terminating the Agreement as of November 1, 1994 (Exhibit 10.12.2 to 1994 10-K). *10.13 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Western Gas Marketing Limited, as agent for TransCanada PipeLines Limited, dated December 15, 1980 (Exhibit 10.13 to Form S-1). *10.13.1Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.14 Form of Credit Agreement between Northern Border Partners, L.P., as borrower, and Northern Plains Natural Gas Company, Northwest Border Pipeline Company and Pan Border Gas Company, as lenders (Exhibit 10.14 to Form S-1). *10.15 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.16 Form of Conveyance, Contribution and Assumption Agreement among Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, Northern Border Partners, L.P., and Northern Border Intermediate Limited Partnership (Exhibit 10.16 to Form S-1). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Transcontinental Gas Pipe Line Corporation, dated July 14, 1983, with Amended Exhibit A effective February 11, 1994 (Exhibit 10.17 to 1995 10-K). 10.18 Northern Border Pipeline Company U.S. Shippers Service Agreement dated August 30, 1991 between Northern Border Pipeline Company and Mobil Natural Gas, Inc., with Amended Exhibit A effective April 29, 1994 and designation of agent effective August 1, 1996. 21. The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership and Northern Border Pipeline Company. __________ *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 1996. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 28th day of March, 1997. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) By LARRY L. DEROIN Larry L. DeRoin Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. Signature Title Date LARRY L. DEROIN Chief Executive Officer and March 28, 1997 Larry L. DeRoin Chairman of the Partnership Policy Committee (Principal Executive Officer) GEORGE L. MAZANEC Member of Partnership Policy March 28, 1997 George L. Mazanec Committee BRIAN E. O'NEILL Member of Partnership Policy March 28, 1997 Brian E. O'Neill Committee JERRY L. PETERS Chief Financial and March 28, 1997 Jerry L. Peters Accounting Officer NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS Page No. Report of Independent Public Accountants F-2 Consolidated Balance Sheet - December 31, 1996 and 1995 F-3 Consolidated Statement of Income - Years Ended F-4 December 31, 1996, 1995 and 1994 Consolidated Statement of Cash Flows - Years Ended F-5 December 31, 1996, 1995 and 1994 Consolidated Statement of Changes in Partners' Capital - F-6 Years Ended December 31, 1996, 1995 and 1994 Notes to Consolidated Financial Statements F-7 through F-16 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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Omaha, Nebraska, January 22, 1997 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (In Thousands)
December 31, ASSETS 1996 1995 CURRENT ASSETS Cash and cash equivalents $ 41,390 $ 39,418 Accounts receivable 16,907 18,928 Related party receivables 2,364 2,883 Materials and supplies, at cost 4,128 4,437 Total current assets 64,789 65,666 NATURAL GAS TRANSMISSION PLANT Property, plant and equipment 1,513,116 1,499,893 Less: Accumulated provision for depreciation and amortization 575,257 542,306 Net property, plant and equipment 937,859 957,587 OTHER ASSETS 13,836 18,086 Total assets $1,016,484 $1,041,339 LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Current maturities of long-term debt $ 17,500 $ 15,000 Note payable 10,000 -- Accounts payable 3,463 1,193 Accrued taxes other than income 20,968 19,903 Accrued interest 10,353 10,516 Over recovered cost of service 4,236 2,508 Accumulated provision for billings subject to refund 12,227 -- Total current liabilities 78,747 49,120 LONG-TERM DEBT, net of current maturities 360,000 395,000 MINORITY INTERESTS IN PARTNERS' CAPITAL 158,089 166,789 RESERVES AND DEFERRED CREDITS 9,062 11,313 COMMITMENTS AND CONTINGENCIES (NOTE 6) PARTNERS' CAPITAL General Partners 8,212 8,382 Common Units 303,777 310,089 Subordinated Units 98,597 100,646 Total partners' capital 410,586 419,117 Total liabilities and partners' capital $1,016,484 $1,041,339 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, 1996 1995 1994 OPERATING REVENUE $201,943 $206,497 $211,580 OPERATING EXPENSES Operations and maintenance 28,366 26,730 28,919 Depreciation and amortization 46,979 47,081 41,959 Taxes other than income 24,390 23,886 24,438 Operating expenses 99,735 97,697 95,316 OPERATING INCOME 102,208 108,800 116,264 INTEREST EXPENSE 33,117 35,205 38,424 OTHER INCOME (EXPENSE) Other income (expense), net 2,951 478 (1,382) Allowance for equity funds used during construction 396 90 42 Other income (expense) 3,347 568 (1,340) MINORITY INTERESTS IN NET INCOME 22,153 22,360 23,147 NET INCOME TO PARTNERS $ 50,285 $ 51,803 $ 53,353 NET INCOME PER UNIT $ 1.88 $ 1.94 $ 2.00 NUMBER OF UNITS USED IN COMPUTATION 26,200 26,200 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, 1996 1995 1994 CASH FLOWS FROM OPERATING ACTIVITIES: Net income to partners $ 50,285 $ 51,803 $ 53,353 Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 47,010 47,083 41,959 Minority interests in net income 22,153 22,360 23,147 Provision for billings subject to refund 12,227 -- -- Changes in other current assets and liabilities 7,749 (975) (925) Other (1,890) 6,807 3,554 Total adjustments 87,249 75,275 67,735 Net cash provided by operating activities 137,534 127,078 121,088 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property, plant, and equipment, net (18,597) (8,411) (2,985) Other (4,796) -- -- Net cash used in investing activities (23,393) (8,411) (2,985) CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions Common units (43,516) (43,516) (43,516) Subordinated units (14,124) (14,124) (14,124) General partners (1,176) (1,176) (1,176) Minority Interests (30,853) (29,555) (26,252) Retirement of long-term debt (32,500) (35,000) (25,000) Borrowings on note payable 10,000 -- -- Net cash used in financing activities (112,169) (123,371) (110,068) NET CHANGE IN CASH AND CASH EQUIVALENTS 1,972 (4,704) 8,035 Cash and cash equivalents-beginning of period 39,418 44,122 36,087 Cash and cash equivalents-end of period $ 41,390 $ 39,418 $ 44,122 The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (In Thousands)
