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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION

                              Washington, DC 20549

                              -------------------


                                    FORM 10-K

              [X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                   For the fiscal year ended December 31, 2001
                                       Or
             [ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

      For the transition period from January 1, 2001 to December 31, 2001.

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                        Commission File Number 333-42578


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
             (Exact name of registrant as specified in its charter)
           DELAWARE                                      06-1285387
  (State or other jurisdiction of           (I.R.S. Employer Identification No.)
  incorporation or organization)
                               ONE CORPORATE DRIVE
                                    SUITE 600
                         SHELTON, CONNECTICUT 06484-6211
                     (Address of principal executive office)
                                   (Zip Code)

                                 (203) 925-7200
              (Registrant's telephone number, including area code)

                              -------------------

Securities registered pursuant to Section 12(b)
of the Act
            NONE                                           NONE
    (Title of each class)                 (Name of exchange on which registered)
           Securities registered pursuant to Section 12(g) of the Act:
                                      NONE
                                (Title of class)

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934
during the preceding 12 months (or shorter period that the registrant was
required to file such reports), and (2) has been subject to the filing
requirements for at least the past 90 days.
                                Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
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                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

          FORM 10-K ANNUAL REPORT, FOR THE YEAR ENDED DECEMBER 31, 2001

                                TABLE OF CONTENTS
                                                                           Page

Special Note Regarding Forward-Looking Statements.............................1

                                     PART I.

Item 1.     Business..........................................................1

Item 2.     Properties.......................................................14

Item 3.     Legal Proceedings................................................15

Item 4.     Submission of Matters to a Vote of Security Holders..............15

                                    PART II.

Item 5.     Market for the Registrant's Common Equity and Related
            Stockholder Matters..............................................15

Item 6.     Selected Financial Data..........................................15

Item 7.     Management's Discussion and Analysis of Financial Condition
            and Results of Operations........................................16

Item 7a.    Quantitative and Qualitative Disclosures About Market Risk.......23

Item 8.     Financial Statements and Supplementary Data......................23

Item 9.     Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure.........................................24

                                    PART III.

Item 10.    Directors and Executive Officers of the Partnership..............24

Item 11.    Executive Compensation...........................................27

Item 12.    Security Ownership of Certain Beneficial Owners and Management...30

Item 13.    Certain Relationships and Related Transactions...................31

                                    PART IV.

Item 14.    Exhibits, Financial Statement Schedules and Reports on
            Form 8-K.........................................................31

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                                     PART V.

Index to Financial Statements................................................F-1
































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                SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

     This annual report contains various forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. When used in this annual
report, the words "believes", "anticipates", "expects" and similar expressions
are used to identify forward-looking statements. Such forward-looking statements
are based on current expectations, are not guarantees of future performance and
include assumptions about future market conditions, operations and results. They
are made in reliance on the "safe harbor" provisions of the Private Securities
Litigation Reform Act of 1995. Iroquois Gas Transmission System, L.P. (the
"Partnership") can give no assurance that such expectations will be achieved.
The many factors that could cause actual results to differ materially from those
in the forward-looking statements herein include, but are not limited to:

          o    future demand and prices for natural gas;

          o    availability of supplies of Canadian natural gas;

          o    regulatory, political, legislative and judicial developments,
               particularly with regard to regulation by the Federal Energy
               Regulatory Commission (the "FERC");

          o    competitive conditions in the marketplace;

          o    changes in the receptivity of the financial markets to the
               Partnership or other oil and gas credits similar to the
               Partnership and, accordingly, the Partnership's strategy for
               financing any change in business strategy or expansion.

     A discussion of these and other factors which may affect the Partnership's
actual results, performance, achievements or financial position is contained in
the "Risk Factors" section below. The Partnership does not undertake any
obligation to publicly update or revise forward-looking statements, whether as a
result of new information, future events, or otherwise.

                                    PART I.

ITEM 1.  BUSINESS

Introduction

     Iroquois Gas Transmission System, L.P. is a Delaware limited partnership.
It was formed for the purpose of constructing, owning and operating a 375-mile
interstate natural gas transmission pipeline from the Canada-United States
border near Waddington, New York to South Commack, Long Island, New York. The
Partnership provides service to local gas distribution companies, electric
utilities and electric power generators, as well as marketers and other
end-users, directly or indirectly, by connecting with pipelines and exchanges
throughout the northeastern United States. The Partnership is exclusively a
transporter of natural gas in interstate commerce and operates under authority
granted by the FERC. The Partnership

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commenced full operations in 1992, creating a link between markets in the states
of Connecticut, Massachusetts, New Hampshire, New Jersey, New York and Rhode
Island, and western Canada natural gas supplies. The Partnership's pipeline
system connects with four interstate pipelines and the pipeline system of
TransCanada PipeLines Limited (the "TransCanada System") at the Canada-United
States border near Waddington, New York. The Partnership has more than doubled
the amount of gas that flows through its pipeline system on an annual basis
since 1992, while the transportation rates the Partnership charges have
decreased by approximately 40% as a result of FERC rate reduction orders.

     The Partnership provides transportation service to its shippers under
transportation service contracts which provide for either firm reserved service
or interruptible service. Firm reserved transportation service contracts are
either long-term, multi-year contracts or short-term contracts of less than one
year. Under firm reserved transportation contracts, a certain amount of the
Partnership's pipeline system's capacity is reserved for the use of a shipper.
Under interruptible transportation service contracts, a shipper's access to the
Partnership's pipeline system depends upon the availability of pipeline system
capacity on any given day. Currently, the Partnership has 35 shippers under
long-term firm reserved transportation service contracts and its pipeline
system's contracted capacity of 1,006 thousands of dekatherms per day, or
MDth/d, is fully subscribed. As of December 31, 2001, approximately 88% of the
Partnership's pipeline capacity was contracted under firm reserved
transportation service contracts that continue until at least 2011.

     The partners and their respective interests in the Partnership are as
follows:

                                                                    Percentage
                                                                    Ownership
  Ultimate Parent of Partner     Name of Partner                     Interest
  --------------------------     ---------------                    ----------

  TransCanada PipeLines          TransCanada Iroquois Ltd.            29.0%
    Limited                      TCPL Northeast Ltd.                  11.96%

  KeySpan Energy Corporation     NorthEast Transmission               19.4%
                                   Company
                                 LILCO Energy Systems, Inc.            1.0%

  Dominion Resources, Inc.       Dominion Iroquois, Inc.              24.72%

  PG&E Generating Company        JMC-Iroquois, Inc.                    4.93%
                                 Iroquois Pipeline Investment, LLC     0.84%

  CTG Resources, Inc.            TEN Transmission Company              4.87%

  New Jersey Resources           NJNR Pipeline Company                 3.28%
    Corporation


     On January 18, 2000, El Paso Energy Corp. and The Coastal Corporation
("Coastal") announced plans to merge. At the time, Coastal, through its
affiliates, owned a 17.0% interest in the Partnership. As a condition of the
merger, the Federal Trade Commission, or FTC, ordered Coastal to divest all of
its interest in the Partnership. Four of the remaining partners of the

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Partnership agreed to purchase Coastal's interest. On April 27, 2001, the FTC
approved the divestiture of Coastal's interests to affiliates of Dominion
Resources, Inc., TransCanada PipeLines Limited, PG&E Corporation and New Jersey
Resources Corporation. The divestiture transaction closed on May 4, 2001.

     Iroquois Pipeline Operating Company ("IPOC"), a wholly owned subsidiary of
the Partnership, is the operator of the Partnership's pipeline system and is
responsible for the day-to-day management of the pipeline system pursuant to an
operating agreement entered into between the Partnership and IPOC on January 14,
1989.

Description of the Pipeline

     Pipeline Facilities. The Partnership's pipeline system extends 375 miles
from the Canada-United States border near Waddington, New York to South Commack,
Long Island, New York. The pipeline system offers access to natural gas supplies
in Western Canada to local gas distribution companies, electric utilities,
electric power generators and natural gas marketers operating in the New York
and New England power grids.

     Compressor Stations. Compressor stations increase the pressure of natural
gas flowing through the Partnership's pipeline system, increasing its capacity
and the volume of natural gas that can be shipped under contract. In May 1992,
the FERC approved construction of the Partnership's first compressor station
located in Wright, New York. This station went into service in November 1993 and
by that year-end, the volumes under contract had increased to 648.6 MDth/d. A
second compressor station, in Croghan, New York, was commissioned in December
1994, expanding firm reserved service to 758.9 MDth/d. The Partnership's third
compressor station, located in Athens, New York, commenced operation on
November 1, 1998. As of December 31, 2001, the Partnership had firm reserved
transportation contracts in place to deliver 1,006 MDth/d.

     Metering Stations and Interconnects. The Partnership receives natural gas
from the TransCanada System at the Canada-United States border near Waddington,
New York and delivers gas in New York and Connecticut through meters tied
directly to end-user markets. The Partnership's pipeline system operates and
maintains a total of 19 delivery meters to which the Partnership has primary
rights with a combined capacity of approximately 3.8 million Dth/d. Each meter
station consists of a separate control building that contains gas measurement
equipment and electrical and instrumentation devices. The Partnership has
incorporated a manual chart recorder system to maintain continuous gas
measurement in the event of a total electronic failure. The Partnership also
delivers gas to the other major natural gas pipelines in the Northeast through
its five interconnections with four interstate pipelines: Algonquin Gas
Transmission Company, Dominion Transmission Corporation, Tennessee Gas Pipeline
Company, and the TransCanada System. The Partnership also has an interconnection
with the New York Facilities System at South Commack, Long Island. The New York
Facilities System is a pipeline system owned and used by both Consolidated
Edison Company of New York, or Con Ed, and KeySpan Energy Corporation.

     Communications. The Partnership maintains 24-hour monitoring of its
pipeline system via a computerized data monitoring and control system known as
SCADA (supervisory control

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and data acquisition) that links all compressor stations and maintenance bases
with the Partnership's gas control center in Shelton, Connecticut. Remote
facilities along the pipeline route are accessed with the use of multiple
address radio communication links to a satellite system, which allows the
pipeline system to be operated remotely from the gas control center.

     Operations. The gas control center houses the gas management, control and
computer systems required to operate the pipeline system and dispatch gas. A
backup gas control center is located in Oxford, Connecticut. In the event that
neither of these control centers is available, the Partnership's entire pipeline
system can be monitored and operated from the Wright compressor station. The
Partnership has operated the pipeline system with regular and continuous
maintenance since it commenced operations. Inspections and tests have been
performed at prescribed intervals to ensure the integrity of the system. These
include periodic corrosion surveys, testing of relief and over-pressure devices
and periodic aerial inspections of the right-of-way, all conforming to the
United States Department of Transportation regulations. Such actions have
allowed the Partnership to maintain high operational availability of its system,
in particular, its compressors. Availability is a measure of the overall
reliability of a compressor. During the last five years, the average
availability of the Partnership's compressor units has ranged from 97% to 98%, a
rate that the Partnership believes is higher than the rest of the industry. In
addition, because multiple compressor stations are operational, the system is
capable of achieving high levels of throughput even when one or more compressor
units are experiencing an outage.

Transportation Services and Shippers

     The design capacity of the Partnership's pipeline system is fully
subscribed under firm reserved transportation service contracts with 35
shippers. Under the firm reserved transportation service contracts, the pipeline
receives natural gas on behalf of shippers at designated receipt points and
transports the gas on a firm basis up to each shipper's maximum daily quantity.
As of December 31, 2001, approximately 88% of the capacity of the Partnership's
pipeline system was contractually committed through at least November 1, 2011.
The Partnership has also entered into several short-term (less than one year)
firm reserved transportation service contracts and numerous interruptible
transportation service contracts. Reservation and variable fees are payable
under firm reserved transportation service contracts and depend on the volume of
gas shipped and the zone within which the gas is shipped. The Partnership is
also authorized by the FERC to enter into "negotiated rate" contracts with
shippers who are provided with a service that varies in some manner from the
standard tariff offering. To date, the Partnership has entered into a limited
number of negotiated rate contracts for short-term firm transportation service.

     The Partnership's pipeline system is divided into two zones: zone one
covers the mainline from Waddington to Wright, New York and zone two covers the
territory from Wright, New York through Connecticut to South Commack, Long
Island, New York.

     The Partnership's shippers under firm transportation service contracts
consist of major electric and gas utility companies, marketers, gas producers
and independent electric generating companies. KeySpan Energy Corporation, PG&E
Corporation and El Paso Energy Corp.,

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through their affiliates, each accounted for more than 10% of the Partnership's
revenues as of December 31, 2001.

     As of December 31, 2001, approximately 97% of the pipeline system's volume
was under firm reserved transportation service contract with shippers who are
rated investment grade by a nationally recognized credit rating agency.
Approximately 44% of the pipeline system's volume was under firm reserved
transportation service contract with shippers with a debt rating of "A" or
higher. Certain of the Partnership's shippers are not rated by credit rating
agencies. Non-rated or non-investment grade rated shippers accounted for
approximately 1% of the pipeline system's volume. The Partnership has determined
under internal credit standards that those shippers or their guarantors are
creditworthy so that they are not required to post credit support in connection
with their transportation service contracts. Approximately 2% of the capacity
was contracted by shippers who have agreed to post letters of credit in an
amount equal to three months of demand charges pursuant to their transportation
service contracts or who have made other credit support arrangements that the
Partnership finds satisfactory.

Demand for Transportation Capacity

     The Partnership's market, the northeastern United States, is comprised of
approximately 12 million natural gas customers, who account for approximately
19% of all natural gas customers in the United States. The Northeast has
experienced an overall increase in natural gas demand in the last decade. The
Partnership expects this demand to continue to grow by 2-3% per year through
2025. The bulk of the growth in the Northeast is expected to occur in the
electric generation sector, which the Partnership expects to grow by 5-8% per
year.

     The Partnership is planning an Eastchester/New York City expansion of its
pipeline system consisting of an approximately 33-mile mainline extension
running from the mainline on Long Island near Northport, through the Long Island
Sound to Eastchester, New York. As currently planned, the new line will proceed
on land for three miles, connecting with the northern section of ConEd's gas
distribution facilities. The Partnership believes that because of the location
of its pipeline and its ability to utilize Long Island Sound, a means of direct
access to the New York City market can be developed with minimal environmental
and landowner or right-of-way issues. In contrast, other competing proposals
must access this market through congested areas at a greater expense. On April
28, 2000, the Partnership filed an application with the FERC pursuant to the
Natural Gas Act of 1938 (the "Natural Gas Act") for a certificate of public
convenience and necessity to construct and operate the Eastchester/New York City
expansion, requesting a November 2002 in-service date. On February 22, 2001, the
Partnership announced that the project had been fully subscribed. Under
precedent agreements, which contain conditions that must be satisfied before a
contract for firm transportation service is signed, five project shippers agreed
to take all of the 230 MDth/d of transportation capacity proposed to be built.
On December 26, 2001, the FERC issued a certificate authorizing the Partnership
to construct and operate the Eastchester Facilities ("December 26 Order"). On
January 25, 2002, the Partnership accepted the terms of the certificate. A
condition in the December 26 Order requires that, prior to commencing
construction, the project shippers execute firm service agreements with 10-year
terms for the entire 230 MDth/d of transportation capacity proposed to be built.
This condition was based on the precedent agreements with the five project
shippers. However, as a result of the current uncertainty and slowdown in the
energy market,

                                       5
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exacerbated by the Enron Corporation bankruptcy proceedings and the resulting
examination, both internal and external, of the financial health of a variety of
other energy market participants, certain Eastchester shippers that were
obligated under the precedent agreements to execute firm transportation service
agreements have indicated an unwillingness to do so. As a result, the
Partnership expects that it will not have executed contracts for 100% of the
total project capacity prior to April 2002, when it anticipates commencing
construction of the Eastchester Facilities. On February 28, 2002, the
Partnership filed a request with the FERC to commence construction even if
service contracts for the full 230 MDth/d of service have not been executed. On
March 13, 2002, the FERC granted the Partnership's request.

