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, 2002
                                       Or

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

                   For the transition period from       to      .

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

                        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. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
                                Yes [ ] No [ X ]


<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

          Form 10-K Annual Report, for the year ended December 31, 2002

                                Table of Contents
                                                                            Page

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

                                     PART I.

ITEM 1.  BUSINESS..............................................................2

ITEM 2.  PROPERTIES...........................................................17

ITEM 3.  LEGAL PROCEEDINGS....................................................17

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................19

                                    PART II.

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
         STOCKHOLDER MATTERS..................................................19

ITEM 6.  SELECTED FINANCIAL DATA..............................................19

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         CONDITION AND RESULTS OF OPERATIONS..................................20

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
         MARKET RISK..........................................................29

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................29

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
         ACCOUNTING AND FINANCIAL DISCLOSURE..................................29

                                    PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP..................30

ITEM 11. EXECUTIVE COMPENSATION...............................................32

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
         MANAGEMENT...........................................................37

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................38

ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES...................................38

                                    PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
         REPORTS ON FORM 8-K..................................................39


                                       i

<PAGE>

INDEX TO FINANCIAL STATEMENTS................................................F-1

                                       ii

<PAGE>


                SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

         This annual report includes statements that are "forward-looking" (as
defined in the Private Securities Litigation Reform Act of 1995). These
forward-looking statements are based on the Partnership's current expectations
and projections about future events. Words such as "believes," "expects,"
"estimates," "may," "intends," "will," "should" or "anticipates" and similar
expressions or their negatives identify forward-looking statements. Examples of
forward-looking statements that are not historical in nature include those
regarding:

          o    trends and outlook in the natural gas transportation industry and
               market;

          o    forecast of growth in natural gas demand and supply;

          o    the Partnership's competitiveness in the natural gas
               transportation market;

          o    the Partnership's business and growth strategies, including
               attracting new shippers and expanding its pipeline system to add
               new markets not currently served by it;

          o    the effects of regulations; and

          o    anticipated future revenues, capital spending and financial
               resources.

The forward-looking statements included in this annual report are subject to
risks and uncertainties that may cause the Partnership's actual results or
performance to differ from any future results or performance expressed or
implied by the forward-looking statements. These risks and uncertainties
include, among other things:

          o    competition and other factors that may affect the Partnership's
               ability to maintain its contracts with its existing shippers or
               acquire new shippers;

          o    inability to execute the Partnership's business strategy, changes
               in the Partnership's business strategy or expansion plans or
               inability to achieve its projections;

          o    regulatory, legislative and judicial developments, particularly
               with respect to regulation by the Federal Energy Regulatory
               Commission, or the FERC ;

          o    dependence on shippers for revenues; and

          o    dependence on availability of Western Canada natural gas reserves
               and the continued availability of gas transportation from Western
               Canada to the Partnership's pipeline through the TransCanada
               PipeLines Limited System.

Certain of these factors are discussed in more detail elsewhere, including,
without limitation, under the captions "Business-Risk Factors," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." Other matters set forth in this annual report may also cause actual
results in the future to differ materially from those described in the
forward-looking statements. The Partnership does not intend to update or revise
any forward-looking statements, whether as a result of new information, future
events or otherwise. In light of these risks, uncertainties and assumptions, the
forward-looking events discussed in this annual report might not occur.



                                       1
<PAGE>

                                    PART I.

ITEM 1.  BUSINESS

Introduction

         Iroquois Gas Transmission System, L.P. is a Delaware limited
partnership. It owns and operates 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 at four locations with three interstate pipelines and also
connects with the pipeline system of TransCanada PipeLines Limited (the
"TransCanada System") at the Canada-United States border near Waddington, New
York.

         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. As of December 31, 2002, the Partnership had 34
shippers under long-term firm reserved transportation service contracts and its
pipeline system's contracted capacity of 1,064 thousands of dekatherms per day,
or MDth/d, was fully subscribed. As of December 31, 2002, approximately 83% of
the Partnership's subscribed 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:



                                       2
<PAGE>
                                                                      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%

       Energy East Corporation        TEN Transmission Company             4.87%

       New Jersey Resources           NJNR Pipeline Company                3.28%
            Corporation


         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 that expires on November 11, 2011 and renews on a yearly basis thereafter.

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 part of an Eastchester/New York City expansion
of its pipeline system consisting of an approximately 36-mile mainline extension
running from the mainline on Long Island near Northport, through the Long Island
Sound to Eastchester, New York (the "Eastchester Extension"), the Partnership
added additional compression and cooling facilities at the Croghan, Wright and
Athens, New York compressor stations in 2002. As of December 31, 2002, the




                                       3
<PAGE>

Partnership had firm reserved transportation contracts in place to deliver 1,064
MDth/d of natural gas.

         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 20 delivery meters with a combined capacity of
approximately 4,230 MDth/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 interconnections at four locations
with three interstate pipelines and also connects with 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 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, New York 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 34
shippers. Under the firm reserved transportation service contracts, the pipeline
receives natural gas on behalf of shippers at



                                       4
<PAGE>

designated receipt points and transports the gas on a firm basis up to each
shipper's maximum daily quantity. As of December 31, 2002, approximately 83% of
the subscribed 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's pipeline is currently 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 is also authorized by the FERC
to enter into "negotiated rate" contracts with shippers. To date, the
Partnership has entered into a limited number of negotiated rate contracts for
short-term firm transportation service.

         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., through their affiliates, each accounted
for more than 10% of the Partnership's revenues for the year ended December 31,
2002. Approximately 46% of the Partnership's existing pipeline system firm
reserved capacity was contracted to affiliates of the Partnership's partners as
of December 31, 2002.

         The Partnership's FERC-approved tariff provides that, subject to
certain exceptions, the Partnership has the right to require that firm
transportation shippers have an investment grade rating or obtain a written
shipper guarantee from a third party with an investment grade rating. During
2002, the energy industry, which includes the Partnership's firm transportation
shippers, experienced significant credit and liquidity issues and credit rating
agency downgrades. As of December 31, 2002, approximately 41% 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 22% 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 37% of the pipeline system's volume. The Partnership determines,
under internal credit standards, the shippers or their guarantors that are
creditworthy so that they are not required to post credit support in connection
with their transportation service contracts. Approximately 6% 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 and approximately 15% have made other credit support
arrangements that the Partnership finds satisfactory. The percentage of shippers
that were required to make credit support arrangements increased in 2002 due in
part to credit agencies downgrading some of the shippers and a change in the
Partnership's credit policy so that it will no longer consider the
creditworthiness of a shipper's parent in lieu of the shipper's own rating,
unless a parental guarantee is to be provided. Aside from a default on a minor
transportation contract with a shipper that is a subsidiary of Enron
Corporation, the Partnership has not experienced any payment defaults.



                                       5
<PAGE>

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 northeastern United
States 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 northeastern United States is
expected to occur in the electric generation sector.

         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
additional 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;

               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.

         In April 2002, the Partnership commenced construction of the
Eastchester Extension. The new line will proceed on land for approximately 4,000
feet, 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 more congested areas at a greater expense. Under
precedent agreements, which contain conditions that must be satisfied before a
contract for firm transportation service is signed, five project shippers agreed
to subscribe for all of the Eastchester Extension's 230 MDth/d of transportation
capacity. On December 26, 2001, the FERC issued a certificate authorizing the




                                       6
<PAGE>

Partnership to construct and operate the Eastchester Extension. On January 25,
2002, the Partnership accepted the terms of the certificate. A condition in the
December 26 order required 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 uncertainty and a slowdown in the energy market, exacerbated by Enron
Corporation's 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 failed to
do so. 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 had not been executed. On March 13, 2002, the FERC granted the
Partnership's request. As a result, the Partnership did not have executed
contracts for 100% of the total project capacity prior to commencing
construction of the Eastchester Extension. To date, the Partnership has
contracted with shippers for 210 MDth/d of transportation services in connection
with the Eastchester Extension.