General Common Subordinated Partners' Partners Units Units Capital Partners' Capital at December 31, 1993 $ 8,632 $319,320 $103,641 $431,593 Net income to partners 1,066 39,474 12,813 53,353 Distributions paid (1,176) (43,516) (14,124) (58,816) Partners' Capital at December 31, 1994 8,522 315,278 102,330 426,130 Net income to partners 1,036 38,327 12,440 51,803 Distributions paid (1,176) (43,516) (14,124) (58,816) 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 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., through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, collectively referred to herein as the Partnership, a Delaware limited 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%) (collectively TransCanada), both of which are wholly-owned subsidiaries of TransCanada PipeLines Limited. 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 PanEnergy Corp. (PanEnergy), 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. The General Partners also own Subordinated Units representing, in the aggregate, an effective 24% limited partner interest in the Partnership. 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. The pipeline system owned by Northern Border Pipeline is a 969-mile natural gas transmission line extending from the United States-Canadian border near Port of Morgan, Montana, to a terminus near Harper, Iowa, where it interconnects with the system of Natural Gas Pipeline Company of America. Northern Border Pipeline is managed by a Management Committee that includes three representatives from the Partnership (one representative from each of the General Partners of the Partnership) and one representative from TransCanada. 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. 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 amount and timing of such distributions are determined by the Northern Border Pipeline Management Committee. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline require the unanimous approval of the Northern Border Pipeline Management Committee. 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. 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 TransCanada 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) 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 $306.7 million and $322.7 million as of December 31, 1996 and 1995, respectively, and are primarily related to accelerated depreciation and other plant-related differences. (D) Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments. (E) Property, Plant and Equipment and Related Depreciation and Amortization Property, plant and equipment is stated at original cost. Balances at December 31, 1996 and 1995 include construction work in progress of approximately $19.6 million and $5.1 million, respectively. Approximately $16.8 million and $4.6 million of the construction work in progress balances at December 31, 1996 and 1995, respectively, represent project-to- date expenditures on Northern Border Pipeline's proposed expansion and extension of its pipeline from its current terminus near Harper, Iowa to a point near Manhattan, Illinois (The Chicago Project) (see Note 6). Expenditures for maintenance and repairs are charged to operations in the period incurred. The provision for depreciation and amortization of the transmission line is an integral part of Northern Border Pipeline's FERC tariff and its levelized cost of service. The effective depreciation rate applied to Northern Border Pipeline's gross transmission plant in 1996, 1995 and 1994 was 3.1%, 3.1% and 2.8%, respectively (see Note 6). 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) 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 cost of service determined for that period in accordance with the FERC tariff (incurred cost of service) to the estimated billing is accumulated, including carrying charges thereon, and is either billed to or credited back to the shippers. Revenues reflect incurred cost of service. An amount equal to differences between billing estimates and the incurred cost of service, including carrying charges, is reflected in current assets or current liabilities. (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. Recognition of this allowance is appropriate because it constitutes an actual cost of construction. 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. Northern Border Pipeline does not use these agreements for trading purposes. The cost or benefit of the interest rate swap agreements is recognized currently as a component of interest expense. 3. 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 on the volumes actually transported. Northern Border Pipeline has firm service agreements for various terms extending as long as October 2012. Based on existing contracts and capacity, Northern Border Pipeline has contracts for its entire firm capacity through October 2001. 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 obligated for approximately 49.0% of the cost of service through its firm service agreements which expire in October 2001. Operating revenues from the PAGUS firm service agreements and interruptible service contracts for the years ended December 31, 1996, 1995 and 1994 were $101.7 million, $99.9 million and $103.1 million, respectively. Northern Natural Gas Company, a wholly-owned subsidiary of Enron, and Panhandle Eastern Pipe Line Company, a wholly-owned subsidiary of PanEnergy, have executed financial guarantees representing 17.2% and 10.7%, respectively, of the total cost of service related to the contracted capacity of PAGUS. The remaining 21.1% of the 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. Shippers affiliated with the partners of Northern Border Pipeline have firm service agreements representing approximately 10.4% of the cost of service through October 2001. These firm service agreements extend for various terms which range from October 2005 to December 2008. Operating revenues from the affiliated firm service agreements and interruptible service contracts for the years ended December 31, 1996, 1995 and 1994 were $22.7 million, $18.8 million and $25.2 million, respectively. 