     The Partnership has also filed applications with the FERC to construct and
operate three other proposed projects. On November 8, 2001, the Partnership
filed an application to construct and operate a second compressor unit at its
existing Athens, New York compressor station. The new facilities would provide
up to 70 MDth/d of firm transportation service to Athens Generating Company,
L.P. with whom the Partnership has executed a precedent agreement for this
service. The proposed in-service date for the Athens Project is September 1,
2003.

     On November 20, 2001, the Partnership filed an application to construct and
operate a new compressor station to be located in Brookfield, Connecticut. This
facility is designed to provide up to 85 MDth/d of firm transportation service
to southern Long Island and the New York City area. The Partnership would
provide firm transportation service to the two shippers with whom it has
executed precedent agreements. The proposed in-service date for the Brookfield
Project is April 2004.

     On December 14, 2001, the Partnership filed an application to construct
approximately 29 miles of 20-inch pipeline from a point offshore of Milford,
Connecticut to a point in Brookhaven, Suffolk County, New York and additional
compression and cooling facilities. These facilities are designed to provide
approximately 175 MDth/d of firm transportation service to the eastern end of
Long Island, New York. The Partnership would provide firm transportation service
to the five shippers with whom it has executed precedent agreements. The
proposed in-service date for the Eastern Long Island Expansion Project is
November 2004.

     The Partnership's long-term financial condition is dependent on the
continued availability of competitively priced western Canadian natural gas for
import into the United States. Natural gas reserves may require significant
capital expenditures by others for exploration and development drilling and the
installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered. The Western
Canada Sedimentary Basin is currently, and is expected to remain, the primary
source of natural gas for the Partnership's pipeline system. Sable Island and
other natural gas discoveries offshore of Nova Scotia may also provide sizable
gas supplies in the future. Advances in technology may increase the ultimate
recoverable reserves from the Western Canada Sedimentary Basin and offshore
basins and bring gas supplies on stream that are currently not economical to
produce.

     A variety of factors could affect the demand for natural gas in the markets
that the Partnership's pipeline system serves. These factors include:

          o    economic conditions;

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          o    fuel conservation measures;

          o    competition from alternative energy sources;

          o    climatic conditions;

          o    legislation or governmental regulations; and

          o    technological advances in fuel economy and energy generation
               devices.

     The Partnership cannot predict whether these or other factors will have an
adverse effect on demand for use of the pipeline system or how significant that
adverse effect could be.

Competition

     The Partnership faces varying degrees of competition from other major
pipeline systems in the Northeast and alternative energy sources, including
electricity, coal, propane and fuel oils. Additionally, in recent years, the
FERC has issued orders designed to increase competition in the natural gas
industry. These orders have resulted in pipelines competing with their
customers, who are now allowed to resell their unused firm reserved
transportation capacity to other shippers. Firm reserved transportation
contracts traditionally had terms of 10 to 20 years; however, due to increased
competition, new firm reserved transportation contracts are usually of a shorter
duration.

FERC Regulation and Tariff Structure

     General. The Partnership is subject to extensive regulation by the FERC as
a "natural gas company" under the Natural Gas Act. Under the Natural Gas Act and
the Natural Gas Policy Act of 1978, the FERC has jurisdiction over the
Partnership 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. The Partnership, where required, holds certificates of public
convenience and necessity issued by the FERC covering its facilities, activities
and services.

     The Partnership's rates and charges for transportation in interstate
commerce are subject to regulation by the FERC. FERC regulations and the
Partnership's FERC-approved tariff allow the Partnership to establish and
collect rates designed to give it an opportunity to recover all actually and
prudently incurred operations and maintenance costs of its pipeline system,
including taxes, interest, depreciation and amortization and a regulated equity
return. The FERC has granted the Partnership the authority to negotiate rates
with its current and potential shippers. The flexibility of such rates will
allow the Partnership to respond to market conditions, as well as permit the
Partnership to negotiate rates or a rate formula that will meet the specific
needs of individual shippers. This ability to negotiate rates will be an
important tool in attracting the growing electric generation market to the
Partnership's pipeline system.

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     Rates charged by the Partnership may not exceed the rates approved by the
FERC. In addition, the Partnership is prohibited from granting any undue
preference to any person, or maintaining any unreasonable difference in its
rates or terms and conditions of service.

     In general, there are two methods available for changing the rate charged
to shippers, provided that the transportation service contracts do not bar such
changes. Under Section 4 of the Natural Gas Act and applicable FERC regulations,
a pipeline may voluntarily seek a change, generally by providing at least 30
days' prior notice to the FERC of the proposed changes and filing the
appropriate rate change application. If the FERC determines that a proposed rate
change may not be just and reasonable as required by the Natural Gas Act, then
the FERC may suspend the rate change for up to five months and set the matter
for an investigation. Subsequent to any suspension ordered by the FERC, the
proposed change may be placed in effect by the pipeline pending final FERC
review. If the pipeline chooses to do this, any increase reflected in the
proposed changes will, in the ordinary course of events, be collected subject to
refund. It is also possible that a pipeline seeking to increase the rates it
charges its shippers pursuant to a rate change application under Section 4 of
the Natural Gas Act may, after review by the FERC, have its rates cut by the
FERC instead. Under Section 5 of the Natural Gas Act, on its own motion or based
on a complaint filed by a customer of a pipeline or other interested person, the
FERC may initiate a proceeding seeking to compel a pipeline to change any rate
or term or condition of service which is on file. If the FERC determines that an
existing rate or condition is unjust, unreasonable, unduly discriminatory or
preferential then any rate reduction or change in service term or condition
which is ordered at the conclusion of such a proceeding is generally effective
prospectively from the date of the order requiring such change.

     The nature and degree of regulation of natural gas companies have changed
significantly during the past 10 years, and there is no assurance that further
substantial changes will not occur or that existing policies and rules will not
be applied in a new or different manner.

     Regulatory Proceedings. After extensive negotiations with various parties
to a series of previous rate-related hearings and orders between 1996 and 1999,
on December 17, 1999, the Partnership filed with the FERC an offer of
settlement, which shall be referred to as the rate settlement. By order dated
February 10, 2000, the FERC approved the rate settlement, effectively resolving
all remaining issues in the Partnership's previous rate proceedings. The
principal elements of the rate settlement are:

          o    a reduction in maximum demand rates phased-in over a three-year
               period that began on January 1, 2001;

          o    withdrawal of certain pending petitions for review regarding FERC
               actions on the Partnership's general rate change application;

          o    a rate moratorium under which the Partnership may not file an
               application to increase rates pursuant to the Natural Gas Act
               prior to January 1, 2004 and no party may file for reductions in
               rates pursuant to the Natural Gas Act prior to April 1, 2003 or
               receive such reductions prior to January 1, 2004 (the rate
               settlement contains certain limited exceptions to the

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               moratorium for tariff changes not intended to effect changes in
               the Partnership's firm reserved service quality or rates); and

          o    retention by the Partnership of revenues associated with new
               volumes, facilities, services or classes of service added after
               November 1, 1999.

     As provided in the rate settlement, the Partnership's maximum demand rate
decreased by $0.00973/Dth effective January 1, 2001, by $0.02433/Dth effective
January 1, 2002; and will decrease by $0.01460/Dth effective January 1, 2003,
for a total cumulative reduction of $0.04866/Dth. The rate settlement also
provides for similar reductions in other rates charged by the Partnership. The
total revenue impact of these rate reductions was $2.4 million in 2001, and is
expected to be approximately $6.0 million in 2002 and $3.6 million in 2003,
based on long-term firm reserved transportation service contracts in place as of
December 31, 2001.

     Rulemaking on FERC's Regulation of Transportation Services. On February 9,
2000, the FERC adopted its Order No. 637. Order No. 637 is intended to increase
efficiency as the market for natural gas continues to become more open and
competitive. As a result of Order No. 637, interstate pipelines should have
greater flexibility in tailoring the firm reserved services they offer to
customers and customers should have improved opportunities to resell their
unused firm reserved transportation service in the secondary market, thus
potentially enhancing the value of firm pipeline service to customers. Order No.
637:

          o    institutes a two-year waiver of price ceilings on short-term
               released capacity (the FERC may later consider a permanent waiver
               based on the experience gained through this experiment);

          o    allows pipelines to make pro forma tariff filings proposing peak
               and off-peak rates for short-term services;

          o    allows pipelines to propose term-differentiated rates for
               short-term and long-term services, with any "excess" revenues
               shared equally with long-term customers;

          o    changes regulations regarding scheduling procedures, capacity
               segmentation, and pipeline penalties to allow shippers to utilize
               pipeline capacity more efficiently;

          o    narrows the right of first refusal for future long-term contracts
               while protecting the right of captive customers to renew
               long-term contracts; and

          o    improves reporting requirements to increase price transparency
               and provide additional information on individual transactions to
               assist the FERC in its effort to monitor the functioning of
               natural gas markets.

     While Order No. 637 requires some significant changes in the functioning of
the secondary market for firm capacity, its implementation should not materially
affect the level of revenues the Partnership receives. The Partnership will have
to incur some costs to modify its

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tariff and information systems to allow it to comply with Order No. 637.
However, the Partnership does not expect these expenditures to be material.

     As required by Order No. 637, the Partnership filed pro forma tariff sheets
with the FERC. This filing is pending at the FERC. See Footnote 7 to the
Consolidated Financial Statements for additional detail.

Safety Regulations

     The Partnership's operations are also subject to regulation by the United
States Department of Transportation under the Natural Gas Pipeline Safety Act of
1969, as amended, or the NGPSA, relating to the design, installation, testing,
construction, operation and management of the Partnership's pipeline system. The
NGPSA requires any entity that owns or operates pipeline facilities to comply
with applicable safety standards, to establish and maintain inspection and
maintenance plans and to comply with such plans.

     The NGPSA was amended by the Pipeline Safety Act of 1992 to require the
Department of Transportation's Office of Pipeline Safety to consider protection
of the environment when developing minimum pipeline safety regulations. In
addition, the amendments required the Department of Transportation to issue
pipeline regulations concerning, among other things, the circumstances under
which emergency flow restriction devices should be required, training and
qualification standards for personnel involved in maintenance and operation, and
requirements for periodic integrity inspections, including periodic inspection
of facilities in navigable waters which could pose a hazard to navigation or
public safety. The amendments also narrowed the scope of gas pipeline exemptions
pertaining to underground storage tanks under the Resource Conservation and
Recovery Act. The Partnership believes its operations comply in all material
respects with the NGPSA; however, the industry, including the Partnership, could
be required to incur additional capital expenditures and increased costs
depending upon regulations issued by the Department of Transportation under the
NGPSA and/or future pipeline safety legislation.

Environmental Matters

     Environmental laws and regulations have changed substantially and rapidly
over the last 20 years, and the Partnership anticipates that there will be
continuing changes. Increasingly strict federal, state or local environmental
restrictions, limitations and regulations have resulted in increased operating
costs for the Partnership, and it is possible that the costs of compliance with
environmental laws and regulations will continue to increase. To the extent that
environmental costs are normal costs of doing business, these costs would be
recoverable under the Partnership's rates through future rate proceedings.

     Current Operations. At each of the Partnership's three natural gas
compressor stations, IPOC routinely monitors environmental standards and
controls and, to date, IPOC has found that environmental permits and regulations
are being complied with in all material respects.

     Settlement of Federal and State Investigations. On May 23, 1996, as part of
a resolution of federal criminal and civil investigations of the construction of
certain of the Partnership's pipeline facilities, IPOC pled guilty to four
felony violations of the Clean Water Act and entered into consent decrees under
the Clean Water Act in four federal judicial districts. Although not a

                                       10
<PAGE>

named defendant, the Partnership signed the plea agreement and consent decrees
and is bound by their terms. The Partnership also entered into related
settlements with the State of New York, the FERC and the Department of
Transportation. Under these various agreements, the Partnership and IPOC agreed
to pay $22 million in fines and penalties and to take remedial measures. The
Partnership and IPOC are taking certain actions and adopting a number of
procedures to reduce their risk of noncompliance with environmental regulations
in the future. In August 1996, as a result of settlement of the federal
proceedings, IPOC was placed by the Environmental Protection Agency on a list
that excludes IPOC from federal financial and other assistance under federal
programs and limits IPOC's ability to do business with U.S. government agencies.
This has not had and the Partnership does not expect it to have a material
adverse impact on the Partnership's business.

Employees

     The Partnership does not directly employ its personnel. The Partnership's
personnel and services are provided by IPOC, its wholly owned subsidiary,
pursuant to the Partnership's operating agreement with IPOC. The Partnership
reimburses IPOC for all reasonable expenses incurred in operating the
Partnership's pipeline system including salaries and wages and related taxes and
benefits. As of December 31, 2001, IPOC had 123 employees.

Risk Factors

     The Partnership's business involves significant risks and uncertainties
including those described below.

The Partnership may not be able to maintain existing shippers or acquire new
shippers

     As of December 31, 2001, approximately 88% of the capacity of the
Partnership's pipeline system was contracted through at least November 1, 2011.
The Partnership cannot give any assurances that it will be able to extend or
replace these contracts at the end of their initial terms. The extension or
replacement of the existing long-term contracts with shippers depends on a
number of factors beyond the Partnership's control, including:

          o    the supply and price of natural gas in Canada and the United
               States;

          o    competition to deliver gas to the Northeast from alternative
               sources of supply;

          o    the demand for gas in the Northeast;

          o    whether transportation of gas pursuant to long-term contracts
               continues to be market practice; and

          o    whether the Partnership's business strategy, including its
               expansion strategy, is successful.

     If the Partnership materially breaches its obligations under any
transportation service contract, the affected shipper may have various remedies
including termination of its

                                       11
<PAGE>

transportation service contract. If these contracts are not extended or replaced
or are terminated the Partnership's cash flows and ability to service its
outstanding senior notes may be affected.

The Partnership is dependent on the performance of its shippers

     The Partnership is dependent upon shippers for revenues from contracted
transportation capacity on its pipeline system. The transportation service
contracts obligate the shippers to pay reservation charges regardless of whether
or not they use their reserved capacity to transport natural gas on the pipeline
system, subject to limited rights in favor of the shippers in certain
circumstances to receive reservation charge credits when they release their firm
reserved capacity to other shippers. As a result, under the FERC-approved rate
structure, the Partnership's profitability will generally depend upon the
continued creditworthiness of the shippers rather than upon the amount of
natural gas transported.