         A portion of the upstream Eastchester Extension facilities have been
placed into service. Construction of the portion of the Eastchester Extension
located in the Long Island Sound commenced in October 2002. However, as a result
of delays in obtaining certain construction authorizations and permits, and
delays related to construction incidents, the projected in-service date of the
completed Eastchester Extension is now the late summer or early fall of 2003,
and the Partnership's management believes that the final construction costs will
be at least $250.0 million, rather than the $210.0 million estimated during the
FERC certification process, and will likely reduce the Partnership's initial
margins that that were anticipated when the project application was filed with
the FERC.

         On November 8, 2001, the Partnership filed an application with the FERC
to construct and operate a second compressor unit at the Partnership's existing
Athens, New York compressor station. The Athens Project is designed to provide
up to 70 MDth/d of firm transportation services to Athens Generating Company,
L.P., with whom the Partnership has executed a firm transportation agreement for
this service. On June 3, 2002, the FERC issued a certificate authorizing the
Partnership to construct the Athens Project. However, the Partnership
anticipates that it will have adequate capacity to serve the initial 70 MDth/d
transportation needs of Athens Generating, and so the Partnership intends to
defer the commencement of construction of the second compressor unit at Athens,
subject to a re-evaluation at a later date. Athens Generating is owned by Gen
Holdings I, LLC, a subsidiary of PG&E National Energy Group, Inc. On January 16,
2003, PG&E National Energy Group announced that it had agreed to cooperate with
any reasonable proposal by its lenders regarding the disposition of certain of
its generating assets, including Athens Generating, in connection with defaults
under various debt agreements. The Partnership is awaiting further developments
in connection with the announcement.

         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 shippers with



                                       7
<PAGE>

whom it has executed precedent agreements. On October 31, 2002, the FERC issued
a certificate authorizing the construction of the Brookfield Project. On
December 2, 2002, the Partnership filed a request for clarification or
re-hearing with respect to the rate that would be paid by shippers using the
Brookfield Project facilities. On February 3, 2003, the FERC issued an order
stating that all shippers using the Eastchester Facilities, to which the
Brookfield Project facilities will connect, will be required to pay incremental
fuel costs. The rate to be paid by shippers using the Brookfield Project
facilities to connect to the Eastchester delivery point will ultimately be
determined in future rate proceedings. The Partnership is currently assessing
the market for the Brookfield Project to determine if the projected November
2004 in-service date should be delayed.

         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 to provide approximately 175 MDth/d of firm
transportation service to the eastern end of Long Island, New York. On April 8,
2002, the Partnership filed a motion to consolidate its Eastern Long Island
Project with a similar project proposed by Islander East Pipeline Company, LLC
that was pending at the FERC, and to convene a comparative hearing on the two
projects. The motion was denied by the FERC on September 19, 2002 and a
certificate of public convenience and necessity was issued to Islander East. On
October 10, 2002, the FERC granted the Partnership's motion to defer the Eastern
Long Island Project and directed the Partnership to provide the FERC with an
update on the status of the Eastern Long Island Project at a later date. On
February 7, 2003, the Partnership notified the FERC that, after extensive
discussions with the Eastern Long Island Project's prospective shippers, the
Partnership had determined that insufficient market demand exists to continue to
pursue the Project and the Partnership moved to withdraw its application. As of
December 31, 2002, the Partnership expensed approximately $2.2 million in costs
related to engineering and environmental assessments performed in connection
with the Eastern Long Island Project.

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 of 1938 (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,



                                       8
<PAGE>

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.

         Except in the limited context of negotiated rates, the rates the
Partnership charges may not exceed the just and reasonable 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 reduced 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, particularly in light of the
FERC's decision to seek comments on its negotiated rate policies from companies
in the natural gas industry.



                                       9
<PAGE>

         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. 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 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 100% load factor
interzone rate decreased by $0.01/Dth effective January 1, 2001, by $0.024/Dth
effective January 1, 2002; and by $0.014/Dth effective January 1, 2003, for a
total cumulative reduction of $0.048/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, $6.1 million in 2002
and is expected to be approximately $3.6 million in 2003, based on long-term
firm reserved transportation service contracts in place as of December 31, 2002.

         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    instituted a two-year waiver of price ceilings on short-term
                    released capacity, which expired in September 2002;

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



                                       10
<PAGE>

               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 required some significant changes in the
functioning of the secondary market for firm capacity, its implementation has
not materially affected the level of revenues the Partnership receives. The
Partnership has incurred and may incur additional costs to modify its tariff and
information systems to allow it to comply with Order No. 637. However, these
expenditures have not been, and are not expected to be, material.

         As required by Order No. 637, the Partnership filed pro forma tariff
sheets with the FERC. Portions of this filing remain pending at the FERC. See
Note 7 to the Consolidated Financial Statements included elsewhere in this
annual report.

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.



                                       11
<PAGE>

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 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 $22.0 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, 2002, IPOC had 129 employees.

Risk Factors

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

The Partnership may not be able to maintain its contracts with existing shippers
or enter into contracts with new shippers

         As of December 31, 2002, approximately 83% of the subscribed capacity
of the Partnership's pipeline system was contracted through at least November 1,
2011. The



                                       12
<PAGE>

Partnership cannot give any assurances that it will be able to extend or replace
these contracts at the end of their initial terms or that, if the Partnership
does extend or replace its existing firm reserved transportation service
contracts, it will be able to do so at the maximum rates that the FERC will
authorize it to charge. The extension or replacement of the existing long-term
contracts with the Partnership's shippers and its ability to enter into similar
contracts for the total increased capacity of its pipeline system to be
generated by its expansions 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 transportation service contract. The Partnership
cannot assure you that it will be able to replace a contract terminated for
breach with a comparable contract. If these contracts are terminated or are not
extended or replaced with comparable contracts, or if the Partnership is unable
to secure contracts for all the capacity to be generated by its expansions, the
Partnership's cash flows and ability to service its outstanding senior notes may
be adversely 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 firm reserved 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. As a result, the
Partnership's profitability generally depends upon the continued
creditworthiness of the shippers rather than upon the amount of natural gas
transported. During 2002, the energy industry, which includes the Partnership's
firm transportation shippers, experienced significant credit and liquidity
issues and credit rating agency downgrades. However, aside from a default on a
minor transportation contract with a shipper that is a subsidiary of Enron
Corporation, the Partnership has not experienced any payment defaults. There can
be no assurance however, that shippers will not default on their payment
obligations for transportation services provided in the future.