4. CREDIT FACILITIES, SHORT-TERM BORROWINGS AND LONG-TERM DEBT In October 1996, Northern Border Pipeline entered into a one-year $50 million revolving credit agreement with a financial institution. The 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. The interest rate options available under the credit agreement are based upon the London Interbank Offered Rate (LIBOR), certificate of deposit rates or other short-term interest rates. Compensating balances are not required, but Northern Border Pipeline is required to pay a commitment fee on unborrowed funds. In late December 1996, $10 million was borrowed under the credit agreement at an interest rate of 5.94% and is shown as a note payable in the accompanying consolidated balance sheet. Northern Border Pipeline has senior notes in the aggregate principal amount of $250 million at both December 31, 1996 and 1995, pursuant to note purchase agreements, which combined have an average fixed interest rate of 8.43%. Annual principal payments on the senior notes begin August 2000, with the final principal payment due August 2003. As of December 31, 1996 and 1995, Northern Border Pipeline had outstanding $127.5 million and $160 million, respectively, under an amended bank loan agreement. The amended bank loan agreement provides for fixed, semi-annual repayments and has a final maturity of December 31, 1999. The amended bank loan 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. The interest rate options available to Northern Border Pipeline under the amended bank loan agreement were based upon LIBOR, CD Advances rate or U.S. prime rate. At December 31, 1996 and 1995, Northern Border Pipeline had outstanding interest rate swap agreements with notional amounts of $90 million and $115 million, respectively. Under the agreements, which have a remaining average maturity of approximately three years as of December 31, 1996, Northern Border Pipeline makes payments to counterparties at fixed rates and in return receives payments at variable rates based on LIBOR. At both December 31, 1996 and 1995, Northern Border Pipeline was in a payable position relative to its counterparties. The average effective interest rate of Northern Border Pipeline's amended bank loan agreement, taking into consideration the interest rate swap agreements, was 7.32% and 7.39% at December 31, 1996 and 1995, respectively. The average interest rates and interest paid, net of amounts capitalized, on the total outstanding debt, including the interest rate swap agreements, were as follows:
1996 1995 1994 Average interest rate during the year ended December 31 8.37% 8.34% 8.50% Average interest rate at December 31 8.21% 8.38% 8.24% Interest paid, net of amounts capitalized, during the year ended December 31 (in millions of dollars) $31.9 $34.3 $37.8
Aggregate repayments of long-term debt required for the next five years are as follows: $17.5 million, $50 million, $60 million, $66 million and $41 million for 1997, 1998, 1999, 2000 and 2001, respectively. The credit agreement, senior notes and amended bank loan agreement 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, 1996 and 1995, respectively, $27 million and $29 million of partners' capital of Northern Border Pipeline could be distributed. The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the senior notes was approximately $271 million and $282 million at December 31, 1996 and 1995, respectively. At December 31, 1996 and 1995, the estimated fair value which would be payable to terminate the interest rate swap agreements, taking into account current interest rates, was approximately $4 million and $7 million, respectively. Northern Border Pipeline presently intends to maintain the current schedule of maturities for the senior notes and the interest rate swap agreements which will result in no gains or losses on their respective repayment. The carrying value of the credit agreement and the amended bank loan agreement approximate the fair value since the interest rates are periodically adjusted to current market conditions. 5. PARTNERS' CAPITAL Partners' capital consists of 19,780,000 Common Units representing an effective 74% limited partner interest in the Partnership; 6,420,000 Subordinated Units representing an effective 24% limited partner interest in the Partnership owned by the General Partners; and a 2% general partner interest. The Partnership Policy Committee may cause the Partnership to issue additional Common Units or other partner interests. However, the Partnership may not issue more than an additional 17,200,000 Common Units or equivalent other partner interests while the Subordinated Units have not been converted or are still outstanding without the approval of the holders of at least a majority of the outstanding Common Units (excluding Common Units held by the General Partners and their affiliates). Subordinated Units may not be converted to Common Units until after December 31, 1998 and after certain financial tests have been met. 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 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 to the rights of the holders of the Common Units to receive the minimum quarterly distribution. 6. COMMITMENTS AND CONTINGENCIES Regulatory Proceedings In November 1995, Northern Border Pipeline filed a rate case in compliance with its FERC tariff for the determination of its allowed equity rate of return. In December 1995, the FERC issued an order that permitted Northern Border Pipeline to begin collecting the requested increase in the equity rate of return effective June 1, 1996, subject to refund. Northern Border Pipeline filed for FERC approval of a Stipulation and Agreement (Stipulation) on October 15, 1996, to settle its rate case. On November 19, 1996, the Stipulation was certified by an Administrative Law Judge (ALJ) to the FERC for review and approval. In accordance with the terms of the Stipulation, Northern Border Pipeline's allowed equity rate of return would be reduced from a requested 14.25% to 12.75% for the period June 1, 1996 to October 1, 1996 and to 12% thereafter. Additionally, the Stipulation would reduce the 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, resulting in an average effective depreciation rate of 3.1% for the year ended December 31, 1996. Beginning January 1, 1997, the depreciation rate would be reduced to 2.5%. Northern Border Pipeline has reduced its operating revenue by approximately $12.2 million for the year ended December 31, 1996, which includes $7.4 million attributable to the reduction in depreciation and amortization expense for 1996, to reflect the terms of the Stipulation. Northern Border Pipeline must receive FERC approval of the Stipulation before it can implement all of the filed for terms and any associated refunds. The Partnership is unable to predict if or when the Stipulation will be approved as filed and thus actual results could differ from amounts recorded. In August 1996, the FERC issued an order which contained a preliminary determination favorable to Northern Border Pipeline's October 1995 amended application with the FERC for