     The Partnership's rates are calculated on the basis of the assumed
contracted capacity of 1,006 MDth/d and its revenue projections assume that
shippers will pay these rates as required by their contracts. A prolonged
economic downturn in the energy industry or a broader economic downturn
affecting the Northeast could impact the ability of some or all of the shippers
to fulfill their obligations under the transportation service contracts. A
failure to pay by any of the shippers would decrease the Partnership's revenues
and cash flows and could have an impact on the Partnership's ability to make
payments on its outstanding senior notes.

Changes in regulation and rates may adversely affect the Partnership's results
of operations

     The Partnership's pipeline system is an interstate natural gas pipeline
subject to regulation as a natural gas company by the Natural Gas Act. As such,
the rates the Partnership can charge its shippers and other terms and conditions
of service are subject to FERC review and the possibility of modification in
rate proceedings. The objective of this rate setting review process is to allow
the Partnership to recover its costs to construct, own, operate and maintain its
pipeline and to afford the pipeline an opportunity to earn a reasonable rate of
return. No assurance can be given that the FERC will not alter or refine its
preferred methodology for establishing pipeline rates and tariff structure in a
way that is detrimental to the Partnership.

A decline in the availability of Western Canadian natural gas may reduce
shippers' willingness to contract for capacity on the Partnership's pipeline

     The Partnership's long-term financial condition is dependent on the
continued availability of Western Canadian natural gas for import into the
United States. If the availability of Western Canadian natural gas were to
decline over the initial term of the Partnership's current transportation
service contracts, existing shippers may not extend their contracts and the
Partnership may be unable to find replacement sources of natural gas for the
pipeline system's capacity. The Partnership cannot give any assurances as to the
availability of additional sources of gas that can interconnect with its
pipeline system.

     Continued sales of Western Canadian natural gas to the United States will
also depend on:

                                       12
<PAGE>

          o    the level of exploration, drilling, reserves and production of
               Western Canada Sedimentary Basin natural gas and the price of
               such natural gas;

          o    the accessibility of Western Canada Sedimentary Basin natural gas
               which may be affected by weather, natural disaster or other
               impediments to access;

          o    the price and quality of natural gas available from alternative
               United States and Canadian sources and the rates to transport
               Canadian natural gas to the United States border; and

          o    the regulatory environments in the United States and Canada,
               including the continued willingness of the governments of both
               countries to permit the import to the United States of natural
               gas from Canada on a commercially acceptable basis.

Failure of the pipeline system's operations may result in liabilities for the
Partnership and reduce its revenues or impair its ability to meet its
obligations under its senior notes

     There are risks associated with the operation of a complex pipeline system,
such as operational hazards and unforeseen interruptions caused by events beyond
the Partnership's control. These include adverse weather conditions, accidents,
breakdown or failure of equipment or processes, performance of the facilities
below expected levels of capacity and efficiency and catastrophic events such as
explosions, fires, earthquakes, floods, landslides or other similar events.
Liabilities incurred and interruptions to the operation of the pipeline caused
by such events could reduce revenues generated by the Partnership and increase
the Partnership's expenses and impair the Partnership's ability to meet its
obligations under the terms of its senior notes. Insurance proceeds may not be
adequate to cover all liabilities incurred, lost revenues or increased expenses.

The Partnership may not succeed in its planned expansions

     The Partnership's ability to engage in any expansion project will be
subject to, among other things, approval of its management committee and
numerous business, economic, regulatory, competitive and political uncertainties
beyond the Partnership's control. Therefore, the Partnership cannot guarantee
that any proposed expansion or extension project will be undertaken or, if
undertaken, will be successful.

     The success of any planned expansions, once undertaken, may depend on
several factors, including, among others, the following:

          o    other existing pipelines may provide transportation services to
               the area to which the Partnership is expanding;

          o    any entities, upon obtaining the proper regulatory approvals, may
               construct new competing pipelines or increase the capacity of
               existing competing pipelines;

                                       13
<PAGE>

          o    a competitor's new or upgraded pipeline could offer
               transportation services that are more desirable to shippers
               because of location, facilities or other factors; and

          o    shippers may not be willing to sign long-term contracts for
               service which would make use of a planned expansion.

     The Partnership would also require additional capital to fund any planned
expansions of its pipeline system. If the Partnership fails to generate
sufficient funds in the future, it may have to delay or abandon its expansion
plans, in which case it will lose the ability to capitalize expenditures on such
abandoned expansions. Also, a proposed expansion may cost more than planned to
complete and such excess costs may not be recoverable.

The Partnership is subject to laws relating to the protection of the environment
that could involve substantial compliance costs and liabilities

     The Partnership's operations are subject to federal, state and local laws
and regulations relating to the protection of the environment. Risks of
substantial costs and liabilities are inherent in pipeline operations and the
Partnership cannot guarantee that significant costs and liabilities will not be
incurred under applicable environmental and safety laws and regulations,
including those relating to claims for damages to property and persons resulting
from the Partnership's pipeline system operations.

     Moreover, it is possible that increasingly stringent changes to federal,
state or local environmental laws and regulations, and enforcement policies
thereunder, could result in increased costs and liabilities to the Partnership.
The Partnership is unable to predict the effect that any future changes in
environmental laws and regulations will have on its future earnings and it
cannot guarantee that environmental costs incurred by it will be recoverable
under its FERC-approved tariff.

ITEM 2.  PROPERTIES

     The Partnership's principal executive office is located in Shelton,
Connecticut in approximately 33,422 square feet of leased office space under a
lease agreement, 4,322 square feet of which expires on June 30, 2003, and the
remaining 29,100 square feet of which expires on April 30, 2011. The Partnership
also leases approximately 14,000 square feet of warehouse and office space in
Oxford, Connecticut under a lease agreement that expires on March 31, 2004. The
Partnership believes that its facilities are adequate for the Partnership's
current operations and that additional leased space can be obtained if needed.

     The Partnership holds the right, title and interest to and in its pipeline
system. With respect to real property, the pipeline system falls into two
categories: (i) parcels which the Partnership owns, such as compressor station
and meter station sites; and (ii) parcels in which the Partnership has a
leasehold interest, easement or right-of-way from landowners permitting the use
of land for the construction and operation of the pipeline system. The
Partnership obtained the right to construct and operate its pipeline system
across certain property through negotiations and through the exercise of the
power of eminent domain, where necessary. The Partnership

                                       14
<PAGE>

continues to have the power of eminent domain in each of the states in which it
operates its pipeline system. The Partnership leases a right-of-way easement on
Long Island, New York from the Long Island Lighting Company, the predecessor to
KeySpan Energy Corporation, the parent of LILCO Energy Systems, Inc., a general
partner of the Partnership, which expires in 2030. The Partnership believes that
it has satisfactory interests in all of the properties making up its pipeline
system.

ITEM 3.  LEGAL PROCEEDINGS

     The Partnership is a party to various legal actions incident to its
business. However, the Partnership believes that the outcome of these
proceedings will not have a material adverse effect on the Partnership's
financial condition or results of operations.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     The Partnership has not submitted any matters to the vote of its security
holders.

                                    PART II.

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
         MATTERS

     The Partnership does not have any publicly-traded common equity.

ITEM 6.  SELECTED FINANCIAL DATA


     The following selected financial data should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and with the Partnership's financial statements, including the notes
thereto, appearing elsewhere in this annual report. The income statement,
balance sheet and cash flow data for the years ended December 31, 2001, 2000,
1999, 1998 and 1997 have been derived from the Partnership's financial
statements, which have been audited by PricewaterhouseCoopers LLP, independent
public accountants.

<TABLE>
<CAPTION>

                                            Year ended December 31,
                                 -----------------------------------------------
                                    2001     2000     1999       1998      1997
                                 -----------------------------------------------
                                     (In thousands of dollars, except ratios)
<S>                              <C>      <C>      <C>         <C>      <C>
Income Statement Data:
Net operating revenues...........$128,270 $127,234 $123,919(1) $140,371 $153,652
Operating expenses:
  Operations.....................  22,108   21,119   21,534      21,703   23,988
  Depreciation and amortization..  23,847   23,609   21,976      29,795   32,094
  Taxes other than income taxes..  10,953   11,156   11,449      10,390   10,266
                                  ------- -------- ---------   -------- --------
    Total operating expenses.....  56,908   55,884   54,959      61,888   66,348
Operating income.................  71,362   71,350   68,960      78,483   87,304
  Other income and (expenses)....   1,829    1,824    1,419       6,758(2) 4,180
                                  -------  -------  -------    --------  -------
Income before interest charges
  and taxes......................  73,191   73,174   70,379      85,241   91,484
  Net interest expense...........  28,067   31,139   30,621      32,476   34,990
                                  -------  -------  -------    --------  -------

                                       15
<PAGE>


Income before taxes.............   45,124   42,035   39,758     52,765    56,494
  Provisions for taxes(3).......   18,275   17,083   15,580     20,788    22,408
                                 --------   ------   ------  ---------  --------
Net income...................... $ 26,849 $ 24,952 $ 24,178   $ 31,977  $ 34,086
                                 ========  =======  =======   ========  ========
Cash Flow Data:

Net cash from operating
  activities.................... $ 77,265 $ 57,181 $ 57,961   $ 83,899  $ 87,116
Capital expenditures............   36,340    8,268    7,718     14,172    14,719

Balance Sheet Data
 (at End of Period):
Net property, plant and
 equipment...................... $533,219 $520,172 $534,806   $548,832  $563,766
Total assets....................  591,745  584,368  594,851    606,870   624,505
Long-term debt, including
 current maturities.............  366,666  388,889  336,664    365,388   394,111
Partners' capital............... $190,764 $169,423 $227,388   $212,630  $199,865
---------------------------
</TABLE>

(1)  Total revenues decreased in 1999 compared to 1998 due to the implementation
     of a rate reduction.

(2)  Includes settlement income for releasing a shipper from its remaining
     long-term firm reserved transportation service contract.

(3)  The payment of income taxes is the responsibility of partners of the
     Partnership. The Partnership's approved rates, however, include an
     allowance for taxes (calculated as if it was a corporation) and the FERC
     requires the Partnership to record such taxes in its partnership records to
     reflect the taxes payable by its partners as a result of the Partnership's
     operations. These taxes are recorded without regard to whether each partner
     can utilize its share of the Partnership's tax deductions. The
     Partnership's rate base, for rate-making purposes, is reduced by the amount
     equivalent to accumulated deferred income taxes in calculating the required
     return.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

Overview

     The Partnership was formed for the purpose of constructing, owning and
operating a 375-mile interstate natural gas transmission pipeline from the
Canada-United States border near Waddington, New York to South Commack, Long
Island, New York. The Partnership provides service to local gas distribution
companies, electric utilities and electric power generators, as well as
marketers and other end-users, directly or indirectly, by connecting with
pipelines and exchanges throughout the northeastern United States. The
Partnership is exclusively a transporter of natural gas in interstate commerce
and operates under authority granted by the FERC. The Partnership commenced full
operations in 1992, creating a link between markets in the states of
Connecticut, Massachusetts, New Hampshire, New Jersey, New York and Rhode
Island, and western Canada natural gas supplies. The Partnership's pipeline
system connects with four interstate pipelines and the pipeline system of
TransCanada PipeLines Limited at the Canada-United States border near
Waddington, New York.

     The Partnership currently has in place several transportation contracts
with Enron Corporation. One is a demand release from a firm shipper whereby
Enron assumed all of that shipper's capacity under its firm contract. The
agreement between the releasing shipper and Enron provides that the releasing
shipper shall remain liable to the Partnership for the full

                                       16
<PAGE>

amount of the demand charge for any month in which Enron fails to pay the
replacement demand charge. In addition, the general terms and conditions of the
Partnership's tariff provide that unless the Partnership otherwise agrees in
writing (which it has not, in this case), a releasing shipper shall remain
liable for the demand charge, any other fixed charges associated with the
released capacity and any late charges resulting from a replacement shipper's
failure to pay the replacement demand charge.

     The Partnership also has several smaller contracts in place with Enron. A
provision for doubtful accounts receivable of approximately $60,000,
representing the full amount outstanding under these contracts for November 2001
and December 2001, was recorded on the Partnership's books in December 2001.

Results of Operations

     The components of operating revenues and volumes transported for the past
three years are provided in the following table:

<TABLE>
<CAPTION>

                                                           Year ended
                                                          December 31,
 Revenues and Volumes Delivered                 ----------------------------
                                                 2001       2000       1999
                                                -----       ----       -----
<S>                                             <C>        <C>        <C>
 Revenues (dollars in millions)
    Long-term firm reserved service             $119.1     $116.3     $116.6
    Short-term firm (1)                            5.5        4.7        2.2
    Interruptible/other (1)                        3.7        6.2        5.1
                                                ------     ------     ------
             Total revenues                     $128.3     $127.2     $123.9

 Volumes Transported (millions of dekatherms)
    Long-term firm reserved service              281.8      292.1     290.6
    Short-term firm (1)                           15.7       25.3      21.6
    Interruptible/other (1)                       20.6       30.7      32.7
                                                ------     ------     -----
             Total volumes transported           318.1      348.1     344.9
</TABLE>

-------------------

(1)  Short-term represents firm service contracts of less than one year; other
     revenue includes deferred asset surcharges, park and loan service revenue
     and marketing fees.

Revenues and Expenses

     Revenues. The Partnership receives revenues under long-term firm reserved
transportation service contracts with shippers in accordance with service rates
approved by the FERC. The Partnership's revenues are primarily derived from
long-term firm reserved transportation contracts and, as such, are not directly
affected by fluctuations in volumes. The Partnership also has interruptible
transportation service revenues, which, although small relative to overall
revenues, are at the margin and thus can have a significant impact on its net
income. Such revenues include short-term firm reserved transportation service
contracts of less than one-year terms as well as standard interruptible
transportation service contracts. While it is common for pipelines to have some
form of required revenue sharing of their interruptible transportation

                                       17
<PAGE>

service revenues with long-term firm reserved service shippers, the Partnership
does not. However, the Partnership cannot assure that this will be the case in
the future.

     During the latter part of 1999, the Partnership held negotiations with its
shippers, which led to the settlement of certain remaining issues from previous
rate cases between the Partnership and its shippers. The settlement received
FERC approval on February 10, 2000. The settlement provides for a schedule of
rate reductions through the year 2003, generally precludes additional rate cases
during this period initiated by the Partnership or any shipper that was a
settling party, and resolves all rate matters outstanding from the Partnership's
previous two rate cases. Consequently, the Partnership's maximum demand rate
decreased by $0.00973/Dth effective January 1, 2001; by $0.02433 effective
January 1, 2002; and will decrease by $0.01460/Dth effective January 3, 2003,
for a total cumulative reduction of $0.04866/Dth. The settlement had no impact
on 2000 income, had a negative revenue impact of $2.4 million in 2001, and is
expected to have a negative revenue impact of $6.0 million in 2002 and $3.6
million in 2003, based upon long-term firm reserved transportation contracts in
effect as of December 31, 2001.