         The Partnership's rates are calculated on the basis of the assumed
contracted capacity of 1,064 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



                                       13
<PAGE>

economic downturn affecting the northeastern Unites States could negatively
affect 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 its
shippers, for any length of time during which the Partnership does not succeed
in obtaining a creditworthy replacement shipper would decrease the Partnership's
revenues and cash flows and could have an adverse 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

         Because its pipeline system is an interstate natural gas pipeline, the
Partnership is subject to regulation as a "natural gas company" under the
Natural Gas Act of 1938, as amended, or the Natural Gas Act. The Natural Gas Act
makes the rates the Partnership can charge its shippers and other terms and
conditions of service subject to FERC review and the possibility of modification
in rate proceedings. Under the Natural Gas Act, the Partnership's rates must be
"just and reasonable," as determined by the FERC. In rate review proceedings,
the FERC has the responsibility to ensure that the rates that interstate
pipelines, such as the Partnership's, charge are not greater than those
necessary to enable the pipeline to recover the costs incurred to construct,
own, operate and maintain its pipeline system and to afford the pipeline an
opportunity to earn a reasonable rate of return. Under FERC regulations,
shippers have the opportunity to contest the Partnership's rates and tariff
structure. The Partnership cannot assure you that the FERC will not alter or
refine its preferred methodology for establishing pipeline rates and tariff
structure. It is possible that changes in the FERC's ratemaking policies could
result in lower rates than those the Partnership could charge under the existing
methodology, or could make a large proportion of our rate subject to recovery on
the basis of actual quantities of natural gas that the Partnership transports,
rather than on the basis of firm capacity reservations. Such changes could
therefore adversely affect the Partnership's revenues and ability to service its
senior notes.

         Under the terms of the transportation service contracts and in
accordance with the FERC's rate making principles, the Partnership is only
permitted to recover costs associated with the construction and operation of its
pipeline system which are actually, reasonably and prudently incurred and are
included in its pipeline system's regulatory rate base. There can be no
assurance that all costs the Partnership incurs, including costs we incur in
constructing its expansions, will be recoverable through its rates.

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, if upstream transportation service on the TransCanada System
were to become constrained or if the price of Western Canada natural gas were to
increase significantly, 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.



                                       14
<PAGE>

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

               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, including capacity
                    constraints on the TransCanada System;

               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 basis that is commercially
                    acceptable to the Partnership's shippers and their
                    customers.

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 beyond the Partnership's control. 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.

We face construction and other risks in connection with the Eastchester
Extension

         The Partnership faces development and construction risks typical for
natural gas pipeline expansions, including, but not limited to, labor disputes,
shortages of material and skilled labor, slower than projected construction
progress, the existence of sensitive property owned by third parties and
environmental and geological problems. In addition, there are risks associated
with the construction of a large, mainly underwater, pipeline project such as
the Eastchester Extension. These risks include adverse weather conditions,
unexpected construction conditions, accidents, the breakdown or failure of
construction equipment or processes, catastrophic events such as explosions,
fires and shipwrecks and other similar events beyond our control. As a result of
delays in obtaining certain construction authorizations and permits, and delays
related to construction incidents involving damage being caused to undersea
electric transmission cables in the Long Island Sound, the projected in-service
date of the completed Eastchester Extension is



                                       15
<PAGE>

now late summer or early fall 2003, and the Partnership's management believes
that the final construction costs of the Eastchester Extension will be at least
$250.0 million, rather than the $210.0 million estimated during the FERC
certification process and will likely reduce the Partnership's initial margins
that were anticipated when the project application was filed with the FERC.
There can be no assurance that further similar delays and incidents will not
occur and that additional changes to the in-service date or budget associated
with the Eastchester Extension will not be made and would not have a material
adverse effect on the Partnership's financial condition.

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,
restrictions under the indenture relating to the Partnership's senior notes 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;

               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;

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

               o    laws and regulations, including permit requirements, may
                    become more stringent so as to affect materially the
                    viability of the expansions.

         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.



                                       16
<PAGE>

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 and public
safety. 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 the development or discovery of other
facts or conditions, such as 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 that expires on April 30, 2011. The Partnership has an option to
cancel approximately 4,300 square feet of that space by written notification to
the landlord of the Shelton office no later than December 31, 2003 and by making
a one-time payment to the landlord of approximately $50,000. The cancellation of
that portion of the lease would be effective January 1, 2005. The Partnership
has not yet decided if it will exercise this option. 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 continues to have the
power of eminent domain in each of the states in which it operates its pipeline
system. The Partnership also leases a right-of-way easement on Long Island, New
York, 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

         On November 16, 2002, certain undersea electric transmission cables
owned by the Long Island Power Authority, or LIPA, and Connecticut Light and
Power Company, or CL&P, were allegedly damaged and/or destroyed as a result of
an allision with an anchor deployed by the



                                       17
<PAGE>

DSV Mr. Sonny, a work vessel owned and operated by a subcontractor taking part
in the construction of the Eastchester Extension. In a letter dated January 8,
2003, attorneys for LIPA and CL&P advised that LIPA and CL&P intend to hold
Horizon Offshore Contractors, Inc. (the Partnership's general marine
contractor), Thales Geo Solution Group, Ltd. (Horizon's subcontractor), owners
of DSV Mr. Sonny, the Partnership and IPOC jointly and severally liable for the
full extent of their damages, including emergency response costs, repair of the
electrical cables, loss of use and disruption of services to customers, and any
other damages of whatever nature arising from or related to the incident. LIPA
and CL&P estimate that repair costs will be $33.8 million. In addition, the
Partnership has been informed that the Town of Huntington, New York, may assert
a claim against the Partnership alleging violations of certain municipal
ordinances based on a claim that dielectric fluid was released from the cable as
a result of this incident.

         Under the terms of the construction contract between Horizon and the
Partnership, Horizon is required to indemnify the Partnership for Horizon's
negligence associated with the construction of the Eastchester Extension.
Pursuant to the contract, Horizon named the Partnership as an additional named
insured under Horizon's policies of insurance. The Partnership understands that
the Partnership is covered under such policies to the extent that Horizon has
assumed the liabilities under the contract with the Partnership. In any event,
the Partnership believes it is adequately insured by its own insurers.
Therefore, based on its initial investigation, the Partnership's management
believes that this matter will not have a material adverse effect on the
Partnership's financial condition or results of operations.

         On February 27, 2003, the New York Power Authority, or NYPA, informed
the Partnership that one of four cables that comprise its Y-49 facility, which
is a 600 megawatt undersea electrical power interconnection between Westchester
County and LIPA's transmission system at Sands Point, New York, allegedly
sustained damage causing a rupture and leakage of dielectric fluid. NYPA has
suggested that the damage to the Y-49 cables may have been caused by an anchor
of Horizon's pipeline lay barge, Gulf Horizon, while constructing the
Eastchester Extension. The Partnership is a party to an agreement with NYPA
which provides, among other things, that in the event of damage to Y-49 cables
resulting from the Partnership's or its contractor's negligence, acts, omissions
or willful misconduct, the Partnership will indemnify NYPA for repair costs and
the costs of replacement electrical capacity while the Y-49 cables are out of
service, subject to NYPA's duty to mitigate damages.

         At this time, NYPA has not commenced litigation against the Partnership
or otherwise made a specific written claim for specified damages against the
Partnership as a result of this incident. The Partnership is currently
investigating the incident and evaluating its rights, obligations and
responsibilities relating thereto. Given the preliminary stage of this matter,
at this time, the Partnership is unable to assess the likelihood of an
unfavorable outcome and/or the amount or range of loss, if any, in the event of
an unfavorable outcome. Under the terms of the construction contract between
Horizon and the Partnership, Horizon is required to indemnify the Partnership
for Horizon's negligence associated with the construction of the Eastchester
Extension. Pursuant to the contract, Horizon named the Partnership as an
additional named insured under their policies of insurance. The Partnership
understands that the Partnership is covered under such policies to the extent
that Horizon has assumed the liabilities under the



                                       18
<PAGE>

contract with the Partnership. The Partnership is currently investigating the
applicability of all available insurance coverage.