The Chicago Project. The preliminary determination found that The Chicago Project is required by the public convenience and necessity and authorizes the project facility costs to be included with existing facility costs in the determination of rates. The preliminary determination contemplates issuance of a final order by the FERC, subject to completion of the environmental review. In September 1996, Northern Border Pipeline filed an amendment to its October 1995 application to reflect limited facility modifications which among other things, reduced environmental impacts and project costs. In December 1996, the FERC issued a draft Environmental Impact Statement (EIS) which concluded The Chicago Project would have a limited adverse environmental impact and would be environmentally acceptable after adoption of certain recommended mitigation measures. Northern Border Pipeline's September 1996 application with the FERC for The Chicago Project facilities proposes construction and operation of 243 miles of pipeline, 147 miles of pipeline loop and a total of 228,500 compressor horsepower at eight compressor stations. The application also requests approval to remove from service 100,000 compressor horsepower at five existing compressor stations to be replaced with 175,000 compressor horsepower. The project is expected to cost, using certain construction cost escalation assumptions, approximately $837 million and, subject to timely regulatory approvals, be ready for service in November 1998. A final EIS and FERC order approving construction and operation of The Chicago Project is anticipated in 1997. In May 1996, the FERC granted rehearing of its May 1994 order on Northern Border Pipeline's methodology for recording in its books and reflecting in its rates amounts related to alternative minimum tax (AMT). The FERC Audit Staff (Staff), in December 1991 after an examination of Northern Border Pipeline's records for the period January 1, 1987 through December 31, 1989, took exception to Northern Border Pipeline's established method of accounting for AMT for ratemaking purposes. Northern Border Pipeline did not agree with the exception noted by the Staff and proceeded with a hearing before an ALJ who concluded Northern Border Pipeline had properly accounted for AMT. Ultimately, in the May 1996 order, the FERC accepted the ALJ's conclusions and vacated its May 1994 order which had held that the AMT component of Northern Border Pipeline's rate base should reflect the particular tax circumstances of each Northern Border Pipeline partner. There were no accounting adjustments or rate refunds required in resolution of this issue. In May 1996, the Staff issued its audit report on its examination of Northern Border Pipeline's records for the three year period subsequent to January 1, 1990. The audit report required Northern Border Pipeline to record certain adjustments to its accounts including the reclassification of $3.9 million of costs from utility plant in service to a regulatory asset. In accordance with Northern Border Pipeline's FERC tariff, the regulatory asset is includable in rate base, however Northern Border Pipeline must file with the FERC for the future recovery of this asset through amortization in cost of service. The General Partners indemnified the Partnership for any negative impact on distributions the Partnership received from Northern Border Pipeline as a result of this audit attributable to periods prior to October 1, 1993. The adjustments made and the indemnification received as a result of the audit report did not materially affect the consolidated financial position or results of operations. Environmental Matters The Partnership is not aware of any material contingent liabilities of Northern Border Pipeline with respect to compliance with applicable environmental laws and regulations. Other Various legal actions which have arisen in the ordinary course of business are pending. The Partnership believes that the resolution of these issues, including the FERC proceedings discussed above, will not have a material adverse impact on the Partnership's results of operations or financial position. 7. CAPITAL EXPENDITURE PROGRAM Total capital expenditures for 1997 are estimated to be $210 million for The Chicago Project and $14 million for renewals and replacements for the existing facilities. Funds required to meet the 1997 capital expenditures are anticipated to be provided from debt borrowings, internal sources and equity contributions from minority interest holders. 8. 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 number of outstanding Common Units of 19,780,000 and outstanding Subordinated Units of 6,420,000. 9. QUARTERLY FINANCIAL DATA (Unaudited)
(In thousands, except Operating Operating Net Income Net Income per unit amounts) Revenue Income to Partners per Unit 1996 First Quarter $52,953 $26,325 $12,847 $0.48 Second Quarter 52,918 25,943 12,737 0.48 Third Quarter 52,863 25,991 12,942 0.48 Fourth Quarter 43,209 23,949 11,759 0.44 1995 First Quarter $52,188 $27,736 $12,960 $0.48 Second Quarter 52,587 27,608 12,969 0.49 Third Quarter 51,886 27,301 12,786 0.48 Fourth Quarter 49,836 26,155 13,088 0.49
10. SUBSEQUENT EVENTS On January 16, 1997, the Partnership declared a cash distribution of $0.55 per Unit and a cash distribution to the General Partners at a rate equivalent to their combined 2% General Partner interest for the period October 1, 1996 through December 31, 1996. The distribution is payable February 14, 1997, to the General Partners and to the Unitholders of record at January 31, 1997. EX-10 2 MATERIAL CONTRACTS EXHIBIT 10.18 T1018F NORTHERN BORDER PIPELINE COMPANY U. S. SHIPPERS SERVICE AGREEMENT This Agreement ("the Service Agreement") is made and entered into at Omaha, Nebraska as of August 30, 1991, by and between NORTHERN BORDER PIPELINE COMPANY, hereinafter referred to as "Company" and MOBIL OIL CANADA, a partnership, hereinafter referred to as "Shipper". WHEREAS, Company's investors and lenders rely on Certificates of Public Convenience and Necessity granted by the Federal Energy Regulatory Commission "FERC" and on the Tariff for the return of and the return on all funds invested in or loaned to the Company; and WHEREAS, the transportation of natural gas shall be effectuated pursuant to Part 157 or Part 284 of the Federal Energy Regulatory Commission's Regulations; and WHEREAS, Company recognizes that it will be a condition to the initial effectiveness of this Service Agreement that, notwithstanding