     Despite the 2001 rate decrease of $0.0096/Dth, long-term firm revenues for
2001 increased $2.8 million, from $116.3 million to $119.1 million, largely as a
result of the addition of a power plant to the Partnership's system in November
2000, as well as additional winter firm contracts in place since December 2000.
Short-term firm revenues increased $0.8 million, from $4.7 million in 2000 to
$5.5 million in 2001, despite a decrease in volumes transported, primarily due
to higher peak period pricing in 2001. Interruptible/other revenues decreased
$2.5 million, from $6.2 million in 2000 to $3.7 million in 2001, due to warmer
temperatures and competitive alternative fuel pricing, as evidenced by the
decrease in volumes in 2001 as compared to 2000.

     Total revenues for 2000 were $127.2 million, an increase of $3.3 million
over 1999 revenues. This increase resulted primarily from interruptible and
short-term firm transportation services, which experienced increased volumes and
favorable market prices.

     Operating and Maintenance Expense. Operation and maintenance expenses
include operating, maintenance and administrative expenses for the Partnership's
corporate office in Shelton, Connecticut and the field support for the mainline,
metering and compression facilities. Operation and maintenance expenses
increased 4.7%, from $21.1 million in 2000 to $22.1 million in 2001, primarily
due to increased payroll and benefits expense, partially offset by a reduction
in outside services employed. In January 2001, the Partnership assumed
responsibility for the operating and maintenance activities related to its
pipeline system, which it had previously contracted to a third-party. This
change contributed to the increase in payroll and benefits expense and the
decrease in the cost of outside services employed.

     Operation and maintenance expense for 2000 decreased almost 2% from 1999 to
$21.1 million in 2000 as a result of efficiency gains and cost control measures
throughout the Partnership's operations.

     Other Income and Expenses. Other income includes certain investment income
and the net of income and expense adjustments not recognized elsewhere. Interest
income decreased approximately $0.8 million in 2001 compared to 2000 primarily
due to a decrease in the interest rate realized from investments as well as
lower average cash balances during 2001. Interest

                                       18
<PAGE>

income increased $0.6 million in 2000 compared to 1999. The increase was
primarily due to higher average cash balances and higher interest rates realized
on cash investments in 2000.

     Interest Expense. Interest expense decreased $2.5 million in 2001 compared
to 2000, primarily due to a result of a lower average long-term debt balance due
to scheduled debt repayments and lower interest rates on floating rate debt in
the second half of 2001. This decrease was partially offset by an increase of
$1.0 million of interest expense in the first five months of 2001, reflecting an
increase in average debt balance due to the long-term debt refinancing, which
closed May 30, 2000.

     Interest expense for 2000 also reflected the impact of the long-term
refinancing which closed May 30, 2000. While the effective interest rate on
long-term debt decreased, overall interest expense increased since the average
long-term debt balance increased from $353.4 million to $376.6 million. Interest
expense for the first five months of 2000 decreased $1.1 million due to
scheduled debt repayments. Interest expense for the last seven months of 2000
increased $1.8 million as a result of the long-term debt refinancing activities.

     Income Taxes. Provision for taxes increased $1.2 million in 2001 compared
to 2000, and increased $1.5 million in 2000 compared to 1999. The 2001 increase
was primarily due to an increase in taxable income. The 2000 increase was due to
higher taxable income and a change implemented by New York State from a gross
receipts tax based on revenue to an income-based franchise tax. Income taxes are
the responsibility of the Partners (refer to Note 8 to the Financial
Statements).

Liquidity and Capital Resources

     The Partnership's primary source of financing has been cash flow from
operations, its May 2000 offering of $200 million of senior notes and bank
borrowings. The Partnership's ongoing operations will require the availability
of funds to service debt, fund working capital, and make capital expenditures on
the Partnership's existing facilities and expansion projects.

     Cash flow (defined as net income adjusted for non-cash items such as
depreciation and deferred income taxes) represents the cash generated from
operations available for capital expenditures, partner distributions and other
operational needs. Net cash provided by operating activities increased to $77.3
million in 2001 compared to $57.2 million in 2000, due to a change in the timing
of interest payments and amounts capitalized during the refinancing of the
Partnership's debt which closed May 30, 2000, as well as increased accounts
payable due to the Eastchester Project and increased net income. Net cash
provided by operating activities remained relatively constant in 2000 compared
to 1999. Net cash flow used for financing activities decreased from 2000 to 2001
due primarily to the transactions surrounding the refinancing of debt in May
2000.

     Capital expenditures for 2001 were $36.3 million, compared to $8.3 million
in 2000, reflecting primarily the increased activity related to the Eastchester
Project during the year. In addition, there were additional expenditures related
to general plant purchases and other miscellaneous projects. Capital
expenditures in 2000 consisted of preliminary engineering expenditures relating
to the Eastchester Project, as well as general plant purchases and other

                                       19
<PAGE>

minor projects. In 1999, capital expenditures of $7.7 million were restricted to
some post-completion costs for the Athens compressor station, preliminary
engineering work for the Eastchester Project and various general plant
purchases.

     Total capital expenditures for 2002 are estimated to be approximately
$148.7 million, including approximately $134.4 million for the Eastchester
Project. The remaining capital expenditures planned for 2002 are primarily for
the purchase of land for a compressor site, a meter station and interconnect,
several compressor stations to accommodate future growth and various general
plant purchases. The Partnership currently anticipates funding its 2002 capital
expenditures by using internal sources and through the issuance of additional
indebtedness and/or capital contributions by its partners in accordance with the
partnership agreement.

     The Partnership has a $10 million revolving line of credit to support
working capital requirements that was established in May 2000. Funds may be
borrowed on a short-term basis at variable rates. As of December 31, 2001 and
December 31, 2000 there were no borrowings outstanding on this $10 million
facility.

     At December 31, 2001, the Partnership had no off-balance sheet
transactions, arrangements, or other relationships with unconsolidated entities
or persons that would adversely affect liquidity, availability of capital
resources, financial position, or results of operations.

     Total cash distributions to partners of $22.0 million, $100.0 million and
$25.0 million were made during 2001, 2000 and 1999, respectively. The larger
distribution in 2000 is a result of the May 2000 long-term debt refinancing.

Contractual Obligations

     The Partnership is committed to making payments in the future on two types
of contracts: long-term debt and leases. The Partnership has no off-balance
sheet debt or other such unrecorded obligations and has not guaranteed the debt
of any other party. Below is a schedule of the future payments the Partnership
was obligated to make based on agreements in place as of December 31, 2001.

                      Total    2002   2003 to 2004    2005 to 2006   Thereafter
                      -----    ----   ------------    ------------   ----------
                                      (in thousands of dollars)
Long-Term Debt      $366,700 $22,200    $44,400         $44,400       255,700
Operating Leases      13,800   1,100      2,200           2,000         8,600
                    -------- -------    -------         -------       -------

Total Contractual   $380,500 $33,300    $46,600         $46,600      $264,300
                    -------- -------    -------         -------      --------
Obligations

Critical Accounting Policies

     The Partnership's management has evaluated the accounting policies applied
in the preparation of the accompanying financial statements and believes that
the policies currently applied are reasonable and appropriate.

                                       20

<PAGE>

     FAS 71. The Partnership's management believes that the most critical
accounting policy applied in the preparation of the financial statements relates
to the application of FAS 71 "Accounting for the Effects of Certain Types of
Regulation," which establishes the recognition of deferred assets and/or
liabilities if it is determined that it is probable that certain costs will be
recovered from or refunded to customers through the rate-making process.

     The impact of FAS 71 in the Partnership's financial statements can be found
in non-current assets, in both "Other assets and deferred charges" as a part of
the "Construction Work in Progress." These balances include costs that are
currently being recovered or expected to be recovered through the rate-making
process and with the approval of the FERC.

     Historically, the Partnership has not had significant write-offs related to
the deferral of incurred costs and the Partnership's management has taken a
conservative and reasonable approach in order to determine the costs to be
deferred and the likelihood of the realization of these deferred balances. The
Partnership believes that the amounts recorded as deferred assets in the
financial statements related to FAS 71 present its best estimate and judgment in
terms of recovery of the incurred costs.

     Revenue subject to refund. The Partnership is subject to regulation by the
FERC. FERC regulations govern the process by which the rates that the
Partnership charges its shippers for the transportation of natural gas are
determined. Key determinants in the rate-making process are (i) volume
throughput assumption, (ii) costs of providing service, including depreciation
expense and (iii) allowed rate of return, including the equity component of a
pipeline's capital structure and related income taxes.

     As a result of the rate-making process, certain revenues collected by the
Partnership may be subject to possible refunds upon final orders in pending rate
proceedings with the FERC. The Partnership records estimates of refund rate
liabilities considering its and other third-party regulatory proceedings, advice
of counsel and estimated total exposure, as discounted and risk-weighted, as
well as collection and other risks. The Partnership does not have any rate
proceedings pending before the FERC. Therefore, at December 31, 2001, the
Partnership had no potential rate refunds accrued.

     Contingent liabilities. The Partnership establishes reserves for estimated
loss contingencies when it is management's assessment that a loss is probable
and the amount of the loss can be reasonably estimated. Revisions to contingent
liabilities are reflected in income in the period in which different facts or
information become known or circumstances change that affect the previous
assumptions with respect to the likelihood or amount of loss. Reserves for
contingent liabilities are based upon management's assumptions and estimates,
advice of legal counsel or other third parties regarding the probable outcome of
the matter. Should the outcome differ from the assumptions and estimates,
revisions to the estimated reserves for contingent liabilities would be
required. Reference is made to Note 7 to the financial statements for
information about regulatory, judicial and business developments that cause
operating and financial uncertainties.

                                       21

<PAGE>

New Accounting Standards

     Effective January 1, 2001 the Partnership adopted Statement of Financial
Accounting Standards ("SFAS") No. 133 as issued by the Financial Accounting
Standards Board, or FASB, "Accounting or Derivative Instruments and Hedging
Activities", as amended ("SFAS 133"). Under SFAS 133, the Partnership records
the fair value of derivatives held as assets or liabilities. The changes in net
value of the effective portion of derivatives qualifying as cash flow hedges are
recorded in other comprehensive income, a component of partners' equity.

     In June 2001, the FASB issued SFAS No. 141, "Business Combinations" ("SFAS
141"), and No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS
141 is effective for business combinations completed after June 30, 2001 and
SFAS 142 is effective for fiscal year 2002. Implementation of these standards is
not expected to have a material impact on the Partnership's financial position
or results of operations.

     In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS 143"). SFAS 143 provides the accounting
requirements for retirement obligations associated with tangible long-lived
assets. SFAS 143 is effective for fiscal years beginning after June 15, 2002,
and early adoption is permitted. Implementation of this standard is not expected
to have a material impact on the Partnership's financial position or results of
operations.

     In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 supersedes
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" ("SFAS 121") and the accounting and
reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting
the Results of Operations - Reporting the Effects of Disposal of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions,"
related to the disposal of a segment of a business. SFAS 144 establishes a
single accounting model for long-lived assets to be disposed of by sale and
resolves significant implementation issues related to SFAS 121. SFAS 144 is
effective for fiscal years beginning after December 15, 2001. Implementation of
this standard is not expected to have a material impact on the Partnership's
financial position or results of operations.

Other

     The Partnership's transmission activities are subject to regulation by the
FERC under the Natural Gas Act and under the Natural Gas Policy Act of 1978
because the Partnership owns and operates an interstate natural gas pipeline
system that provides interstate transmission services. As a result, the
Partnership's rates and charges for natural gas transportation, the terms and
conditions of the services it offers, the extension, enlargement or abandonment
of its jurisdictional facilities, and its accounting, among other things, are
subject to such regulation.

     The Partnership is also subject to the National Environmental Policy Act
and other federal and state legislation regulating the environmental aspects of
its business. The Partnership believes that it is in substantial compliance with
existing environmental requirements. The Partnership believes that, if
expenditures were required in the future to meet applicable standards

                                       22

<PAGE>

and regulations, the FERC would grant requisite rate relief so that, for the
most part, such expenditures and a return thereon would be permitted to be
recovered. Based on current information, the Partnership believes that
compliance with applicable environmental requirements is not likely to have a
material effect upon its earnings or competitive position.

     The majority of the Partnership's plant and equipment and inventory is
subject to ratemaking treatment, and under current FERC practices, recovery of
increased costs for replacing facilities due to inflation is limited to
prudently incurred, historical costs as established in the prior rate
proceeding. Under current FERC practice, amounts in excess of historical cost
are not recoverable between rate proceedings, leading to a delay between
incurrence of costs and their recovery. However, the Partnership believes that
in future rate proceedings it will be allowed to recover and earn a return based
on increased actual costs incurred when existing facilities are replaced and new
facilities are placed in service. Cost-based regulation, along with competition
and other market factors, limit the Partnership's ability to take inflation into
account in pricing services and products.


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Market risk represents the risk of changes in value of a financial
instrument, derivative or non-derivative, caused by fluctuations in interest
rates and prices. The following discussion of the Partnership's risk management
activities includes forward-looking statements that involve risks and
uncertainties. Actual results could differ materially from those contemplated in
the forward-looking statements. The Partnership handles market risks in
accordance with established policies, which may include various derivative
transactions.

     The financial instruments held or issued by the Partnership are for
purposes other than trading or speculation. The Partnership is exposed to risk
resulting from interest rate changes on its variable-rate debt. As of December
31, 2001, the Partnership had $172.2 million of variable-rate debt outstanding.
Holding other variables constant, including levels of indebtedness, a one-
percentage point increase in interest rates would impact pre-tax earnings by
approximately $1.3 million. The Partnership uses interest rate swap agreements
to manage the risk of increases in certain variable rate issues. It records
amounts paid and received under those agreements as adjustments to the interest
expense of the specific debt issues. The Partnership believes that there is no
material market risk associated with these agreements. (See Note 3 to the
financial statements.)

     The Partnership's pension plan assets are made up of equity and fixed
income investments. Fluctuations in those markets could cause the Partnership to
recognize increased or decreased pension income or expense.



ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Financial statements are contained on pages F-1 through F-21 of this
report.

                                       23
<PAGE>

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

     None.

                                   PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP

Executive Officers

     The following table sets forth the names, ages and positions of the
executive officers of IPOC.

       Name                 Age                  Position
       ----                 ---                  --------
Craig R. Frew               51   President
Paul Bailey                 55   Vice President and Chief Financial Officer
Jeffrey A. Bruner           43   Vice President, General Counsel and Secretary
Herbert A. Rakebrand III    45   Vice President, Marketing and Transportation
David J. Warman             44   Vice President, Engineering and Operations

     Craig R. Frew is President of IPOC. Mr. Frew has 30 years of experience in
the natural gas industry. Mr. Frew joined TransCanada PipeLines Limited in 1976
and transferred to IPOC in 1994 while TransCanada PipeLines Limited was the
operator of the Partnership's pipeline system. With TransCanada PipeLines
Limited, Mr. Frew held a number of senior management positions including the
position of President of its wholly owned subsidiary, Western Gas Marketing
Limited, from 1989 to 1993. Mr. Frew currently serves on the board of directors
of the Interstate Natural Gas Association and is Chairman and member of the
board of directors of the New England Gas Association.