         The Partnership is a party to various other legal matters incidental 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. See Note 7 to the Consolidated
Financial Statements appearing elsewhere in this annual report.

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, 2002, 2001,
2000, 1999 and 1998 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,
                                                                  -----------------------
                                                   2002         2001         2000        1999        1998
                                                   ----         ----         ----        ----        ----
                                                          (In thousands of dollars, except ratios)
    Income Statement Data:
   <S>                                            <C>            <C>         <C>      <C>           <C>
    Operating revenues...................         $126,320       $128,270    $127,234 $123,919(1)   $140,371
    Operating expenses:
        Operation and maintenance........           26,112         22,108      21,119      21,534     21,703
        Depreciation and amortization....           23,684         23,847      23,609      21,976     29,795
        Taxes other than income taxes....           11,206         10,953      11,156      11,449     10,390
                                                 ---------      ---------   ---------   --------- ----------
          Total operating expenses.......           61,002         56,908      55,884      54,959     61,888
    Operating income.....................           65,318         71,362      71,350      68,960     78,483
     Other income and (expenses).........            2,708          1,829       1,824       1,419    6,758(2)
                                                 ---------      ---------   ---------  ----------  ----------
    Income before interest charges and taxes        68,026         73,191      73,174      70,379     85,241
        Net interest expense.............           25,148         28,067      31,139      30,621     32,476
                                                 ---------      ---------   ---------   ---------  ---------
    Income before taxes..................           42,878         45,124      42,035      39,758     52,765
        Provisions for taxes(3)..........           16,911         18,275      17,083      15,580     20,788
                                                 ---------      ---------   ---------   ---------  ---------
    Net income...........................         $ 25,967       $ 26,849    $ 24,952    $ 24,178   $ 31,977
                                                  --------       --------    --------    --------   --------
    Cash Flow Data:
</TABLE>

                                       19
<PAGE>

<TABLE>
<CAPTION>
    <S>                                           <C>            <C>         <C>         <C>        <C>
    Net cash from operating
        activities.......................         $ 68,782       $ 77,265    $ 57,181    $ 57,961   $ 83,899
    Capital expenditures.................         $109,433        $36,340      $8,268      $7,718    $14,172

    Balance Sheet Data
    (at End of Period):
    Net property, plant and equipment             $621,475       $533,219    $520,172    $534,806   $548,832
    Total assets.........................         $689,385       $591,745    $584,368    $594,851   $606,870
    Long-term debt, including
        current maturities...............         $407,222       $366,666    $388,889    $336,664   $365,388
    Partners' capital....................         $232,073       $190,764    $169,423    $227,388   $212,630
</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 owns and operates 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 at four locations with three interstate pipelines and
also connects with the pipeline system of TransCanada PipeLines Limited at the
Canada-United States border near Waddington, New York.

         On April 19, 2002, the Partnership began constructing its
Eastchester/New York City extension (the "Eastchester Extension"), consisting of
an addition to its pipeline system of approximately 36 miles of 24-inch diameter
pipe, which will extend from the Partnership's existing mainline at Northport in
Suffolk County, New York mostly through the navigable waters of the Long Island
Sound and the East River to Hunts Point in Bronx County, New York. At Hunts
Point, the extension of the Partnership's mainline will form an interconnection
with the New York Facilities Group. As part of the Eastchester Extension, the
Partnership is also



                                       20
<PAGE>

building two new compressor stations in Dover, New York and Boonville, New York.
A portion of the upstream Eastchester Extension facilities have been placed into
service.

         Construction of the Long Island Sound portion of the Eastchester
Extension commenced in October 2002. As a result of delays in obtaining certain
construction authorizations and permits and delays related to construction
incidents, the projected in-service date of the entire Eastchester Extension is
now the late summer or early fall of 2003, and management believes that final
project construction costs will be at least $250.0 million, rather than the
$210.0 million in project costs estimated during the FERC's certification
process and will likely reduce the Partnership's initial margins that were
anticipated when the project application was filed with the FERC. See Note 7 to
the Consolidated Financial Statements included elsewhere in this annual report.

Results of Operations

         The components of Operating Revenues and Volumes Transported for the
past three years are provided in the following table:

                                                         Year ended
  Revenues and Volumes Transported                       December 31,
                                                --------------------------------
                                                2002         2001       2000
                                                ----         ----       ----

  Revenues (dollars in millions)
     Long-term firm reserved service           $114.8     $119.1     $116.3
     Short-term firm (1)                          4.1        5.5        4.7
     Interruptible/other (1)                      7.4        3.7        6.2
                                                  ---       ----        ---
                    Total revenues             $126.3     $128.3     $127.2

  Volumes Transported
        (millions of dekatherms)
     Long-term firm reserved service            300.7      281.8      292.1
     Short-term firm (1)                         11.4       15.7       25.3
     Interruptible/other (1)                     32.3       20.6       30.7
                                                 ----       ----       ----
                    Total volumes transported   344.4      318.1      348.1

(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 firm revenues are
primarily derived from long-term contracts and 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. Interruptible
transportation service 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



                                       21
<PAGE>

transportation 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, and which 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 settling party and resolves all rate matters outstanding from
the Partnership's previous two rate cases. The settlement had no impact on 2000
income. The first rate reduction was implemented January 1, 2001. The settlement
had a negative revenue impact of $2.4 million in 2001 and $6.1 million in 2002,
and is expected to have a negative revenue impact of $3.6 million in 2003, based
upon long-term firm reserved transportation contracts in effect as of December
31, 2002.

         Total revenues for 2002 were $126.3 million, a decrease of $2.0
million from 2001 revenues. Long-term firm revenues for 2002 decreased $4.3
million from 2001 primarily due to a rate decrease of $.024/Dth. The rate
decrease resulted in a $6.1 million decrease in long-term firm revenues for
2002, which was partially offset by the addition of new long-term firm
contracts. Short-term firm revenues for 2002 decreased $1.4 million from 2001
while interruptible/other revenues increased $3.7 million to $7.4 million over
2001 levels due primarily to a shift in demand for services from short-term firm
to interruptible.

         Despite the 2001 rate decrease of $0.01/Dth, long-term firm revenues
for 2001 increased $2.8 million, from $116.3 million in 2000 to $119.1 million,
largely as a result of the addition of a power plant contract to the
Partnership's system in November 2000, as well as additional winter firm
contracts added in 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.

         Operation and Maintenance Expense. Operation and maintenance expense
includes operating, maintenance and administrative expenses for the
Partnership's corporate office in Shelton, Connecticut and field support for the
mainline, metering and compression facilities. Operation and maintenance expense
for 2002 increased $4.0 million over 2001 to $26.1 million primarily due to a
$2.2 million expense related to the Partnership's investment in its Eastern Long
Island Project, which has been withdrawn from the FERC certification process, as
well as increased payroll, benefit, outside service and insurance costs.

         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 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.



                                       22
<PAGE>

         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 $1.0 million to $0.4 million in 2002
compared to 2001 primarily due to a decrease in the interest rate realized from
investments as well as lower average cash balances during 2002. Interest income
decreased approximately $0.8 million to $1.4 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.

         Allowance for equity funds used during construction increased $1.9
million to $2.3 million in 2002 due primarily to the Partnership's expenditures
for the Eastchester Extension. Allowance for equity funds used during
construction increased $0.3 million to $0.4 million in 2001 due primarily to
preliminary expenditures for the Eastchester Extension.