any other provision of the Tariff or this Service Agreement, the FERC shall have issued a nonappealable certificate with terms and conditions which achieve substantially the results requested by the Company, and such FERC certificate having been approved by Shipper (such approval not to be unreasonably withheld) and accepted by the Company. NOW THEREFORE, in consideration of their respective covenants and agreements hereinafter set out, the parties hereto covenant and agree as follows: Article 1 - Basic Receipts Shipper shall on each day beginning with Shipper's Billing Commencement Date, as defined in Section 1 of the General Terms and Conditions of Company's FERC Gas Tariff and Article 7 herein, be entitled to tender and, following tender, deliver to Company, at each of Shipper's Points of Receipt, a quantity of gas not in excess of the Daily Receipt Quantity for such Point of Receipt for such day, as defined in such Section 1, and Company shall, on such day, as defined in such Section 1, and Company shall, on such day, take receipt of the quantity of gas so tendered and delivered by Shipper at such Point of Receipt. Article 2 - Excess Receipts If Shipper shall desire to tender to Company on any day beginning with Shipper's Billing Commencement Date, at any of Shipper's Points of Receipt, a quantity of gas in excess of Shipper's Daily Receipt Quantity for such Point of Receipt for such day, it shall notify Company of such desire. If Company in its sole judgment, determines that it has available the necessary capacity to receive and transport all or any part of such excess quantity and make deliveries in respect thereof, and that the performance of Company's obligations to other Shippers under their Service Agreements will not be adversely affected thereby, Company may elect to receive from Shipper said excess quantity or part thereof, and shall so notify Shipper. Scheduling of Excess Receipts will be in accordance with Subsection 5.3 of Rate Schedule T-1, Section 5 of Rate Schedule IT-1 and Subsection 5.1 in Rate Schedule OT-1. If more than one of the Shippers subject to Rate Schedule T-1 shall notify Company of a desire to tender gas to Company pursuant to Article 2 of their respective Service Agreements on any day, Company, if it elects to receive less than all of such gas, shall, except as otherwise required by Subsection 5.3 of Rate Schedule T-1 and Subsection 13.73 of the General Terms and Conditions, allocate among such Shippers the aggregate quantity it so elects to receive in proportion to their respective Total Maximum Receipt Quantities or in such other equitable manner as Company's operating conditions and the availability of its facilities may reasonably require. Receipt of gas under this Article 2 which Company has previously elected to receive from Shipper may be curtailed partially or entirely at any time or from time to time by Company at will, in which event Company shall so notify Shipper of its decision. Article 3 - Deliveries Company shall deliver gas to Shipper at the Point(s) of Delivery and under the conditions specified in Exhibit A hereto and in accordance with Section l3 of the General Terms and Conditions. Article 4 - Payments Shipper shall make payments to Company in accordance with Rate Schedules T-1 and OT-1 and the other applicable terms and provisions of this Service Agreement. Article 5 - Change in Tariff Provisions Upon notice to Shipper, Company shall have the right to file with the Federal Energy Regulatory Commission any changes in the terms of any of its Rate Schedules, General Terms and Conditions or Form of Service Agreement as Company may deem necessary, and to make such changes effective at such times as Company desires and is possible under applicable law. Shipper may protest any filed changes before the Federal Energy Regulatory Commission and exercise any other rights it may have with respect thereto. Article 6 - Cancellation of Prior Agreements When this Service Agreement becomes effective, it shall supersede, cancel and terminate the following Agreements: Precedent Agreement dated July 16, 1990. Article 7 - Term This Service Agreement shall become effective upon its execution and shall under all circumstances continue in effect in accordance with the Tariff for fifteen (15) years after the Billing Commencement Date, defined herein as the later of November 1, 1992, or the i-service date of the facilities certificate for construction and operation in a Federal Energy Regulatory Commission proceeding prosecuted by Company in reliance upon this Agreement, and shall continue in effect thereafter until terminated by either Shipper or Company by not less than six (6) months prior written notice to the other. Provided however, this Agreement will terminate if the Federal Energy Regulatory Commission authorization to construct and operate the facilities under terms and conditions which achieve substantially the result requested by the company has not been received and approved by Shipper (such approval not to be unreasonably withheld) and accepted by Company by December 31, 1993. Service rendered pursuant to this Service Agreement shall be abandoned upon termination of this Agreement. This Service Agreement shall automatically terminate and be of no further force and effect unless Shipper shall furnish a proper security arrangement, in accordance with Subsection 9.1 of Rate Schedule T-1, to the Company within thirty (30) days after notice from the Company subsequent to the occurrence of any of the following events: The filing by Shipper or its parent of a voluntary petition in bankruptcy or the entry of a decree or order by a court having jurisdiction in the premises adjudging the Shipper as bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the Shipper under the Federal Bankruptcy Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Shipper or any substantial part of its property, or the ordering of the winding-up or liquidation of its affairs, with said order or decree continuing unstayed and in effect for a period of sixty (60) consecutive days. A failure by Shipper to pay in full the amount of any invoice rendered by Company shall continue for ten (10) days from the date payment is due. Termination of this U.S. Shippers Service Agreement shall not relieve Company and Shipper of the obligation to correct any volume imbalances hereunder, or Shipper to pay money due hereunder to Company and shall be in addition to any other remedies that Company may have. Article 8 - Applicable Law