     Paul Bailey is Vice President and Chief Financial Officer of IPOC. Mr.
Bailey has 20 years of experience in the natural gas industry and an additional
14 years in the electric industry. Mr. Bailey joined TransCanada PipeLines
Limited in 1982 and transferred to IPOC in 1992 while TransCanada PipeLines
Limited was the operator of the Partnership's pipeline system. With TransCanada
PipeLines Limited, Mr. Bailey held a variety of senior management positions in
the accounting and finance areas of the company. From 1968 to 1982 Mr. Bailey
was employed by Ontario Hydro and held a number of positions in the accounting
and financial planning departments.

     Jeffrey A. Bruner is Vice President, General Counsel and Secretary of IPOC.
Mr. Bruner joined IPOC in 1992. Prior to joining IPOC he was with Transco Energy
Company for eight years where he held various positions in the legal department,
including the position of General Attorney in charge of the legal department for
Transcontinental Gas Pipe Line Corporation, an interstate pipeline affiliate of
Transco Energy.

                                       24
<PAGE>

     Herbert A. Rakebrand III is Vice President of Marketing and Transportation
of IPOC. Mr. Rakebrand has 22 years of experience in the natural gas industry.
Mr. Rakebrand assisted in establishing IPOC's transportation department, having
joined IPOC in 1991, prior to the pipeline being placed in service. From 1980 to
1991, Mr. Rakebrand was employed by the Long Island Lighting Company where he
held various positions in the gas engineering and gas supply departments.

     David J. Warman is Vice President of Engineering and Operations of IPOC.
Mr. Warman joined TransCanada PipeLines Limited in 1982 and transferred to IPOC
in 1990 while TransCanada PipeLines Limited managed the construction of the
Partnership's pipeline system. With TransCanada PipeLines Limited, Mr. Warman
held a number of positions in the engineering area, in particular pipeline
design, materials engineering, pipeline construction and project management.

Management Committee Composition

     The representatives on the Partnership's management committee are employed
at affiliates of partners of the Partnership. The following table sets forth the
names of the representatives on the Partnership's management committee, the
names of the affiliates of the partners at which they are employed and the names
of relevant partners.

                              Affiliate at
Name                  Age     Which Employed            Partner Represented
----                  ---     --------------            -------------------

Paul D. Koonce        42      Dominion Resources, Inc.  Dominion Iroquois, Inc.

Larry S. McGaughy     54      Connecticut Energy        TEN Transmission
                              Corporation               Company


Charles A. Daverio    52      KeySpan Energy            NorthEast Transmission
                              Corporation               Company, LILCO Energy
                                                        Systems, Inc.

Joseph P. Shields     44      New Jersey Natural        NJNR Pipeline Company
                              Gas Company

Peter Lund            43      PG&E National Energy      JMC-Iroquois, Inc.
                              Group                     Iroquois Pipeline
                                                        Investment, LLC

Paul MacGregor        45      TransCanada Pipelines     TransCanada Iroquois
                              Ltd.                      Ltd./TCPL Northeast Ltd.


     Paul D. Koonce joined Dominion Energy, Inc. as Senior Vice President in
January 1999. He is responsible for Dominion Energy's commercial activities.
From 1982 through 1992, he worked for East Tennessee Natural Gas, Entrade
Corporation, Texas Gas Transmission and Transcontinental Gas Pipeline
Corporation. In 1992, he joined Sonat Marketing Company as Vice President where
he was promoted to Senior Vice President of Sonat Energy Services and

                                       25
<PAGE>

named Executive Vice President of Sonat Power Systems. Mr. Koonce has served on
the management committee of the Partnership since the beginning of 2000.

     Larry S. McGaughy is the President of three non-utility affiliates at
Connecticut Energy Corporation (CNE Energy Services Group, Inc., CNE Development
Corporation and CNE Venture-Tech, Inc.). From 1990 to 1995, he served as a Vice
President of Southern Connecticut Gas Company in the various functional areas of
Marketing, Corporate Planning, Corporate Engineering and Gas Control. Prior to
joining Southern, Mr. McGaughy served as Director of Marketing and Energy
Services and as Director of Regulatory Control and Budgets at Tampa Electric
Company over a period of eleven years. Mr. McGaughy has served as a member of
the management committee of the Partnership since November 2000.

     Charles A. Daverio has served as Vice President of KeySpan Energy Trading
Services, LLC since December 1996. He joined KeySpan Energy Corporation in 1976
as an associate engineer. He held various supervisory and managerial positions
in the Nuclear Engineering Department, Gas Supply and Planning, and Gas
Operators from 1979 through 1996. Mr. Daverio has served as the representative
of KeySpan Energy Corporation on the management committee of the Partnership
since 1991.

     Joseph P. Shields is a Senior Vice President of New Jersey Natural Gas
Company, a subsidiary of New Jersey Resources Corporation. Since 1983, he has
served as Manager, Director and Vice President of Gas Supply in New Jersey
Natural Gas Company. Prior to joining New Jersey Natural Gas Company, he was
employed by the State of New Jersey Board of Public Utilities. He joined the
management committee of the Partnership as of August 16, 2000.

     Peter Lund has been Vice President-Pipeline Marketing and Development of
PG&E National Energy Group, since March 2000. Prior to his current role, Mr.
Lund served as Vice President - Transportation and Storage Operations of PG&E
Gas Transmission. Before joining PG&E Gas Transmission Northwest in 1988, Mr.
Lund worked as a resource analyst for Pacific Gas and Electric Company and as a
mineral exploration geologist for various firms. In addition, Mr. Lund is a
board member of the Pacific Coast Gas Association, the Private Industry Sponsors
of the Canadian Energy Research Institute and a board member and former
president of the Northwest Gas Association. Mr. Lund has been a member of the
management committee of the Partnership since 1999.

     Paul F. MacGregor has served as Vice President-East Business Development
for TransCanada Pipelines Ltd. since January 2001. Mr. MacGregor is responsible
for the business development activities of TransCanada's non-regulated pipeline
services and investments. In addition, he oversees TransCanada's ownership
interests in several of its Canadian and U.S. pipeline investments. Mr.
MacGregor joined TransCanada in 1981 and since then he has held various
positions including in Facilities Planning and Vice President, North American
Pipeline Investments for TransCanada's energy transmission business unit. Mr.
MacGregor has been a member of the management committee of the Partnership since
1999.

                                       26
<PAGE>

ITEM 11. EXECUTIVE COMPENSATION

     Summary Compensation Table. The following summary compensation table sets
forth information regarding compensation for fiscal years 2001, 2000 and 1999
paid to the President and each of the four other most highly compensated
executive officers of IPOC. All compensation to the executive officers is paid
by IPOC and reimbursed by the Partnership.

<TABLE>
<S>     <C>                         <C>            <C>              <C>              <C>                  <C>
                                                                                 Other Annual         All Other
  Name and                                        Salary           Bonus         Compensation        Compensation
  Principal Position                 Year        ($) (1)            ($)             ($)(3)             ($) (4)
  ------------------               --------      -------            ---             ------             -------

  Craig R. Frew                      2001     $297,231.80      $160,000.00                ---         $137,347.00
       President                     2000      262,058.23       125,000.00          65,598.34           10,500.00
                                     1999      256,913.55       111,150.00                ---           10,000.00

  Paul Bailey                        2001     $186,200.04       $84,000.00                ---          $64,181.70
       Vice President and Chief      2000      184,293.98        55,000.00          72,429.11            9,448.94
       Financial Officer             1999      177,177.00        46,000.00                ---            8,695.75

  Jeffrey A. Bruner                  2001     $150,000.24       $60,000.00                ---          $37,180.77
       Vice President, General       2000      148,580.38        44,000.00                ---            7,428.98
       Counsel and Secretary         1999      142,506.00        38,500.00                ---            7,215.26

  Herbert A. Rakebrand III           2001     $177,107.86       $65,000.00                ---          $48,668.00
       Vice President, Marketing     2000      164,588.58     73,000.00(2)                ---            8,089.90
       and Transportation            1999      147,502.00        43,500.00                ---            7,340.06

  David J. Warman                    2001     $131,257.96       $54,000.00                ---          $36,162.50
       Vice President,               2000      126,011.79        37,000.00                ---            6,190.08
       Engineering                   1999      115,011.00        29,000.00                ---            5,840.55
       and Operations

-----------------------------
<FN>

(1)  Amounts reported for the 1999, 2000 and 2001 fiscal years, respectively
     include salary paid in lieu of vacation for the following: Mr. Frew --
     $9,692.55, $4,754.25 and $3,492.70; Mr. Rakebrand -- $2,500, $2,788.50 and
     $4,307.70; and Mr. Warman -- $0, $2,211.75, $1,657.84, respectively.

(2)  Mr. Rakebrand's 2000 Bonus Amount was erroneously reported as $69,000 in
     the Form 10-K filed for fiscal year 2000.

(3)  Other Annual Compensation for fiscal year 2000 includes loan forgiveness
     and certain personal benefits, including the following for the 2000 fiscal
     year: Mr. Frew -- $56,193.64 for loan forgiveness; and Mr. Bailey --
     $60,560.18 for loan forgiveness. Other Annual Compensation below the
     disclosure thresholds has been omitted.

(4)  A portion of the amounts presented in this column represent amounts that
     became vested and payable to the named-executive officers under the IPOC
     long-term incentive plan on December 31, 2001. The general terms of the
     long-term incentive plan are discussed below in a separate section. For
     fiscal year 2001, the named executive officers became entitled to receive
     the following amounts under the long-term incentive plan: Mr. Frew became
     entitled receive $126,847.00; Mr. Bailey became entitled to receive

                                       27
<PAGE>

     $54,967.00; Mr. Bruner became entitled to receive $29,598.00; Mr. Rakebrand
     became entitled to receive $40,168.00; and Mr. Warman became entitled to
     receive $29,598.00. The other portion of the amounts presented in this
     column represent the matching contributions made by IPOC under the Iroquois
     Pipeline Operating Company Savings Plan (the "401(k) Plan") and the IPOC
     Supplemental 401(k) Savings Plan (the "Supplemental Plan"). Under the
     401(k) Plan, which is generally available to all employees, IPOC currently
     matches a participant's tax-deferred contributions by an amount equal to
     100% of such contribution for each year, up to 5% of the participant's
     annual compensation. Under the Supplemental Plan, IPOC currently matches
     the tax-deferred contributions by a select group of management or highly
     compensated employees in an amount equal to 100% of such contribution for
     each year, up to 5% of the participant's annual compensation, less any
     matching contributions allocated to the participant's account under the
     401(k) Plan. The following contributions were made during the 1999, 2000
     and 2001 fiscal years, respectively under the 401(k) Plan: Mr. Frew
     received $8,000, $8,500 and $8,500; Mr. Bailey received $8,000, $8,500 and
     $8,500.00; Mr. Bruner received $7,215.26, $7,428.98 and $7,582.77; Mr.
     Rakebrand received $7,340.06, $8,089.90 and $8,500; and Mr. Warman received
     $5,840.55, $6,190.08 and $6,564.50, respectively. In addition, the
     following amounts were received during the 1999, 2000 and 2001 fiscal
     years, respectively under the Supplemental Plan: Mr. Frew received $2,000
     for each year; and Mr. Bailey received $697.75, $948.94, and $714.70, for
     each year respectively.
</FN>
</TABLE>

Long-Term Incentive Plan Awarded In Last Fiscal Year

     Effective as of January 1, 1999, IPOC adopted a performance share unit
plan, which provides financial incentives to certain key executives. All key
employees of IPOC and its subsidiaries are eligible to participate in the
performance plan. The participants for each year will be selected by the
compensation committee. Participants are awarded "phantom shares" of the
partnership ("Performance Units") which are valued annually based upon our
year-end book value and our average return on rate base equity. The payout value
of the Performance Units is based on the sum of (i) the value of the Performance
Units at the end of a performance period and (ii) the amount of dividends per
Performance Unit during the period. Payment on the Performance Units is made in
cash within 30 days following completion of our audited financial statements.

     The Performance Units generally vest and become payable over five years,
with 50% of each award vesting at the end of the third year and 25% vesting at
the end of each of the fourth and fifth years. Upon a termination of a
participant's employment with IPOC or its subsidiaries, for any reason other
than death, disability, or retirement, all unvested Performance Units will be
forfeited. Upon a termination due to the participant's death, disability or
retirement, the committee may, in its sole discretion, provide for the vesting
and payment of any unvested Performance Units.

     No new awards of Performance Units were granted to the named executive
officers during fiscal year 2001.

Pension Plans

     IPOC sponsors a qualified non-contributory, cash balance retirement plan
covering substantially all of its employees and an excess retirement plan
covering certain key employees. Under the pension plan, each participant is
given a hypothetical account balance, which is credited with a specified
percentage of a portion of the participant's covered compensation based on his
or her age and service. The excess pension plan is an unfunded pension
arrangement that

                                       28
<PAGE>

provides certain highly compensated employees with the benefit that they would
have been entitled to but for the limitations set forth in the Internal Revenue
Code of 1986, as amended. In addition, under the excess pension plan, the
benefits provided to Messrs. Frew, Bailey and Warman take into account their
years of service with TransCanada Pipelines Limited. The benefits under the
excess pension plan are not subject to the provisions of the Internal Revenue
Code that limit the compensation used to determine benefits and the amount of
annual benefits payable under the qualified pension plan.

     The following table illustrates, for representative annual covered
compensation and years of benefit service classifications, the annual retirement
benefit that would be payable to employees under both the non-contributory cash
balance retirement plan and the excess pension plan if they retired in 2002 at
age 65, based on the straight-life annuity form of benefit payment and not
subject to deduction or offset. In calculating the benefits shown in the
following table, salaries were assumed to remain level and hypothetical account
balances were assumed to grow at 5.5% per year.


                               PENSION PLAN TABLE

<TABLE>
<CAPTION>
                                      Years of Service
-------------------------------------------------------------------------------
   Remuneration      15         20          25           30           35
-------------------------------------------------------------------------------
<S>                <C>         <C>         <C>         <C>          <C>
     150,000       43,234      63,764      91,961      123,412      166,844
     200,000       58,975      87,088     125,650      168,848      228,409
     250,000       74,717     110,412     159,341      214,286      289,975
     300,000       90,458     133,736     193,031      259,722      351,541
     350,000      106,200     157,061     226,721      305,159      413,106
     400,000      121,941     180,385     260,411      350,596      474,673
     450,000      137,683     203,709     294,102      396,033      536,237
     500,000      153,424     227,034     327,791      441,469      597,804
</TABLE>

     The number of years of credited service, as of December 31, 2001, for
Messrs. Frew, Bailey, Bruner, Rakebrand and Warman are 25.50, 19.33, 9.58, 10.33
and 19.42, respectively. These numbers include the credited service with
TransCanada Pipelines Limited pursuant to the excess pension plan.