         Interest Expense. Interest expense decreased $0.8 million to $27.9
million in 2002 compared to 2001, primarily due to a lower average long-term
debt balance due to scheduled debt repayments and lower interest rates on
floating rate debt during the first half of 2002, partially offset in the latter
half of 2002 by an increase in the Partnership's average debt balance,
reflecting the Partnership's $170.0 million bond offering completed in August
2002. See Note 3 to the Consolidated Financial Statements included elsewhere in
this annual report.

         Interest expense decreased $2.5 million to $28.7 million in 2001
compared to 2000, primarily due to a lower average long-term debt balance due to
scheduled debt repayments and lower interest rates on floating rate debt in the
latter half of 2001. This decrease was partially offset by an increase of
interest expense in the first half of 2001, reflecting an increase in average
debt balance due to the long-term debt refinancing, which closed May 30, 2000.
See Note 3 to the Consolidated Financial Statements included elsewhere in this
annual report.

         Allowance for borrowed funds used during construction increased $2.1
million to $2.7 million in 2002 due primarily to the Partnership's expenditures
for the Eastchester Extension. Allowance for borrowed funds used during
construction increased $0.6 million to $0.7 million in 2001 due primarily to
preliminary expenditures for the Eastchester Extension.

         Income Taxes. Provision for taxes decreased $1.4 million to $16.9
million in 2002 compared to 2001 due primarily to a decrease in taxable income.
Provision for taxes increased $1.2 million to $18.3 million in 2001 compared to
2000 due primarily to an increase in taxable income.

Critical Accounting Policies and Estimates

         The Partnership's discussion and analysis of its financial condition,
results of operations and cash flows are based upon the Partnership's
consolidated financial statements, which have been prepared in accordance with
accounting principles generally accepted in the United States of America, or
GAAP. The preparation of these consolidated financial statements required
management to make estimates and judgments that affect the reported amount of
assets and liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities at the date of the consolidated financial
statements. Actual results may differ from these estimates under different
assumptions or conditions.



                                       23
<PAGE>

         Critical accounting policies and estimates are defined as those that
are reflective of significant judgment and uncertainties, and potentially may
result in materially different outcomes under different assumptions and
conditions. The Partnership believes that its accounting policies and estimates
that are most critical to the reported results of operations, cash flows and
financial position are described below.

         Regulatory accounting

         The Partnership follows accounting policies prescribed by GAAP and the
FERC. As a rate-regulated Partnership, the Partnership is subject to the
Financial Accounting Standards Board ("FASB") Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation". The application of SFAS 71 results in differences in the timing of
recognition of certain revenues and expenses from that of other businesses and
industries. The Partnership's gas transmission business remains subject to
rate-regulation and continues to meet the criteria for application of SFAS 71.
This ratemaking process results in the recording of regulatory assets based on
current and future cash inflows. Regulatory assets represent incurred costs that
have been deferred because they are probable of future recovery in customer
rates. As of December 31, 2002 and 2001, the Partnership recorded regulatory
assets of $15.7 million and $15.1 million, respectively. The Partnership
continuously reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. The Partnership expects to fully recover
these regulatory assets in its rates. If future recovery of costs ceases to be
probable, the Partnership would be required to charge these assets to current
earnings. However, impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.

         Derivatives and hedging

         The Partnership utilizes derivative contracts to hedge interest rate
risk associated with the Partnership's existing variable rate debt, and to hedge
the net proceeds of new fixed rate debt. SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities", as amended, requires that the Partnership
document its hedging strategies and estimates of hedge effectiveness prior to
initiating a hedge, as well as continuing to assess hedge effectiveness for the
life of the hedging instrument. Currently, the Partnership has two interest rate
swaps outstanding with a total notional amount of $36.1 million, and a fair
value of ($2.8) million, net of taxes. The Partnership records the market value
of these interest rate swaps on its financial statements as a component of Other
Comprehensive Income (Partners' Equity) and Other Non-current Liabilities.

         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



                                       24
<PAGE>

assumptions and estimates, revisions to the estimated reserves for contingent
liabilities would be required. See Note 7 to the Consolidated Financial
Statements included elsewhere in this annual report for information about
regulatory, judicial and business developments that cause operating and
financial uncertainties.

Liquidity and Capital Resources

         The Partnership's primary source of financing has been cash flow from
operations, its May 2000 offering of $200.0 million of senior notes, and its
August 2002 offering of $170.0 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.

         Net cash provided by operating activities decreased to $68.8 million in
2002 compared to $77.3 million in 2001, partially due to an increase in debt
issuance costs associated with the financing completed on August 14, 2002
related to the Eastchester Extension, and more fully described below. 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 Extension and increased net income. Net cash flow related to
financing activities increased by $84.8 million in 2002, as compared to 2001,
due to the Eastchester Extension financing. No new borrowings were made in 2001.
Net cashflow used for financing activities decreased from 2000 to 2001 due
primarily to the transactions surrounding the refinancing of debt in May 2000.

         On August 14, 2002, the Partnership issued $170.0 million of senior
unsecured notes that mature on October 31, 2027. The proceeds from the sale of
the notes were used to repay a portion of the first tranche of term loans under
the Partnership's amended credit agreement. This agreement provides for
borrowings from time to time against a second tranche of term loans in an
aggregate amount not to exceed $120.0 million, which, with cash from operations,
will be used to finance the remaining construction of the Eastchester Extension,
an additional expansion at Athens and for general corporate purposes. As of
December 31, 2002, the debt outstanding under our amended credit agreement was
$37.2 million.

         On August 9, 2000, the Partnership entered into an interest rate swap
agreement to hedge a portion of the interest rate risk on its credit facilities.
The interest rate swap agreement terminates on the last business day in May
2009. Under its terms, the Partnership agreed to pay 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 payment of a floating
rate of 3-month LIBOR on the amortizing notional amount. The Partnership also
agreed to grant an option to the swap counter-party to enter into an additional
interest rate swap agreement. The option was exercised on December 26, 2000 with
a termination date 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. The two interest swap agreements were amended on
August 14, 2002 to match the term of the Partnership's amended credit agreement,
which was also completed on that date. As of



                                       25
<PAGE>

December 31, 2002 and December 31, 2001, the aggregate notional principal amount
of these two swaps was $36.1 million and $41.7 million, respectively. The fair
value of these interest rate swaps, net of taxes at December 31, 2002 and
December 31, 2001, was ($2.8) million and ($1.8) million, respectively.

         On June 19, 2002, the Partnership entered into forward interest rate
agreements with two major financial institutions in the aggregate notional
amount of $120.0 million. On July 31, 2002, the Partnership entered into
additional forward interest rate agreements with the same institutions in the
aggregate notional amount of $50.0 million. The forward interest rate agreements
were entered into to hedge the underlying interest rate for the unsecured senior
notes which the Partnership issued on August 14, 2002. Upon the closing of the
financing transaction, the forward interest rate agreements were terminated and
the Partnership paid $5.8 million to settle those contracts. The Partnership has
deferred and is amortizing this amount over the life of the senior notes.

         The Partnership also is party to a $10.0 million, 364-day, variable
rate revolving line of credit to support working capital requirements. As of
December 31, 2002 and December 31, 2001, there were no borrowings outstanding
under this facility.