and Submission to Jurisdiction This Service Agreement and Company's Tariff, and the rights and obligations of Company and Shipper thereunder are subject to all relevant and United States lawful statutes, rules, regulations and orders of duly constituted authorities having jurisdiction. Subject to the foregoing, this Service Agreement shall be governed by and interpreted in accordance with the laws of the State of Nebraska. For purposes of legal proceedings, this Service Agreement shall be deemed to have been made in the State of Nebraska and to be performed there, and the Courts of that State shall have jurisdiction over all disputes which may arise under this Service Agreement, provided always that nothing herein contained shall prevent the Company from proceeding at its election against the Shipper in the Courts of any other state, Province or country. At the Company's request, the Shipper shall irrevocably appoint an agent in Nebraska to receive, for it and on its behalf, service of process in connection with any judicial proceeding in Nebraska relating to the Agreement. Such service shall be deemed completed on delivery to such process agent (even if not forwarded to and received by the Shipper). If said agent ceases to act as a process agent within Nebraska on behalf of Shipper, the Shipper shall appoint a substitute process agent within Nebraska and deliver to the Company a copy of the new agent's acceptance of that appointment within 30 days. Article 9 - Successors and Assigns After establishing creditworthiness in accordance with Section 9 of Rate Schedule T-1, any person which shall succeed by purchase, amalgamation, merger or consolidation to the properties, substantially as an entirety, of Shipper or of Company, as the case may be, and which shall assume all obligations under Shipper's Service Agreement of Shipper or Company, as the case may be, shall be entitled to the rights, and shall be subject to the obligations, of its predecessor under Shipper's Service Agreement. Either party to a Shipper's Service Agreement may pledge or charge the same under the provisions of any mortgage, deed of trust, indenture, security agreement or similar instrument which it has executed, or assign such Service Agreement to any affiliated Person (which for such purpose shall mean any person which controls, is under common control with or is controlled by such party). Nothing contained in this Article 9 shall, however, operate to release predecessor Shipper from its obligation under its Service Agreement unless Company shall, in its sole discretion, consent in writing to such release, which it shall not do unless it concludes that, on the basis of the facts available to it, such release is not likely to have a substantial adverse effect upon other Shippers or other Persons who may become liable to provide funds to Company to enable it to meet any of its obligations. Company shall not release any Shipper from its obligations under its Service Agreement without the written consent of the other firm Shippers unless: (a) such release is effected pursuant to an assignment of obligations by such Shipper, and the assumption thereof by the assignee, and the terms of such assignment and assumption render the obligations being assigned and assumed no more conditional and no less absolute than those at the time provided therein; and (b) such release is not likely to have a substantial adverse effect upon Company or the other Shippers. For the purposes hereof, and without limiting the generality of the foregoing, any release of any Shipper from its obligations under its Service Agreement shall be deemed likely to have a substantial adverse effect upon Company or the other Shippers if the assignee of such obligations has a credit standing which is not at least equal to the credit standing of the assignor of such obligations (credit standings in each case as reflected by the ratings on outstanding debt securities by Moody's Investors Service, Standard and Poor's Corporation or another rating service acceptable to all Shippers to the extent available or by other appropriate objective measures). Shipper shall, at Company's request, execute such instruments and take such other action as may be desirable to give effect to any such assignment of Company's rights under such Shipper's Service Agreement or to give effect to the right of a Person whom the Company has specified pursuant to Section 6 of the General Terms and Conditions of Company's FERC Gas Tariff as the Person to whom payment of amounts invoiced by Company shall be made; provided, however, that: (a) Shipper shall not be required to execute any such instruments or take any such other action the effect of which is to modify the respective rights and obligations of either Shipper or Company under this Service Agreement; and (b) Shipper shall be under no obligation at any time to determine the status or amount of any payments which may be due from Company to any Person whom the Company has specified pursuant to said Section 6 as the Person to whom payment of amounts invoiced by Company shall be made. Article 10 - Loss of Governmental Authority, Gas Supply, Transportation or Market Without limiting its other responsibilities and obligations under this Service Agreement, the Shipper acknowledges that it is responsible for obtaining and assumes the risk of loss of the following: (1) gas removal permits, (2) export and import licenses, (3) gas supply, (4) markets and (5) transportation upstream and downstream of the Company's pipeline system. Notwithstanding the loss of one of the items enumerated above, Shipper shall continue to be liable for payment to the Company of the transportation charges as provided for in this Service Agreement. Article 11 - Other Operating Provisions (This Article to be utilized when necessary to specify other operating provisions.) Article 12 - Exhibit A of Service Agreement, Rate Schedules and General Terms and Conditions Company's Rate Schedules and General Terms and Conditions, which are on file with the Federal Energy Regulatory Commission and in effect, and Exhibit A hereto are all applicable to this Service Agreement and are hereby incorporated in, and made a part of, this Service Agreement. In the event that the terms and conditions herein are in conflict with the General Terms and Conditions in Company's FERC Gas Tariff, the terms and conditions of this Service Agreement are controlling. IN WITNESS WHEREOF, The parties hereto have caused this Agreement to be