Supplemental Executive Retirement Agreements

     Mr. Frew is a party to a supplemental executive retirement agreement, dated
July 1, 1997 that provides a guaranteed retirement benefit of 60% of his average
annual compensation, including salary and bonus for the three highest
consecutive calendar years during his employment with IPOC. This amount is
reduced by any retirement benefits that Mr. Frew is entitled to pursuant to the
IPOC pension plan and excess pension plan, certain TransCanada Pipelines pension
plans, the IPOC 401(k) plan and his social security benefits.

     Mr. Bailey is party to a similar supplemental executive retirement
agreement dated July 1, 1997; however, Mr. Bailey's guaranteed retirement
benefit is 40% of his three-year average annual compensation, including salary
and bonus for the three highest consecutive calendar years during his employment
with IPOC.

                                       29
<PAGE>

Compensation of the Management Committee

     The Partnership does not pay any of the representatives on the
Partnership's management committee any compensation for their service on the
management committee.

Compensation Committee Interlocks and Insider Participation

     The executive committee, a sub-committee composed of members of the
management committee, functions as the Partnership's compensation committee by
determining the policies applicable to the manner in which the Partnership's
executives are compensated. The members of the executive committee are Paul
MacGregor, Paul Koonce and Charles Daverio, each of whom served on the committee
during the fiscal year 2001. None of the members of the executive committee has
ever been an officer of the Partnership, or any subsidiary thereof, had any
direct or indirect personal or professional economic dealings with the
Partnership, or any subsidiary thereof, or engaged in any other activity that is
required to be disclosed as an interlock or insider participation matter.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The Partners

     The Partnership is a limited partnership wholly owned by its partners. The
following information summarizes the ownership interest of the partners:

<TABLE>
<S>      <C>                           <C>                            <C>            <C>              <C>
                                                                    General        Limited
                                                                    Partner        Partner      Total Partnership
  Ultimate Parent                Name of Partner                    Interest       Interest         Interest
  ---------------                ---------------                    --------       --------     -----------------
  TransCanada PipeLines          TransCanada Iroquois Ltd.           29.0%            --              29.0%
        Limited                  TCPL Northeast Ltd.                 11.96%           --             11.96%

  KeySpan Energy Corporation     NorthEast Transmission Company      18.07%         1.33%             19.4%

                                 LILCO Energy Systems, Inc.           1.0%            --              1.0%

  Dominion Resources, Inc.       Dominion Iroquois, Inc.             24.72%           --             24.72%

  PG&E Generating Company        JMC-Iroquois, Inc.                  4.57%           .36%             4.93%
                                 Iroquois Pipeline Investment,       0.84%            --              0.84%
                                 LLC

  CTG Resources, Inc.            TEN Transmission Company            4.46%           .41%             4.87%

  New Jersey Resources           NJNR Pipeline Company               3.28%            --              3.28%
      Corporation

</TABLE>

     On January 18, 2000, El Paso Energy Corp. and The Coastal Corporation
("Coastal") announced plans to merge. At the time, Coastal, through its
affiliates, owned a 17.0% interest in

                                       30
<PAGE>

the Partnership. As a condition of the merger, the Federal Trade Commission, or
FTC, ordered Coastal to divest all of its interest in the Partnership. Four of
the remaining partners of the Partnership agreed to purchase Coastal's interest.
On April 27, 2001, the FTC approved the divestiture of Coastal's interests to
affiliates of Dominion Resources, Inc., TransCanada PipeLines Limited, PG&E
Corporation and New Jersey Resources Corporation. The divestiture transaction
closed on May 4, 2001.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Affiliates of each partner of the Partnership transport natural gas on the
Partnership's pipeline system, at rates, terms and conditions contained in its
FERC approved tariff. At December 31, 2001, approximately 49% of natural gas
under long-term firm contract was transported by affiliates of partners. The
Partnership also leases a right-of-way easement which requires annual payments
escalating 5% a year over the 39-year term of the lease on Long Island, New
York, from the Long Island Lighting Company, the predecessor to KeySpan Energy
Corporation, the parent of LILCO Energy Systems, Inc., a general partner of the
Partnership.

                                    PART IV.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

         (a) Exhibits

Index to Exhibits

Exhibit
 Number                                             Description
--------                                            -----------

3.1*      Amended and Restated Limited Partnership Agreement of the Partnership
          dated as of February 28, 1997 among the partners of the Partnership.

3.2*      First Amendment to Amended and Restated Limited Partnership Agreement
          of the Partnership dated as of January 27, 1999 among the partners of
          the Partnership.

4.1*      Indenture dated as of May 30, 2000 between the Partnership and the
          Chase Manhattan Bank, as trustee (the "Trustee") for $200,000,000
          aggregate principal amount of 8.68% senior notes due 2010.

4.2*      First Supplemental Indenture, dated as of May 30, 2000 between the
          Partnership and the Trustee for $200,000,000 aggregate principal
          amount of 8.68% senior notes due 2010.

4.3*      Form of Exchange Note.

                                       31
<PAGE>

4.4*      Exchange and Registration Rights Agreement dated as of May 30, 2000
          among the Partnership and the Initial Purchasers for $200,000,000
          aggregate principal amount of 8.68% senior notes due 2010.

10.1*     Credit Agreement among the Partnership, The Chase Manhattan Bank, as
          administrative agent, Bank of Montreal, as syndication agent and Fleet
          National Bank, as documentation agent, and other financial
          institutions, dated May 30, 2000.

10.2*     Amended and Restated Operating Agreement dated as of February 28, 1997
          between Iroquois Pipeline Operating Company and the Partnership.

10.3*     Agreement Between Iroquois Pipeline Operating Company and Tennessee
          Gas Pipeline Company with respect to operating pipelines of the
          Partnership dated as of March 15, 1991.

10.4*     FERC Gas Tariff, First Revised Volume No. 1 of the Partnership filed
          with the Federal Energy Regulatory Commission.

10.5*     Stipulation and Agreement dated as of December 17, 1999 between the
          Partnership, the Federal Energy Regulatory Commission Staff and all
          active participants in Docket Nos. RP94-72-009, FA92-59-007,
          RP97-126-015, and RP97-126-000 as approved by the Federal Energy
          Regulatory Commission on February 10, 2000.

10.6*     Supplemental Executive Retirement Agreement dated as of July 1, 1997
          between the Partnership and Craig R. Frew.

10.7*     Supplemental Executive Retirement Agreement dated as of July 1, 1997
          between the Partnership and Paul Bailey.

10.8*     Supplementary Pension Plan of Iroquois Pipeline Operating Company
          adopted on December 31, 1998.

10.9*     Performance Share Unit Plan of Iroquois Pipeline Operating Company
          effective as of January 1, 1999.

12.1*     Statements regarding computation of ratios.

21.1*     List of Subsidiaries of the Partnership.

-------------------------
*         Previously filed as an exhibit to the Partnership's Registration
          Statement on Form S-4 (No. 333- 42578)

(b) Reports on Form 8-K

     None.

                                       32
<PAGE>


                                   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.

                         IROQUOIS GAS TRANSMISSION SYSTEM, L.P., as Registrant
                         By:     Iroquois Pipeline Operating Company, its Agent


Date: March 29, 2002         By:     /s/ Paul Bailey
                                  -------------------------------------
                                     Name:  Paul Bailey
                                     Title: Vice President and
                                            Chief Financial Officer


                             By:     /s/ Craig R. Frew
                                  -------------------------------------
                                     Name:  Craig R. Frew
                                     Title: President

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on March 29, 2002.

     Signatures                                   Title
     ----------                                   -----

/s/ Paul Bailey               Vice President and Chief  Financial
------------------------      Officer of Iroquois
Paul Bailey                   Pipeline Operating Company

/s/ Craig R. Frew             President of Iroquois Pipeline Operating Company
------------------------
Craig R. Frew

/s/ Nicholas A. Rinaldi       Controller of Iroquois Pipeline Operating Company
------------------------
Nicholas A. Rinaldi

/s/ Paul F. MacGregor         Representative on the Management Committee
------------------------
Paul F. MacGregor

/s/ Charles A. Daverio        Representative on the Management Committee
------------------------
Charles A. Daverio

/s/ Paul D. Koonce            Representative on the Management Committee
------------------------
Paul D. Koonce

/s/ Larry S. McGaughy         Representative on the Management Committee
------------------------
Larry S. McGaughy

                                       33
<PAGE>

/s/ Joseph P. Shields         Representative on the Management Committee
------------------------
Joseph P. Shields

/s/ Peter G. Lund             Representative on the Management Committee
------------------------
Peter G. Lund
















                                       34
<PAGE>

                                    PART V.

                          INDEX TO FINANCIAL STATEMENTS

                                                                           Page
                                                                           ----

Report of Independent Accountants..........................................F-2

Financial Statements

      Consolidated Statements of Income for the years ended December 31,
          2001, 2000 and 1999..............................................F-3

      Consolidated Balance Sheets as of December 31,
          2001 and 2000....................................................F-4

      Consolidated  Statements of Cash Flows for the years ended
          December 31, 2001,  2000 and 1999................................F-6

      Statements of Changes in Partners'  Equity for the years ended
          December 31, 2001,  2000, 1999 and 1998 .........................F-8

Notes to Financial Statements..............................................F-9



















                                      F-1
<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


To the Partners and Board of Directors of
Iroquois Gas Transmission System, L.P.:

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of cash flows and of changes in partners'
equity present fairly, in all material respects, the financial position of
Iroquois Gas Transmission System L.P. and its subsidiary ("the Company") at
December 31, 2001 and 2000, and the results of their operations and cash flows
for each of the three years in the period ended December 31, 2001 in conformity
with accounting principles generally accepted in the United States of America.
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 of these statements in accordance with
auditing principles generally accepted in the United States of America, which
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.

/s/ PricewaterhouseCoopers LLP

February 6, 2002



                                      F-2

<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
                        CONSOLIDATED STATEMENTS OF INCOME


                                                 (thousands of dollars)
<TABLE>
<CAPTION>
FOR THE YEARS ENDED                         2001         2000          1999
DECEMBER 31,

<S>                                       <C>         <C>            <C>
OPERATING REVENUES                        $128,270    $127,234       $123,919

OPERATING EXPENSES:
   Operation and maintenance                22,108      21,119         21,534
   Depreciation and amortization            23,847      23,609         21,976
   Taxes other than income taxes            10,953      11,156         11,449

     Total Operating Expenses               56,908      55,884         54,959

OPERATING INCOME                            71,362      71,350         68,960

OTHER INCOME/(EXPENSES):
   Interest income                           1,412       2,203          1,644
   Allowance for equity funds used
     during construction                       444         126             --
   Other, net                                  (27)       (505)          (225)

                                             1,829       1,824          1,419
INCOME BEFORE INTEREST
 CHARGES AND TAXES                          73,191      73,174         70,379

INTEREST EXPENSE:
   Interest expense                         28,736      31,283         30,621
   Allowance for borrowed funds used
     during construction                      (669)       (144)            --

     Net Interest Expense                   28,067      31,139         30,621

INCOME BEFORE TAXES                         45,124      42,035         39,758

PROVISION FOR TAXES                         18,275      17,083         15,580

NET INCOME                                 $26,849     $24,952        $24,178
</TABLE>


   The accompanying notes are an integral part of these financial statements.


                                      F-3

<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
                           CONSOLIDATED BALANCE SHEETS



ASSETS                                                (thousands of dollars)
AT DECEMBER 31,                                       2001             2000

<TABLE>
<CAPTION>
CURRENT ASSETS:
<S>                                                 <C>              <C>
   Cash and temporary cash investments              $21,715          $25,013
   Accounts receivable - trade                        6,480            7,655
   Accounts receivable - affiliates                   5,267            5,667
   Other current assets                               3,505            3,138
     Total Current Assets                            36,967           41,473

NATURAL GAS TRANSMISSION PLANT:
   Natural gas plant in service                     776,961          777,577
   Construction work in progress                     40,659            7,646
                                                    817,620          785,223
   Accumulated depreciation and amortization       (284,401)        (265,051)
     Net Natural Gas Transmission Plant             533,219          520,172

OTHER ASSETS AND DEFERRED CHARGES:
   Regulatory assets - income tax related            13,298           13,634
   Regulatory assets - other                          1,850            2,038
   Other assets and deferred charges                  6,411            7,051

     Total Other Assets and Deferred Charges         21,559           22,723

     TOTAL ASSETS                                  $591,745         $584,368
</TABLE>


   The accompanying notes are an integral part of these financial statements.

                                      F-4

<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
                           CONSOLIDATED BALANCE SHEETS



LIABILITIES AND PARTNERS' EQUITY                         (thousands of dollars)
AT DECEMBER 31,                                              2001         2000

<TABLE>
<CAPTION>
CURRENT LIABILITIES:
<S>                                                       <C>          <C>
   Accounts payable                                       $  7,655     $  3,639
   Accrued interest                                          2,909        2,909
   Current portion of long-term debt (Note 3)               22,222       22,222
   Accrued property taxes                                    4,001        3,541
   Other current liabilities                                 3,377        1,844
     Total Current Liabilities                              40,164       34,155

LONG-TERM DEBT (NOTE 3)                                    344,444      366,667

OTHER NON-CURRENT LIABILITIES:
   Unrealized loss-interest rate hedge, net of tax
     (Note 2)                                                1,783           --
   Other non-current liabilities                             1,292          489
     Total Other Non-Current Liabilities                     3,075          489

AMOUNTS EQUIVALENT TO DEFERRED INCOME TAXES:
   Generated by Partnership                                 88,623       79,866
   Payable by Partners                                     (75,325)     (66,232)
     Total Amounts Equivalent to Deferred Income
     Taxes                                                  13,298       13,634
COMMITMENTS AND CONTINGENCIES (NOTE 7)                          --           --

     TOTAL LIABILITIES                                     400,981      414,945

PARTNERS' EQUITY                                           190,764      169,423

TOTAL LIABILITIES AND PARTNERS' EQUITY                    $591,745     $584,368
</TABLE>


   The accompanying notes are an integral part of these financial statements.

                                      F-5

<PAGE>

                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
                      CONSOLIDATED STATEMENTS OF CASH FLOWS


<TABLE>
<CAPTION>
                                                        (thousands of dollars)
FOR THE YEARS ENDED DECEMBER 31,                     2001       2000      1999

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                <C>         <C>      <C>
   Net Income                                      $26,849     $24,952  $24,178
   Adjusted for the following:
     Depreciation and amortization                  23,847      23,609   21,976
     Allowance for equity funds used
         during construction                          (444)       (126)      --
     Deferred regulatory assets-income
         tax related                                   336        (867)   1,071
     Amounts equivalent to deferred
         income taxes                                 (336)        867   (1,071)
     Income and other taxes payable by Partners     18,275      17,083   15,580
     Other assets and deferred charges                 718      (5,567)  (1,007)
     Other non-current liabilities                     803          --       --

     Changes in working capital:
        Accounts receivable                          1,575        (944)  (1,352)
        Other current assets                          (367)        284     (932)
        Accounts payable                             4,016         346     (604)
        Accrued interest                                --      (1,872)    (430)
        Other liabilities                            1,993        (584)     552

     Net cash provided by operating activities      77,265      57,181   57,961

CASH FLOWS FROM INVESTING ACTIVITIES:
   Capital expenditures                            (36,340)     (8,268)  (7,718)
      Net Cash used for investing activities       (36,340)     (8,268)  (7,718)

CASH FLOWS FROM FINANCING ACTIVITIES:
   Partner distributions                           (22,000)   (100,000) (25,000)
   Long-term debt borrowings                            --     400,000        --
   Repayments of long-term debt                    (22,223)   (347,775) (28,724)
   Short-term borrowings (repayments)                   --      (3,500)    3,500
     Net cash used for financing activities        (44,223)    (51,275) (50,224)

NET INCREASE (DECREASE) IN CASH AND
     TEMPORARY CASH INVESTMENTS                     (3,298)     (2,362)       19

CASH AND TEMPORARY CASH INVESTMENTS
     AT BEGINNING OF YEAR                           25,013      27,375    27,356

CASH AND TEMPORARY CASH INVESTMENTS
     AT END OF YEAR                                $21,715     $25,013   $27,375


                                      F-6

<PAGE>


SUPPLEMENTAL DISCLOSURES OF CASH
FLOW INFORMATION:
   Cash paid for interest                          $28,011     $32,628   $31,051
</TABLE>

   The accompanying notes are an integral part of these financial statements.