         Capital expenditures for 2002 were $109.4 million, compared to $36.3
million in 2001, reflecting primarily the increased construction activity
related to the Eastchester Extension during the year. In addition, there were
expenditures related to a meter station and interconnect, a compressor station,
general plant purchases and other miscellaneous projects. Capital expenditures
in 2001 also consisted of expenditures relating to the Eastchester Extension, as
well as general plant purchases and other minor projects, including a project
currently in the development stage that involves a possible expansion of the
pipeline to access additional gas supplies from the west. In 2000, capital
expenditures of $8.3 million were restricted to some post-completion costs for
the original Athens compressor station, preliminary engineering costs relating
to the Eastchester Extension, as well as general plant purchases and other minor
projects.

         Total capital expenditures for 2003 are estimated to be approximately
$126.0 million, including approximately $106.0 million for the Eastchester
Extension. The remaining capital expenditures planned for 2003 are primarily for
the purchase of land for a compressor site, a meter station and interconnect,
and various general plant purchases. The Partnership expects to fund its 2003
capital expenditures through additional borrowings under its existing credit
facilities, and internal sources, including cash from operations and increased
equity contributions (by limiting distribution to partners) in accordance with
the partnership agreement. The Partnership's management makes recommendations to
the partnership management committee regarding the amount and timing of
distributions to partners. The amount and timing of distributions is subject to
internal cash requirements for construction, financing and operational
requirements. Distributions and cash calls require the approval of the
management committee. There were no cash distributions to partners during 2002.
Total cash distributions to partners of $22.0 million and $100.0 million were
made during 2001 and 2000, respectively. The larger distribution in 2000 was a
result of the May 2000 long-term debt refinancing.



                                       26
<PAGE>

Off-Balance Sheet Transactions

         At December 31, 2002, 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.

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, 2002.

                     Total    2003      2004     2005    2006   2007 Thereafter
                     -----    ----      ----     ----    ----   ---- ----------
                                   (in thousands of dollars)

Long-Term Debt    $407,200  $22,200   $15,000      --      --     --   $370,000
Operating Leases    11,100    1,000       900     800     800    800      6,800
                  --------  -------   -------    ----    ----   ----   --------
Total
Contractual
Obligations       $418,300  $23,200   $15,900    $800    $800   $800   $376,800
                  ========  =======   =======    ====    ====   ====   ========

New Accounting Standards


         In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations", which 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. The Partnership does
not expect the implementation of SFAS 143 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 supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of" 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 has not
had a material impact on the Partnership's financial position or results of
operations.

         In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities", which nullifies Emerging Issues
Task Force Issue No. 94-3,



                                       27
<PAGE>

"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)". The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002. Implementation of this standard is not
expected to have a material impact on the Partnership's financial position or
results of operations.

         FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others" is effective for the year ended December 31, 2002. FASB Interpretation
No. 45 elaborates on the disclosures to be made by a guarantor about its
obligations under certain guarantees it has issued. It also clarifies that a
guarantor is required to recognize, at the inception of a guarantee, a liability
for the fair value of the obligation undertaken in issuing the guarantee. The
initial recognition and initial measurement provisions of FASB Interpretation
No. 45 are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002, however the disclosure requirements are effective with
respect to the 2002 financial statements contained in this annual report. The
application of this Interpretation is not expected to materially impact the
financial position, results of operations, or cash flows of the Company.

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
all 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 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.


                                       28
<PAGE>

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. 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 Consolidated Financial Statements included
elsewhere in this annual report. As of December 31, 2002, the Partnership had
$37.2 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 less than $0.1 million.

         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-2 through F-24 of this
report.


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

         None.



                                       29
<PAGE>

                                   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                52    President*
Paul Bailey                  56    Vice President and Chief Financial Officer
Jeffrey A. Bruner            44    Vice President, General Counsel and Secretary
Herbert A. Rakebrand III     46    Vice President, Marketing and Transportation
David J. Warman              45    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.

         Herbert A. Rakebrand III is Vice President of Marketing and
Transportation of IPOC. Mr. Rakebrand has 23 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

--------------------
     * Mr. Frew has indicated that he will be resigning as President of the
Partnership in April 2003 and the Partnership expects to announce a new
President at that time.



                                       30
<PAGE>

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.
<TABLE>
<CAPTION>

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

 <S>                  <C>    <C>                            <C>
  Georgia B. Carter   45     Dominion Resources, Inc.       Dominion Iroquois, Inc.

  Michael I. German   52     Energy East                    TEN Transmission Company


  Richard A. Rapp     53     KeySpan Energy Corporation     NorthEast Transmission
                                                            Company, LILCO Energy
                                                            Systems, Inc.

  Joseph P. Shields   45     New Jersey Natural Gas Company NJNR Pipeline Company

  Peter Lund          44     PG&E National Energy Group     JMC-Iroquois, Inc.
                                                            Iroquois Pipeline
                                                            Investment, LLC

  Paul MacGregor      46     TransCanada Pipelines Ltd.     TransCanada Iroquois
                                                            Ltd./TCPL Northeast Ltd.
</TABLE>


         Georgia B. Carter is Managing Counsel for Gas Transmission and Storage
for Dominion Resources Inc. Prior to this position, she served as Senior Counsel
for Dominion Resource Services, Inc. Ms. Carter joined Consolidated Gas Supply
Company as an attorney in 1983, became General Manager Marketing in 1993, and
was promoted to Vice President, Marketing and Customer Services in 1996.
Subsequent to the merger of Dominion Resources, Inc. and Consolidated Natural
Gas Company in January 2000, she held the same position until a reorganization
in late 2001.



                                       31
<PAGE>

         Michael I. German is Senior Vice President of the Energy East
Management Corporation, and President, CEO and board representative for the
companies within The Energy Network and Energy East Enterprises. He is
responsible for growth and business development across these businesses. Mr.
German also represents Energy East on the management committee for Iroquois Gas
Transmission System. Prior to this, Mr. German was President and COO of NYSEG,
and before joining NYSEG was the AGA's Sr. Vice President. He also worked for
the U.S. Department of Energy and the Energy Research and Development
Administration. Mr. German is a member of the Washington, DC Bar Association.

         Richard A. Rapp is Senior Vice President of KeySpan Energy Supply, Inc.
Until March 2003, he was the Vice President and Deputy General Counsel of
KeySpan Corporation. Mr. Rapp served in various attorney and supervisory
positions in KeySpan's Legal Department, beginning in August 1984.

          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 is the Vice President-Pipeline Marketing and Development of
PG&E National Energy Group. He has led the commercial aspects of PG&E's
interstate pipeline operations since becoming Vice President of PG&E Gas
Transmission - Northwest in 1995. 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 and chair-elect of the Western Energy 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.

ITEM 11. EXECUTIVE COMPENSATION

         Summary Compensation Table. The following summary compensation table
sets forth information regarding compensation for fiscal years 2002, 2001 and
2000 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.