duly executed as of the day and year first set forth above. ATTEST: NORTHERN BORDER PIPELINE COMPANY /s/ Janet K. Place BY: /s/J. C. Pyle Assistant Secretary Title:Vice President ATTEST: MOBIL OIL CANADA, by its Managing Partner, Mobil Oil Canada, Limited /s/Ed Brown Assistant Corporate Secretary BY: /s/R. F. Guerrant Title: Vice President P:place\T1profor EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT (Continued) COMPANY - Northern Border Pipeline Company COMPANY'S ADDRESS - 1111 South 103rd Street Omaha, Nebraska 68124-1000 SHIPPER - Mobil Oil Canada SHIPPER'S ADDRESS - P.O. Box 800 330 5 Avenue S.W. Calgary, AB, Canada T2P 2J7 Attn: Manager, Gas Supply & Transportation Points of Maximum Maximum Maximum Minimum Receipt Receipt Pressure Temperature Temperature Quantity (per day) Point of 30,000 Mcf 1435 psig 120 F 32 F Morgan, MT Total 30,000 Mcf Maximum Receipt Quantity EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT Points of Maximum Minimum Minimum Delivery Delivery Pressure Temperature (per day) Ventura, IA 30,000 Mcf 820 psig 32 F This Exhibit A is made and entered into as of August 30, 1991. On the effective date designated by the Federal Energy Regulatory Commission, it shall supersede the Exhibit A dated as of none, 19 . Effective Date of this Exhibit A is set forth in Article 7 hereof. T1018 NORTHERN BORDER PIPELINE COMPANY U.S. SHIPPERS SERVICE AGREEMENT AMENDED EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT Company: Northern Border Pipeline Company Company's Address: 1111 South 103rd Street Omaha, Nebraska 68124-1000 Shipper: Mobil Natural Gas Inc. Attn: Mr. Glen Hammerlindl Shipper's Address: 330 - 5th Avenue S.W. Calgary, AB, Canada T2P 2J7
Maximum Minimum Maximum Role Maximum Receipt Delivery Receipt Minimum (Notes Quantity Pressure Pressure Temperature Temperature Points 1 and 3) (MCF/Day) (PSIG) (PSIG) (F) (F) Port of Morgan, MT PR 30,000 1435 - 120 32 RD 30,000 - - - - TP 30,000 - - - - DD 30,000 - - - - Buford, ND PR 30,000 1435 - 120 32 (Secondary-Note 2) RD 30,000 - - - - TP 30,000 - - - - DD 30,000 - - - - Watford City, ND PR 30,000 1435 - 120 32 (Secondary-Note 2) RD 30,000 - - - - TP 30,000 - - - - DD 30,000 - - - - Hebron, ND PR 30,000 1435 - 120 32 (Secondary-Note 2) RD 30,000 - - - - TP 30,000 - - - - PD 30,000 - 725 - 32 DD 30,000 - - - - Glen Ullin, ND PR 30,000 1435 - 120 32 (Secondary-Note 2) RD 30,000 - - - - TP 30,000 - - - - PD 30,000 - 725 - 32 DD 30,000 - - - -
-1- NORTHERN BORDER PIPELINE COMPANY U.S. SHIPPERS SERVICE AGREEMENT AMENDED EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT (continued)
Maximum Minimum Maximum Role Maximum Receipt Delivery Receipt Minimum (Notes Quantity Pressure Pressure Temperature Temperature Points 1 and 3) (MCF/Day) (PSIG) (PSIG) (F) (F) Mina, SD RD 4,500 - - - - (Secondary-Note 2) TP 30,000 - - - - PD 4,500 - 750 - 32 DD 4,500 - - - - Aberdeen, SD RD 25,000 - - - - (Secondary-Note 2) TP 30,000 - - - - PD 25,000 - 800 - 32 DD 25,000 - - - - Webster, SD RD 5,000 - - - - (Secondard-Note 2) TP 30,000 - - - - PD 5,000 - 700 - 32 DD 5,000 - - - - Milbank, SD RD 8,073 - - - - (Secondary-Note 2) TP 30,000 - - - - PD 8,073 - 800 - 32 DD 8,073 - - - - Ivanhoe, MN RD 1,791 - - - - (Secondary-Note 2) TP 30,000 - - - - PD 1,791 - 700 - 32 DD 1,791 - - - - Marshall, MN RD 30,000 - - - - (Secondary-Note 2) TP 30,000 - - - - PD 30,000 - 800 - 32 DD 30,000 - - - - Westbrook, MN RD 500 - - - - (Secondary-Note 2) TP 30,000 - - - PD 500 - 800 - 32 DD 500 - - - - Welcome, MN RD 30,000 - - - - (Secondary-Note 2) TP 30,000 - - - - PD 30,000 - 796 - 32 DD 30,000 - - - -
-2- NORTHERN BORDER PIPELINE COMPANY U.S. SHIPPERS SERVICE AGREEMENT AMENDED EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT (continued)
Maximum Minimum Maximum Role Maximum Receipt Delivery Receipt Minimum (Notes Quantity Pressure Pressure Temperature Temperature Points 1 and 3) (MCF/Day) (PSIG) (PSIG) (F) (F) Ledyard, IA RD 4,000 - - - - (Secondary-Note 2) TP 30,000 - - - - PD 4,000 - 800 - 32 DD 4,000 - - - - Ventura, IA RD 30,000 - - - - TP 30,000 - - - - PD 30,000 - 820 - 32 DD 30,000 - - - - Total Maximum Receipt Quantity 30,000 MCF - - - - - - - - - - - Note 1: The point role will be either PR for physical receipts, RD for receipt by displacement, TP for transfer points, PD for physical deliveries, and DD for delivery by displacement. Note 2: Should nominations at secondary receipt and delivery points be received which exceed available capacity, volumes will be scheduled in accordance with Northern Border's nomination and scheduling procedures. Note 3: For receipt or delivery of gas by displacement, Company cannot and does not have an obligation to physically deliver or receive gas at these points. Volumes will be delivered or received at these point(s) only to the extent that corresponding equal or greater volumes are received or delivered by other parties at these points on the same day. These corresponding volumes will be used to displace volumes nominated for delivery or receipt by Shipper.
-3- NORTHERN BORDER PIPELINE COMPANY U.S. SHIPPERS SERVICE AGREEMENT AMENDED EXHIBIT A TO U.S. SHIPPERS SERVICE AGREEMENT (continued) This Exhibit A is made and entered into as of April 28, 1994. On the effective date designated by the Federal Energy Regulatory Commission, it shall supersede the Exhibit A dated as of February 4, 1993. The effective date of this Exhibit A is April 29, 1994. NORTHERN BORDER PIPELINE COMPANY ATTEST: By: Northern Plains Natural Gas Company, Operator /s/Janet K. Place By: /s/Robert A. Hill Title: Assistant Secretary Title: Vice President ATTEST: MOBIL NATURAL GAS INC. /s/M.L. Burns By: /s/R. F. Guerrant Title: Attorney-in-Fact Mobil Natural Gas Inc. 12450 GREENSPOINT DRIVE HOUSTON, TEXAS 77X 1991 July 23,1996 VIA FAX: 402/398-7870 Northern Border Pipeline P. O Box 3330 Omaha, NE 68lO3-0330 Attention: Marge Shade JOINT VENTURE MARKETING Dear Marge: Please be advised that effective August 1, 1996, Mobil Natural Gas Inc. (MNGI) will be doing business through a joint venture marketing company. The new entity, PanEnergy Trading and Market Services, L.L.C. ("PanEnergy Marketing" or "Agent") will serve as agent for MNGI and various other affiliates of Mobil Corporation ("Mobil"), including the party ("Principal") to the transportation contract (s) with your company, as listed on the Exhibit "A" to this letter. Principal warrants to you that Agent shall have authority to perform all shipper functions under the referenced contract (s), effective August 1, 