                                      F-7

<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
                    STATEMENT OF CHANGES IN PARTNERS' EQUITY

<TABLE>
<CAPTION>
                                            (thousands of dollars)
PARTNERS' EQUITY

<S>                                              <C>
BALANCE AT DECEMBER 31, 1998                     $212,630

   Net income 1999                                 24,178
   Taxes payable by Partners                       15,580
   Equity distributions to Partners               (25,000)

BALANCE AT DECEMBER 31, 1999                     $227,388

   Net income 2000                                 24,952
   Taxes payable by Partners                       17,083
   Equity distributions to Partners              (100,000)

BALANCE AT DECEMBER 31, 2000                     $169,423

   Net income 2001                                 26,849
   Taxes payable by Partners                       18,275
   Equity distributions to Partners               (22,000)
   Other comprehensive loss, net of tax            (1,784)

PARTNERS' EQUITY
   BALANCE AT DECEMBER 31, 2001                  $190,764
</TABLE>








                                      F-8

<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



NOTE 1

DESCRIPTION OF PARTNERSHIP:

Iroquois Gas Transmission System, L.P., ("Iroquois" or "Company") is a Delaware
limited partnership formed for the purpose of constructing, owning and operating
a natural gas transmission pipeline from the Canada-United States border near
Waddington, NY, to South Commack, Long Island, NY. In accordance with the
limited partnership agreement, the Partnership shall continue in existence until
October 31, 2089, and from year to year thereafter, until the Partners elect to
dissolve the Partnership and terminate the limited partnership agreement.

As of December 31, 2001, the Partners consist of TransCanada Iroquois Ltd.
(29.0%), North East Transmission Company (19.4%), Dominion Iroquois, Inc.
(24.72%), TCPL Northeast Ltd. (11.96%), JMC-Iroquois, Inc. (4.93%), TEN
Transmission Company (4.87%), NJNR Pipeline Company (3.28%), LILCO Energy
Systems, Inc. (1.0%), and Iroquois Pipeline Investment, LLC (.84%). On May 4,
2001, ARR Iroquois, Inc and ANR New England Pipeline Company sold their interest
in the Company to Dominion Iroquois, Inc., TCPL Northeast Ltd, Iroquois Pipeline
Investment, LLC and NJNR Pipeline Company, whose interests were increased by
8.72%, 5.96%, .84% and .48% respectively. The Iroquois Pipeline Operating
Company, a wholly-owned subsidiary, is the administrative operator of the
pipeline.

Income and expenses are allocated to the Partners and credited to their
respective equity accounts in accordance with the partnership agreements and
their respective percentage interests. Distributions to Partners are made
concurrently to all Partners in proportion to their respective partnership
interests. Total cash distributions of $22.0 million, $100.0 million and $25.0
million were made during 2001, 2000 and 1999, respectively.



NOTE 2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Basis of Presentation

The consolidated financial statements of the Company are prepared in accordance
with generally accepted accounting principles and with accounting for regulated
public utilities prescribed by the Federal Energy Regulatory Commission
("FERC"). Generally accepted accounting principles for regulated entities allow
the Company to give accounting recognition to the actions of regulatory
authorities in accordance with the provisions of Statement of Financial
Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain
Types of Regulation". In accordance with SFAS No. 71, the Company has deferred
recognition of costs (a regulatory

                                      F-9
<PAGE>

asset) or has recognized obligations (a regulatory liability) if it is probable
that such costs will be recovered or an obligation relieved in the future
through the rate-making process.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and
Iroquois Pipeline Operating Company, a wholly-owned subsidiary. Intercompany
transactions have been eliminated in consolidation.

Cash and Temporary Cash Investments

Iroquois considers all highly liquid temporary cash investments purchased with
an original maturity date of three months or less to be cash equivalents. Cash
and temporary cash investments of $21.7 million at December 31, 2001 and $25.0
million at December 31, 2000 consisted primarily of discounted commercial paper.

Natural Gas Plant In Service

Natural gas plant in service is carried at original cost. The majority of the
natural gas plant in service is categorized as natural gas transmission plant
which began depreciating over 20 years on a straight line basis from the
in-service date through January 31, 1995. Commencing February 1, 1995,
transmission plant began depreciating over 25 years on a straight-line basis as
a result of a rate case settlement. Effective August 31, 1998 the depreciation
rate was changed to 2.77% (36 years average life) in accordance with a FERC rate
order issued July 29, 1998. General plant is depreciated on a straight-line
basis over five years.

Construction Work In Progress

At December 31, 2001, construction work in progress included preliminary
construction costs relating mainly to the Eastchester Project and other on-going
capital projects.

Allowance for Funds Used During Construction

The allowance for funds used during construction ("AFUDC") represents the cost
of funds used to finance natural gas transmission plant under construction. The
AFUDC rate includes a component for borrowed funds as well as equity. The AFUDC
is capitalized as an element of natural gas plant in service.

Provision for Taxes

The payment of income taxes is the responsibility of the Partners and such taxes
are not normally reflected in the financial statements of partnerships.
Iroquois' approved rates, however, include an allowance for taxes (calculated as
if it were a corporation) and the FERC requires Iroquois to record such taxes in
the Partnership records to reflect the taxes payable by the Partners as a result
of Iroquois' operations. These taxes are recorded without regard as to whether
each Partner can utilize its share of the Iroquois tax deductions. Iroquois'
rate base, for rate-making purposes, is reduced by the amount equivalent to
accumulated deferred income taxes in calculating the required return.

                                      F-10
<PAGE>

The Company accounts for income taxes under Statement of Financial Accounting
Standards ("SFAS") No. 109, "Accounting for Income Taxes". Under SFAS No. 109,
deferred taxes are provided based upon, among other factors, enacted tax rates
which would apply in the period that the taxes become payable, and by adjusting
deferred tax assets or liabilities for known changes in future tax rates. SFAS
No. 109 requires recognition of a deferred income tax liability for the equity
component of AFUDC.

Estimates

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.

Reclassifications

Certain prior year amounts have been reclassified to conform with current year
classifications.

New Accounting Standards

Effective January 1, 2001 the Company has adopted Statement of Financial
Accounting Standards ("SFAS") No. 133 as issued by the Financial Accounting
Standards Board ("FASB"), "Accounting or Derivative Instruments and Hedging
Activities", as amended ("SFAS 133"). Under SFAS 133, Iroquois records the fair
value of derivatives held as assets or liabilities. The changes in net value of
the effective portion of derivatives qualifying as cash flow hedges are recorded
in other comprehensive income, a component of Partners' Equity.

In June 2001, the FASB issued SFAS No. 141, "Business Combinations" ("SFAS
141"), and No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS
141 is effective for business combinations completed after June 30, 2001 and
SFAS 142 is effective for fiscal year 2002. Implementation of these standards is
not expected to have a material impact on the company's financial position or
results of operations.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"). SFAS 143 provides the accounting requirements for
retirement obligations associated with tangible long lived assets. SFAS 143 is
effective for fiscal years beginning after June 15, 2002, and early adoption is
permitted. Implementation of this standard is not expected to have a material
impact on the Company's financial position or results of operations.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of" ("SFAS 121") and the accounting and reporting provisions of
Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations
- Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual
and Infrequently Occurring Events and Transactions," related to the disposal of
a segment of a business. SFAS 144 establishes a single accounting model for
long-

                                      F-11

<PAGE>

lived assets to be disposed of by sale and resolves significant implementation
issues related to SFAS 121. SFAS 144 is effective for fiscal years beginning
after December 15, 2001.

Implementation of this standard is not expected to have a material impact on the
Company's financial position or results of operations.

Other Comprehensive Income

Comprehensive Income consisted of the following:

                                                           At December 31, 2001

Net income                                                           $26,849

Other comprehensive loss

   Unrealized loss on interest rate hedge, net of tax     2,991
   Tax effect                                            (1,207)
                                                         -------

      Unrealized loss on interest rate hedge, net of tax              (1,784)
                                                                      -------

         Comprehensive Income                                        $25,065

Refer to Note 3 to the Financial Statements for details of the interest rate
hedge.

NOTE 3

FINANCING:

On June 11, 1991, Iroquois entered into a loan agreement which provided a loan
facility totaling $522.6 million to be amortized over a 14-year period
commencing November 1, 1992. During 1993, Iroquois entered into Expansion Loan
Agreement No. 1 in the amount of $17.6 million to construct the Wright
Compressor Station. This loan had a maturity date of November 2007. During 1995,
Iroquois entered into Expansion Loan Agreement No. 2 in the amount of $13.4
million to finance the Croghan Compressor Station. This loan had a maturity date
of November 2008. On May 30, 2000, Iroquois exercised its option to prepay these
three loans in full with the proceeds of the Term Loan Facility and Senior Notes
which are described below.

As of December 31, 1999, Iroquois was party to interest rate swap transactions
for aggregate notional principal amounts of $537.6 million relating to the
original loan and Expansion Loan No. 1. The fair value of the interest rate
swaps is the estimated amount that Iroquois would receive or pay to terminate
the swap agreements at the reporting date, taking into account current interest
rates and current creditworthiness of the swap counterparties. The fair value of
these interest rate swaps were ($8.6) million at December 31, 1999. These
interest rate swap agreements were terminated during the first six months of
2000.

On May 30, 2000, Iroquois completed a private offering of $200 million of 8.68%
senior notes due 2010, which were exchanged in a registered offering for notes
with substantially identical

                                      F-12
<PAGE>

terms on September 25, 2000 ("Senior Notes"). Also on May 30, 2000, Iroquois
entered into a credit agreement with certain financial institutions providing
for a term loan facility of $200 million ("Term Loan Facility") and a $10
million, 364-day revolving credit facility. The credit agreement permits
Iroquois 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 Term Loan Facility
will amortize over nine years. At December 31, 2001 and December 31, 2000, there
were no amounts outstanding under the revolving credit facility. The proceeds
from the Senior Notes and Term Loan Facility were used to repay borrowings under
the above mentioned three loan agreements, terminate related interest rate swap
agreements, make a cash distribution to Iroquois' partners of $40 million, pay
certain financing fees and expenses and for general corporate purposes.

During the first six months of 2000, Iroquois paid approximately $0.9 million
for the termination of its entire portfolio of interest rate swap agreements,
which had an aggregate notional principal amount of $437.6 million. Iroquois has
deferred and is amortizing these amounts over the life of the original loan
agreements.

On August 9, 2000, the Company entered into an interest rate swap agreement with
The Chase Manhattan Bank to hedge a portion of the interest rate risk on the new
credit facilities. This interest rate swap agreement was effective on August 30,
2000 and will terminate on the last business day in May 2009. Pursuant to the
terms of this interest rate swap agreement, Iroquois has agreed to pay to The
Chase Manhattan Bank a fixed rate of 6.82% on an initial notional amount of
$25.0 million, which is being amortized during the term of the interest rate
swap agreement, in return for a payment from The Chase Manhattan Bank of a
floating rate of 3-month LIBOR on the amortizing notional amount. On August 9,
2000, the Company also entered into an option with The Chase Manhattan Bank
pursuant to which The Chase Manhattan Bank had the option to enter into an
additional interest rate swap agreement. The Chase Manhattan Bank exercised this
option which was effective on December 26, 2000 and will terminate on the last
business day in May 2009. This additional interest swap agreement has the same
fixed and floating rate terms as the initial interest rate swap agreement and is
for an initial notional amount of $24.3 million, which is being amortized during
the term of the additional interest rate swap agreement. As of December 31, 2001
and December 31, 2000, the aggregate notional principle amount of these two
swaps was $41.7 million and $47.2 million, respectively. The interest rate and
margin over the term of the swaps average 6.820% and 1.260% respectively. The
fair value of these interest rate swaps, net of taxes at December 31, 2001 and
December 31, 2000, was ($1.8) million and ($1.7) million, respectively.

At December 31, 2001, the outstanding principal balance was $200 million on the
Senior Notes and $166.7 million on the Term Loan Facility. The combined schedule
of repayments at December 31, 2001 is as follows (millions of dollars):

                                      F-13
<PAGE>

                        Year                      Scheduled Repayment
                        ----                      -------------------
                        2002                            $  22.2
                        2003                            $  22.2
                        2004                            $  22.2
                        2005                            $  22.2
                        2006                            $  22.2
                        Thereafter                      $ 255.7
NOTE 4

CONCENTRATIONS OF CREDIT RISK:

Iroquois' cash and temporary cash investments and trade accounts receivable
represent concentrations of credit risk. Management believes that the credit
risk associated with cash and temporary cash investments is mitigated by its
practice of limiting its investments primarily to commercial paper rated P-1 or
higher by Moody's Investors Services and A-1 or higher by Standard and Poor's,
and its cash deposits to large, highly-rated financial institutions. Management
also believes that the credit risk associated with trade accounts receivable is
mitigated by the restrictive terms of the FERC gas tariff which requires
customers to pay for service within 20 days after the end of the month of
service delivery.

NOTE 5

FAIR VALUE OF FINANCIAL INSTRUMENTS:

The fair value amounts disclosed below have been reported to meet the disclosure
requirements of SFAS No. 107, "Disclosures About Fair Values of Financial
Instruments" and are not necessarily indicative of the amounts that the Company
could realize in a current market exchange.

The carrying amount of cash and temporary cash investments, accounts receivable,
accounts payable and accrued expenses approximates fair value.

The fair value of long-term debt is estimated based on currently quoted market
prices for similar types of issues. The carrying amounts and estimated fair
values of the Company's long-term debts including current maturities are as
follows (thousands of dollars):

                                  Carrying
                     Year          Amount        Fair Value
                     ----          ------        ----------
                     2001         $366,666        $384,550
                     2000         $388,889        $408,441


                                      F-14
<PAGE>

NOTE 6

GAS TRANSPORTATION CONTRACTS:

As of December 31, 2001, Iroquois had contracts in place to provide firm
reserved transportation service to 36 shippers of 1005.9 MDth/d of natural gas
which breaks down as follows:

                    Remaining             Quantity in MDth/d
                    Term in Years         ------------------
                    -------------
                    Less than 10                606.3
                    11-15                       305.6
                    16-20                        94.0
                                                 ----
                    Total                      1005.9

The long-term firm service gas transportation contracts expire between May 1,
2002 and August 1, 2018.

