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:
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.
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.
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.
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.
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:
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.
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").
Item 7.
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.
Item 8. Financial Statements
The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page.
Item 9.
Item 9. Disagreements on Accounting and Financial Disclosure
None.
PART III
Item 10.
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.
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:
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.
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:
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.
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:
Mr. DeRoin participates in the Executive Supplemental Survivor Benefit Plan. In the event of death after retirement, the Plan provides an annual benefit to the participant's beneficiary equal to 50 percent of the participant's annual base salary at retirement, paid for 10 years. The Plan also provides that in the event of death before retirement, the participant's beneficiary receives an annual benefit equal to 30% of the participant's annual base salary at death, paid for the life of the participant's spouse (but for no more than 20 years in some cases).
Severance Plans
Enron's Severance Pay Plan, as amended, provides for the payment of benefits to employees who are terminated for failing to meet performance objectives or standards or who are terminated due to reorganization or economic factors. The amount of benefits payable for performance related terminations is based on length of service and may not exceed six weeks' pay. For those terminated as the result of reorganization or economic circumstances, the benefit is based on length of service and amount of pay up to a maximum payment of 26 weeks of base pay. If the employee signs a Waiver and Release of Claims Agreement, the severance pay benefits are doubled. Under no circumstances will the total severance pay benefit exceed 52 weeks of pay. Under the Enron Corp. Change of Control Severance Plan, in the event of an unapproved change of control of Enron, any employee who is involuntarily terminated within two years following the change of control will be eligible for severance benefits equal to two weeks of base pay multiplied by the number of full or partial years of service, plus one month of base pay for each $10,000 (or portion of $10,000) included in the employee's annual base pay, plus one month of base pay for each five percent of annual incentive award opportunity under any approved plan. The maximum an employee can receive is 2.99 times the employee's average W-2 earnings over the past five years.
Item 12.
Item 12. 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.
Item 13.
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.
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.
(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
Page No.
Report of Independent Public Accountants Consolidated Balance Sheet - December 31, 1996 and 1995 Consolidated Statement of Income - Years Ended December 31, 1996, 1995 and 1994 Consolidated Statement of Cash Flows - Years Ended December 31, 1996, 1995 and 1994 Consolidated Statement of Changes in Partners' Capital - Years Ended December 31, 1996, 1995 and 1994 Notes to Consolidated Financial Statements through
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
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:
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)
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.