1996 and continuing until Principal or Agent has notified you otherwise, in writing, and you have acknowledged the change. Authority shall include but not be limited to: * Performing nominations and confirmations * Applying shipper and/or producer PDAs as deemed appropriate * Receiving volume statements on-line and/or via hard copy * Negotiating month-to-month spot transportation discounts * Adding receipt and delivery points * Receiving and paying invoices for services rendered under the referenced contract (s) Authority shall exclude: * deleting points * canceling or terminating any referenced contract (s) * amending any referenced contract (s) in any way not listed above. Principal will hold your company harmless for all actions it takes as a result of directions by Agent, except for any purported cancellation, termination, or point deletion. Correspondence involving the referenced contract (s), and invoices for transportation for August 1996 and subsequent gas flow should be sent to: PanEnergy Trading Market Services, L L.C. Attn: Gas Accounting 1077 Westheimer, Suite 650 Houston, TX 77042 Principal will of course continue to be liable for performance. In the event Agent fails to pay you on time, in accordance with the referenced contract (s), you may bill Principal directly. Correspondence directly to Principal, and invoices for transportation prior to August 1996 should be sent to or care of: Mobil Natural Gas Inc. Attn: Gas Volume Analyst 12450 Greenspoint Drive Houston, TX 77060- 1991 Agent will also serve as producer/operator for purposes of scheduling and confirming all points on your pipeline that currently show MNGI or Principal as the producer/operator of record. As such, Agent should have access to all systems and reports currently accessible by MNGI. If you have questions, please call the MNGI gas control representative for your pipeline or Joe Woodard (713) 775-2655. Very truly yours, /s/Y.J. Bourgeois Y. J. Bourgeois Manager Equity Operations (713) 775-2591 MMM:GN Attachment THIS AGREEMENT made as of the 1st day of June, 1992. BETWEEN: MOBIL OIL CANADA, a Partnership, carrying on business in the Province of Alberta (hereinafter called the "Assignor") OF FIRST PART and MOBIL NATURAL GAS INC., a Delaware Corporation, having its Head Office in the City of Houston, State of Texas (hereinafter called the Assignee") OF THE SECOND PART and Northern BORDER PIPELINE COMPANY, a partnership carrying on business in the State of Nebraska and other States of the United States of America (hereinafter called "Northern Border") OF THE THIRD PART WHEREAS by a service agreement (firm service) (the service Agreement") dated the 30th day of August, 1991 between Assignor and Northern Border, the parties thereto agreed with respect to the Transportation of natural gas. AND WHEREAS the Service Agreement, Article 9 permits assignment to an affiliate, and the Assignee is an affiliate of the Assignor. AND WHEREAS the Assignor has agreed to assign, transfer, convey and set over unto the Assignee all its right, title, interest and estate in and to the Service Agreement. NOW THEREFORE THIS AGREEMENT WITNESSETH THAT, in consideration of the covenants and agreements herein contained, the parties hereto covenant and agree as follows: 1. The Assignor hereby assigns, transfers, conveys and sets over unto the Assignee, its successors and assigns, absolutely and forever, all of the Assignor' s right, title, interest and estate in, to and under the Service Agreement. 2. The Assignee accepts the assignment and covenants and agrees with theAssignor and Northern Border and each of them, that from and after the date of this Agreement, the Assignee will observe and perform the covenants and agreements of the Assignor contained in the Service Agreement. 3. The Assignee expressly acknowledges that in all matters relating to the Service Agreement subsequent to the assignment to the Assignee, and until thirty (30)days after the delivery of this Agreement properly executed to Northern Border, the Assignor has been acting as trustee for and as the duly authorized agent of the Assignee, and the Assignee does hereby expressly ratify, adopt and confirm all acts or omissions of the Assignor in its capacity as such trustee and agent to the end that all such acts or omissions shall for all purposes be construed as made or done by the Assignee. 4. Northern Border hereby consents to the Assignor assigning its right, title, interest and estate in the Service Agreement to the Assignee and agrees with the Assignor that from and after the date of this Agreement, it shall hold the Assignee responsible for the observance and performance of covenants and agreements contained in the Service Agreement, and agreed to be obsessedand performed by the Assignor, provided that nothing herein shall relieve the Assignor of its obligations arising pursuant to the Service Agreement. The Assignor releases and relieves Northern Border from all its obligations to the Assignor arising under the provisions of the Service Agreement after the date of this Agreement. 5. The address of the Assignee shall be: Greenspoint Drive, Houston, Texas 77060-191 6. This Agreement will become effective when executed by all parties named herein, but may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same agreement. 7. The Service Agreement as hereby amended is ratified and confirmed. 8. Nothing herein contained shall be taken as authorization for or consent to any further assignment of the right, title and interest or the obligations of the Assignee under the Service Agreement, other than what is permitted in the Service Agreement. IN WITNESS WHEREOF the parties hereto have properly executed this Agreement as of the date first above written. MOBIL OIL CANADA, a Partnership MOBIL NATURAL GAS INC. by its managing partner MOBIL OIL CANADA, LTD. Per: /s/Randy E. W. Selin Per: /s/W. L. Luthy AUTHORIZED SIGNATORY AUTHORIZED SIGNATORY NORTHERN BORDER PIPELINE COMPANY, BY: NORTHERN PLAINS NATURAL GAS COMPANY, MANAGING PARTNER Per:/s/ J.C. Pyle AUTHORIZED SIGNATORY THIS IS THE SIGNATURE PAGE TO THE AGREEMENT MADE AS OF THE 1ST DAY OF JUNE, 1992 BETWEEN MOBIL OIL CANADA, MOBIL NATURAL GAS INC. AND NORTHERN BORDER PIPELINE COMPANY EX-27 3 ARTICLE 5 FDS FOR 10-K
5 1,000 YEAR DEC-31-1996 DEC-31-1996 0 41,390 19,271 0 4,128 64,789 1,513,116 575,257 1,016,484 78,747 0 0 0 0 410,586 1,016,484 0 201,943 0 99,735 0 0 33,117 50,285 0 50,285 0 0 0 50,285 1.88 1.88
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