NOTE 7

COMMITMENTS AND CONTINGENCIES:

Regulatory Proceedings
FERC Docket No. RP97-126 and RP94-72 et al.
-------------------------------------------
On December 17, 1999 Iroquois filed with the Commission a settlement of various
outstanding rate matters. Pursuant to the settlement the parties agreed to a
rate moratorium whereby, with limited exceptions, no new rates could be placed
in effect on Iroquois' system until January 1, 2004. During the period of the
moratorium, Iroquois would reduce its 100% load factor interzone rate by
approximately 4.8(cent) per dekatherm (approximately 1(cent) in 2001, an
additional 2.4(cent) in 2002 and an additional 1.4(cent) in 2003). In 2001, the
settlement resulted in a reduction in revenue of $2.4 million. Based on 2001
long-term firm service contracts the settlement will result in reductions in
revenues of $6.0 million in 2002, and $3.6 million in 2003. By letter order
issued February 10, 2000, the Commission approved the rate settlement without
modification. The settlement became effective on March 10, 2000.

FERC Order No. 637
------------------
On February 9, 2000, the Commission issued Order No. 637 in Docket Nos. RM98-10
and RM98-12. According to the Commission, the order was to reflect "steps to
guarantee effective competition, remove constraints on market power, and
eliminate regulatory bias". Among other things, the order required pipelines to
submit Commission filings to 1) remove the price cap applicable to pipeline
capacity released by firm shippers to new shippers, 2) revise pipeline
scheduling procedures applicable to such released capacity, 3) permit firm
shippers to segment their capacity for their own use or release, 4) revise
pipeline penalty provisions, and 5) expand, modify and consolidate certain
pipeline reporting requirements. On July 17, 2000 and September 1, 2000,
Iroquois submitted filings in (respectively) Docket Nos. RP00-411 and RP00-529
to implement the provisions of Order No. 637. Certain parties, including a
number of Iroquois shippers, opposed certain aspects of the filings. The tariff
sheets submitted in Docket No. RP00-529 were accepted in a letter order dated
September 28, 2000. On November 8, 2001,

                                      F-15
<PAGE>


the Commission issued an order finding that Iroquois' July 17, 2000 filing
generally complied with the Commission's requirements outlined in Order No. 637
("November 8 Order"). The November 8 Order directed Iroquois to make certain
additional changes to the tariff sheets filed on July 17, 2000. Iroquois filed
updated tariff sheets with the Commission on December 10, 2001. An affiliated
group of Iroquois shippers has opposed certain aspects of the December 10
filing. Management believes that the outcome of these proceedings will not have
a material adverse effect on Iroquois' financial condition or results of
operations.

Eastchester Certificate Application (FERC Docket No. CP00-232)
--------------------------------------------------------------
On April 28, 2000, Iroquois filed an application with the Commission to
construct and operate its "Eastchester Extension Project". Under this proposal,
Iroquois would construct and operate certain facilities, including additional
compression facilities and approximately 33 miles of pipeline and associated
facilities from Northport, Long Island to the Bronx, New York. Those proposed
facilities would provide 230,000 dekatherms of natural gas per day to the New
York City area. Iroquois would provide firm transportation service to the
shippers with whom it has executed precedent agreements. On December 26, 2001,
the Commission issued a certificate authorizing the Partnership to construct and
operate the Eastchester facilities ("December 26 Order"). On January 25, 2002,
the Partnership accepted the certificate. A condition in the FERC certificate
requires that, prior to commencing construction, the project shippers execute
firm service agreements with 10-year terms for the entire 230,000 Dt/day of
transportation capacity proposed to be built. This condition was based on
precedent agreements with five project shippers. However, as a result of the
current uncertainty and slow down in the energy market, exacerbated by the Enron
bankruptcy and the resulting examination, both internal and external, of the
financial health of a variety of other energy market participants, certain
Eastchester shippers, that were obligated under the precedent agreements to
execute firm transportation service agreements, have indicated an unwillingness
to do so. As a result, the Partnership expects that it will not have executed
contracts for 100% of the total project capacity prior to April, 2002, when it
anticipates commencing construction. Therefore, on February 28, 2002, the
Partnership filed a request with the FERC to modify the condition in the
December 26 Order and to permit the Partnership to commence construction even if
service contracts for less than the full 230,000 Dt/day of service have been
executed. This request is still pending at the FERC and could delay the
in-service date for certain of the Eastchester facilities.

Athens Project (FERC Docket No. CP02-20-000)
--------------------------------------------
On November 8, 2001, Iroquois filed an application with the Commission to
construct and operate its "Athens Project". Under this proposal, Iroquois would
construct a second compressor unit at its existing Athens, New York compressor
station. The facilities are designed to provide up to 70,000 dekatherms per day
of firm transportation to Athens Generating Company, L. P. ("Athens Generating")
with whom Iroquois has executed a precedent agreement for this service. "Athens
Generating" is in the process of developing a natural gas fired electric
generation facility in the Town of Athens, New York. The proposed in-service
date for this project is September 1, 2003.

Brookfield Project (FERC Docket No. CP02-31-000)
-----------------------------------------------
On November 20, 2001, Iroquois filed an application with the Commission to
construct and operate its "Brookfield Project". Under this proposal, Iroquois
would construct a new compressor station to be located in Brookfield,
Connecticut. This facility is designed to provide

                                      F-16
<PAGE>

up to 85,000 dekatherms per day of firm transportation service to southern Long
Island and the New York City Area. Iroquois would provide firm transportation
service to the shippers with whom it has executed precedent agreements. The
proposed in-service date for the Brookfield Project is April 1, 2004.

Eastern Long Island Expansion Project (FERC Docket No.CP02-52-000)
-----------------------------------------------------------------
On December 14, 2001, Iroquois filed an application with the Commission to
construct and operate its "Eastern Long Island Expansion Project" ("ELI"). In
order to implement the ELI project Iroquois would construct approximately 29
miles of 20-inch pipeline from a point offshore of Milford, Connecticut to a
point in Brookhaven, Suffolk County, New York and additional compression and
cooling facilities. These facilities are designed to provide approximately 175,
000 dekatherms per day of firm transportation service to the eastern end of Long
Island, New York. Iroquois would provide firm transportation service to the
shippers with whom it has executed precedent agreements. The proposed in-service
date for the Eastern Long Island Expansion Project is November 1, 2004.

Legal Proceedings-Other

Iroquois is party to various other legal actions incident to its business.
However, management believes that the outcome of these proceedings will not have
a material adverse effect on Iroquois' financial condition or results of
operations.

Leases

Iroquois leases its office space under operating lease arrangements. The leases
expire at various dates through 2011 and are renewable at Iroquois' option.
Iroquois also leases a right-of-way easement on Long Island, NY, from the Long
Island Lighting Company ("LILCO"), a general partner, which requires annual
payments escalating 5% per year over the 39-year term of the lease. In addition,
Iroquois leases various equipment under non-cancelable operating leases. During
the years ended December 31, 2000, 1999 and 1998, Iroquois made payments of $1.0
million per year under operating leases which were recorded as rental expense.
Future minimum rental payments under operating lease arrangements are as follows
(millions of dollars):

                    Year                       Amount
                    ----                       ------
                    2002                       $ 1.0
                    2003                       $ 1.1
                    2004                       $ 1.1
                    2005                       $ 1.0
                    2006                       $ 1.0
                    Thereafter                 $ 8.6

NOTE 8

INCOME TAXES:

Deferred income taxes which are the result of operations will become the
obligation of the Partners when the temporary differences related to those items
reverse. The Company recognizes a decrease in the Amounts Equivalent to Deferred
Income Taxes account for these

                                      F-17
<PAGE>

amounts and records a corresponding increase to Partners' equity. Deferred
income taxes with respect to the equity component of AFUDC remain on the
accounts of the Partnership until the related deferred regulatory asset is
recognized.

Total income tax expense includes the following components (thousands of
dollars):


                U.S.                       State-
   2001         Federal       State        Other         Total
   -------------------------------------------------------------

   Current      $ 6,431      $2,751        $--          $ 9,182
   Deferred       8,054       1,039         --            9,093
   Total        $14,485      $3,790        $--          $18,275

                U.S.                       State-
   2000         Federal       State        Other        Total
   -------------------------------------------------------------
   Current      $ 5,501      $2,620        $--          $ 8,121
   Deferred       8,342         620         --            8,962
   Total        $13,843      $3,240        $--          $17,083

                U.S.                       State-
   1999         Federal       State        Other        Total
   -------------------------------------------------------------
   Current      $ 5,082      $   540       $1,124       $ 6,746
   Deferred       8,285          549        --            8,834
   Total        $13,367       $1,089       $1,124       $15,580

For the years ended December 31, 2001, 2000 and 1999, the effective tax rate
differs from the Federal statutory rate due principally to the impact of state
taxes.

Deferred income taxes included in the income statement relate to the following
(thousands of dollars):

                                           2001         2000         1999
    -----------------------------------------------------------------------
     Depreciation                       $ 8,157      $ 8,410      $ 8,930
     Deferred regulatory asset              (76)         (76)         (70)
     Property taxes                          (3)          (1)          23
     Legal costs                             --           --          (16)
     Accrued expenses                      (240)          --           16
     Alternative minimum tax credit
                                          1,141          277          (37)
     Other                                  114          352          (12)
     Total deferred taxes               $ 9,093      $ 8,962      $ 8,834


                                      F-18
<PAGE>

The components of the net deferred tax liability are as follows (thousands of
dollars):

          At December 31                               2001          2000
          -----------------------------------------------------------------
         DEFERRED TAX ASSETS:
         Alternative minimum tax credit              $ 1,355      $  2,496
         Accrued expenses                              1,051           812
         Total deferred tax assets                     2,406         3,308

         DEFERRED TAX LIABILITIES
         Depreciation and related items              (75,589)      (67,456)
         Deferred regulatory asset                      (731)         (808)
         Property taxes                                 (874)         (879)
         Other                                        (1,173)       (1,058)
         Total deferred tax liabilities              (78,367)      (70,201)
         Net deferred tax liabilities                (75,961)      (66,893)
         Less deferral of tax rate change                636           661
         Deferred taxes-operations                   (75,325)      (66,232)
         Deferred tax related to equity AFUDC        (12,662)      (12,973)
         Deferred tax related to change in
         tax rate                                       (636)         (661)
         Total deferred taxes                      $ (88,623)    $ (79,866)


NOTE 9

RELATED PARTY TRANSACTIONS:

Operating revenues and amounts due from related parties were primarily for gas
transportation services. Amounts due from related parties are shown net of
payables, if any.

The following table summarizes Iroquois' related party transactions (millions of
dollars):

                                     Payments                      Revenue
                                     to             Due from       from
                                     Related        Related        Related
         2001                        Parties        Parties        Parties
     ---------------------------------------------------------------------
     TransCanada Iroquois Ltd.          $--          $--           $  5.9
     NorthEast Transmission Company      --          1.2             12.2
     JMC - Iroquois, Inc.                --          1.5             17.8
     TEN Transmission Company            --          1.1             11.5
     NJNR Pipeline Company               --          0.6              6.8
     LILCO Energy Systems, Inc.         0.1          0.9              1.1
              Total                    $0.1         $5.3           $ 55.3


                                      F-19
<PAGE>


                                     Payments                      Revenue
                                     to             Due from       from
                                     Related        Related        Related
         2001                        Parties        Parties        Parties
     ---------------------------------------------------------------------
     TransCanada Iroquois Ltd.        $0.2          $0.7           $  7.6
     NorthEast Transmission Company     --           1.1              9.1
     ANR Iroquois, Inc.                 --            --              2.8
     JMC - Iroquois, Inc.               --           1.7             18.1
     TEN Transmission Company           --           0.6              7.4
     NJNR Pipeline Company              --           0.6              7.0
     LILCO Energy Systems, Inc.         --           1.0             11.3
              Total                   $0.2          $5.7           $ 63.3

NOTE 10

RETIREMENT BENEFIT PLANS:

During 1997, the Company established a noncontributory retirement plan ("Plan")
covering substantially all employees. Pension benefits are based on years of
credited service and employees' career earnings, as defined in the Plan. The
Company's funding policy is to contribute, annually, an amount at least equal to
that which will satisfy the minimum funding requirements of the Employee
Retirement Income Security Act ("ERISA") plus such additional amounts, if any,
as the Company may determine to be appropriate from time to time.

During 1997 and 1998 the Company also adopted excess benefit plans ("EBPs") that
provide retirement benefits to executive officers and other key management
staff. The EBPs recognize total compensation and service that would otherwise be
disregarded due to Internal Revenue Code limitations on compensation in
determining benefits under the regular retirement plan. The EBPs are not
considered to be funded for ERISA purposes and benefits are paid when due from
general corporate assets, however, a Rabbi Trust has been established to
partially cover this obligation. The Rabbi Trust is an irrevocable trust which
can be used to satisfy creditors.

The consolidated net cost for pension benefit plans included in the consolidated
statements of income for the years ending December 31, include the following
components (thousands of dollars):

                                                    2001       2000      1999
          ----------------------------------------------------------------------
          Service cost.                             $597       $504      $388
          Interest cost                              137         98        68
          Expected return on plan asset.            (144)       (92)      (52)
          Amortization of prior service cost          22         22        22
          Recognition of net actuarial loss            6          2         9
          Net periodic pension cost                 $618       $534      $435

                                      F-20

<PAGE>

The following tables represent the two Plans' combined funded status reconciled
to amounts included in the consolidated balance sheets as of December 31, 2001
and 2000 (thousands of dollars):

<TABLE>
<CAPTION>
    Change in Benefit Obligation                        2001            2000
                                                       ---------------------
<S>                                                    <C>             <C>
    Benefit obligation at beginning of year            $1,945          $1,456
    Service cost                                          597             504
    Interest cost                                         137              98
    Actuarial gain                                        (67)            (84)
    Benefits paid                                         (42)            (29)
    Benefit obligation at end of year                  $2,570          $1,945

    Change in Plan Assets                              2001             2000
                                                      ----------------------
    Fair value of plan assets at beginning of year    $1,455             $862
    Actual return on plan assets                         (39)              30
    Employer contribution                                863              592
    Benefits paid                                        (42)             (29)
    Fair value of plan assets at end of year          $2,237           $1,455

    Reconciliation of Funded Status                    2001             2000
                                                      -----------------------
    Funded status                                     $(333)           $(490)
    Unrecognized net actuarial loss                     208               98
    Unrecognized prior service cost                     147              169
    Additional minimum liability                       (119)             (96)
    Accrued benefit cost                              $ (97)           $(319)
</TABLE>

The weighted average assumptions used in developing the projected benefit
obligations were:

                                             2001          2000           1999
                                           ------------------------------------
   Discount rate                             7.0%          7.0%           7.0%
   Expected return on plan assets            9.0%          9.0%           9.0%
   Increase in future compensation           4.5%          5.0%           5.0%



                                      F-21