                                       32
<PAGE>

<TABLE>
<CAPTION>
                                                                                 Other Annual         All Other
  Name and                                        Salary           Bonus         Compensation        Compensation
  Principal Position                Year          ($) (1)           ($)             ($)(2)             ($) (3)
  ------------------               --------       -------           ---             ------             -------

 <S>                                 <C>         <C>              <C>                  <C>               <C>
  Craig R. Frew                      2002        $270,169.12      $108,100.00                ---         $232,725.00
       President                     2001         297,231.80       160,000.00                ---          137,347.00
                                     2000         262,058.23       125,000.00          65,598.34           10,500.00

  Paul Bailey                        2002        $193,089.42       $57,000.00                ---         $106,122.20
       Vice President and Chief      2001         186,200.04        84,000.00                ---           64,181.70
       Financial Officer             2000         184,293.98        55,000.00          72,429.11            9,448.94

  Jeffrey A. Bruner                  2002        $157,103.91       $39,100.00                ---          $59,409.00
       Vice President, General       2001         150,000.24        60,000.00                ---           37,180.77
       Counsel and Secretary         2000         148,580.38        44,000.00                ---            7,428.98

  Herbert A. Rakebrand III           2002        $190,895.76       $54,400.00                ---          $79,268.01
       Vice President, Marketing     2001         177,107.86        65,000.00                ---           48,668.00
       and Transportation            2000         164,588.58        73,000.00                ---            8,089.90

  David J. Warman                    2002        $144,853.33       $35,000.00                ---          $58,584.92
       Vice President,               2001         131,257.96        54,000.00                ---           36,162.50
       Engineering                   2000         126,011.79        37,000.00                ---            6,190.08
       and Operations
</TABLE>

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

(1)  Amounts reported for the 2000, 2001, and 2002 fiscal years, respectively
     include salary paid in lieu of vacation for the following: Mr. Frew --
     $4,754.25, $3,492.70, and $0; Mr. Bailey, $0, $0, and $3165.40, Mr. Bruner,
     $0, $0, and $653.85, Mr. Rakebrand -- $2,788.50, $4,307.70, and $9455.28;
     and Mr. Warman -- $2,211.75, $1,657.84, and $4884.93 respectively.

(2)  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.

(3)  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, 2002. The general terms of the
     long-term incentive plan are discussed below in a separate section. For
     fiscal year 2002, the named executive officers became entitled to receive
     the following amounts under the long-term incentive plan: Mr. Frew became
     entitled to receive $220,725.00; Mr. Bailey became entitled to receive
     $95,647.00; Mr. Bruner became entitled to receive $51,502.00; Mr. Rakebrand
     became entitled to receive $69,896.00; and Mr. Warman became entitled to
     receive $51,502.00. Another 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 2000, 2001
     and 2002 fiscal years, respectively under the 401(k) Plan: Mr. Frew
     received $8,500, $8,500 and $10,000; Mr. Bailey received $8,500, $8,500.00,
     and $9,580.70; Mr. Bruner received $7,428.98,



                                       33
<PAGE>

     $7,582.77 and $7,907.00; Mr. Rakebrand received $8,089.90, $8,500; and
     $9,147.50, and Mr. Warman received $6,190.08, $6,564.50, and $7082.92
     respectively. In addition, the following amounts were received during the
     2000, 2001, and 2002 fiscal years, respectively under the Supplemental
     Plan: Mr. Frew received $2,000 for each year; Mr. Bailey received $948.94,
     $714.70, and $894.50 for each year respectively, and Mr. Rakebrand received
     $0, $0, and $224.51 for each year respectively.

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.

       The following table provides information concerning the Performance Units
granted to the named executive officers in fiscal year 2002.

                                                              Estimated Future
                                        Performance Period     Payouts Under
                              Number      Until Maturation        Non-Stock
Name                         of Units        or Payout       Price-Based Plan(4)
----                        ---------    ------------------  -------------------

Craig R. Frew                   150(1)     2003-2004          $117,259.00
                                 75(2)     2003-2005           $54,866.00
                                 75(3)     2003-2006           $42,239.00


Craig R. Frew (5)               170(6)     2002-2003          $152,395.00
                                 85(7)     2002-2004           $68,691.00
                                 85(8)     2002-2005           $71,851.00


Paul Bailey                      60(1)     2003-2004           $46,904.00
                                 30(2)     2003-2005           $21,946.00
                                 30(3)     2003-2006           $19,695.00


Paul Bailey (5)               72.50(6)     2002-2003           $64,992.00
                              36.25(7)     2002-2004           $29,295.00
                              36.25(8)     2002-2005           $30,642.00


                                       34
<PAGE>

Jeffrey A. Bruner                40(1)     2003-2004           $31,269.00
                                 20(2)     2003-2005           $14,631.00
                                 20(3)     2003-2006           $13,130.00


Jeffrey A. Bruner (5)            45(6)     2002-2003           $40,340.00
                              22.50(7)     2002-2004           $18,183.00
                              22.50(8)     2002-2005           $19,019.00


Herbert A. Rakebrand III         55(1)     2003-2004          $42,995.00
                              27.50(2)     2003-2005           $20,117.00
                              27.50(3)     2003-2006           $18,054.00


Herbert A. Rakebrand III (5)     60(6)     2002-2003           $53,787.00
                                 30(7)     2002-2004           $24,244.00
                                 30(8)     2002-2005           $25,359.00


David J. Warman                  40(1)     2003-2004           $31,269.00
                                 20(2)     2003-2005           $14,631.00
                                 20(3)     2003-2006           $13,130.00


David J. Warman (5)              45(6)     2002-2003           $40,340.00
                              22.50(7)     2002-2004           $18,183.00
                              22.50(8)     2002-2005           $19,019.00


---------------------------------------
(1)  Grants vest in full on December 31, 2004.

(2)  Grants vest in full on December 31, 2005.

(3)  Grants vest in full on December 31, 2006.

(4)  The estimated future payout values under the performance share unit plan
     are estimated solely for purposes of this annual report based on certain
     management projections. The actual amount of the payouts under the
     performance plan may be lesser or greater than these estimates. Management
     makes no guarantees about IPOC's actual performance during the performance
     periods.

(5)  These grants were made in 2001. The 2001 grants were erroneously excluded
     from the 2001 Form 10-K.

(6)  Grants vest in full on December 31, 2003.

(7)  Grants vest in full on December 31, 2004.

(8)  Grants vest in full on December 31, 2005.


                                       35
<PAGE>

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 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 2003 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

                                       Years of Service
--------------------------------------------------------------------------------
   Remuneration       15            20           25           30            35
--------------------------------------------------------------------------------
     150,000         42,776       63,051        90,961       121,932     164,797
     200,000         58,518       86,376       124,606       167,369     226,363
     250,000         74,259      109,700       158,297       212,806     287,927
     300,000         90,001      133,024       191,987       258,243     349,494
     350,000        105,742      156,348       225,676       303,680     411,058
     400,000        121,484      179,673       259,367       349,117     472,624
     450,000        137,225      202,997       293,057       394,554     534,191
     500,000        152,967      226,321       326,746       439,991     595,756

         The number of years of credited service, as of December 31, 2002, for
Messrs. Frew, Bailey, Bruner, Rakebrand and Warman are 26.50, 20.33, 10.58,
11.33 and 20.42, 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



                                       36
<PAGE>

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.

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 human resources committee, a sub-committee composed of members of
the management committee, determines the policies applicable to the manner in
which the Partnership's executives are compensated. The members of the human
resources committee are representatives from Keyspan, Dominion and TransCanada.
None of the members of the human resources 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>
<CAPTION>

                                                                    General        Limited
                                                                    Partner        Partner      Total Partnership
  Ultimate Parent                Name of Partner                    Interest       Interest         Interest
  ---------------                ---------------                    --------       --------         --------

  <S>                            <C>                                 <C>             <C>              <C>
  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%
</TABLE>



                                       37
<PAGE>

<TABLE>
<CAPTION>

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

  Energy East Corporation        TEN Transmission Company             4.46%           .41%              4.87%

  New Jersey Resources           NJNR Pipeline Company                3.28%            --               3.28%
      Corporation
</TABLE>


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. Approximately 46% of natural gas under long-term firm
contract was transported by affiliates of partners for the year ended December
31, 2002.

ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

         Within 90 days prior to the date of the filing of this report, the
Partnership carried out an evaluation, under the supervision and with the
participation of the Partnership's management, including the President and the
Chief Financial Officer, of the design and operation of the Partnership's
disclosure controls and procedures. Based on this evaluation, the President and
Chief Financial Officer have concluded that the Partnership's disclosure
controls and procedures (as defined in Rules 10a-14 and 15d-14 under the
Securities Exchange Act of 1934) are effective for gathering, analyzing and
disclosing the information the Partnership is required to disclose in the
reports it files under the Securities Exchange Act of 1934, within the time
periods specified in the rules and forms of the Securities and Exchange
Commission and that such information is accumulated and communicated to the
Partnership's management, including the President and the Chief Financial
Officer, as appropriate to allow timely decisions regarding required
disclosures.

Changes in Internal Controls

         There have been no significant changes in the Partnership's internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of the evaluation referred to above.




                                       38
<PAGE>

                                    PART IV.

ITEM 15. 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    Second Supplemental Indenture dated as of August 13, 2002 between
            the Partnership and JPMorgan Chase Bank (formerly known as the Chase
            Manhattan Bank), as trustee, paying agent, securities registrar and
            transfer agent for $170,000,000 aggregate principal amount of 6.10%
            senior notes due 2027.

     4.3*   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.

     4.4*   Form of Exchange Note.

     4.5*   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   Amendment No. 1 to Credit Agreement, dated as of July 30, 2002,
            among the Partnership, the several banks and other financial
            institutions from time to time party thereto, and JPMorgan Chase
            Bank (formerly known as the Chase Manhattan Bank), as administrative
            agent.



                                       39
<PAGE>

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

     10.4*  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.

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

     10.6*  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.

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

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

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

     10.10* 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.

     99.1   Certification pursuant to 18 U.S.C. Section 1850, as adopted
            pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

(b) Reports on Form 8-K

    Current Report on Form 8-K filed October 7, 2002 (Press Release, Item 5).


                                       40
<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 28, 2003            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 28, 2003.

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

/s/ Paul Bailey                   Vice President and Chief Financial
---------------------------       Officer of Iroquois Pipeline
Paul Bailey                       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/ Richard A. Rapp               Representative on the Management Committee
---------------------------
Richard A. Rapp

/s/ Georgia B. Carter             Representative on the Management Committee
---------------------------
Georgia B. Carter

/s/ Michael I. German             Representative on the Management Committee
---------------------------
Michael I. German



                                       41
<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




                                       42
<PAGE>



                                 CERTIFICATIONS

I, Craig R. Frew, the principal executive officer of Iroquois Gas Transmission
System, L.P., certify that:

1.   I have reviewed this annual report on Form 10-K of Iroquois Gas
     Transmission System, L.P.;

2.   Based on my knowledge, this annual report does not contain any untrue
     statement of a material fact or omit to state a material fact necessary in
     order to make the statements made, in light of the circumstances under
     which such statements were made, not misleading with respect to the period
     covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual report, fairly present in all material
     respects the financial condition, results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

  a.  Designed such disclosure controls and procedures to ensure that material
      information relating to the registrant, including its consolidated
      subsidiaries, is made known to us by others within those entities,
      particularly during the period in which this annual report is being
      prepared;

  b.  Evaluated the effectiveness of the registrant's disclosure controls and
      procedures as of a date within 90 days prior to the filing date of this
      annual report (the "Evaluation Date"); and

  c.  Presented in this annual report our conclusions about the effectiveness of
      the disclosure controls and procedures based on our evaluation as of the
      Evaluation Date;

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation, to the registrant's auditors and the audit
     committee of registrant's board of directors (or persons performing the
     equivalent function):

  a.  All significant deficiencies in the design or operation of internal
      controls which could adversely affect the registrant's ability to record,
      process, summarize and report financial data and have identified for the
      registrant's auditors any material weaknesses in internal controls; and

  b.  Any fraud, whether or not material, that involves management or other
      employees who have a significant role in the registrant's internal
      controls; and



                                       43
<PAGE>

6.   The registrant's other certifying officer and I have indicated in this
     annual report whether or not there were significant changes in internal
     controls or in other factors that could significantly affect internal
     controls subsequent to the date of our most recent evaluation, including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.


                                                 /s/ Craig R. Frew
                                                 -------------------------------
                                                 Craig R. Frew
                                                 President
DATE: March 28, 2003

                                       44
<PAGE>

I, Paul Bailey, Chief Financial Officer of Iroquois Gas Transmission System,
L.P., certify that:

1.   I have reviewed this annual report on Form 10-K of Iroquois Gas
     Transmission System, L.P.;

2.   Based on my knowledge, this annual report does not contain any untrue
     statement of a material fact or omit to state a material fact necessary in
     order to make the statements made, in light of the circumstances under
     which such statements were made, not misleading with respect to the period
     covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual report, fairly present in all material
     respects the financial condition, results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

  a.  Designed such disclosure controls and procedures to ensure that material
      information relating to the registrant, including its consolidated
      subsidiaries, is made known to us by others within those entities,
      particularly during the period in which this annual report is being
      prepared;

  b.  Evaluated the effectiveness of the registrant's disclosure controls and
      procedures as of a date within 90 days prior to the filing date of this
      annual report (the "Evaluation Date"); and

  c.  Presented in this annual report our conclusions about the effectiveness of
      the disclosure controls and procedures based on our evaluation as of the
      Evaluation Date;

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation, to the registrant's auditors and the audit
     committee of registrant's board of directors (or persons performing the
     equivalent function):

  a.  All significant deficiencies in the design or operation of internal
      controls which could adversely affect the registrant's ability to record,
      process, summarize and report financial data and have identified for the
      registrant's auditors any material weaknesses in internal controls; and

  b.  Any fraud, whether or not material, that involves management or other
      employees who have a significant role in the registrant's internal
      controls; and

6.   The registrant's other certifying officer and I have indicated in this
     annual report whether or



                                       45
<PAGE>

     not there were significant changes in internal controls or in other factors
     that could significantly affect internal controls subsequent to the date of
     our most recent evaluation, including any corrective actions with regard to
     significant deficiencies and material weaknesses.


                                                  /s/ Paul Bailey
                                                --------------------------------
                                                Paul Bailey
                                                Vice President and
                                                   Chief Financial Officer
DATE: March 28, 2003

<PAGE>


                          INDEX TO FINANCIAL STATEMENTS

                                                                            Page

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

Financial Statements

      Consolidated Statements of Income for the years ended December 31,
              2002, 2001 and 2000............................................F-3

         Consolidated Balance Sheets as of December 31, 2002
              and 2001.......................................................F-4

         Consolidated Statements of Cash Flows for the years
              ended December 31, 2002, 2001 and 2000.........................F-6

         Statements of Changes in Partners' Equity for the years
              ended December 31, 2002, 2001, 2000 and 1999...................F-8

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



                                      F-1
<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS

           TO THE PARTNERS 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, 2002 and 2001, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
2002 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 standards 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 our opinion.


                                                      PricewaterhouseCoopers LLP

                                                           Boston, Massachusetts

                                                                February 7, 2003







                                      F-2
<PAGE>




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


                                                (thousands of dollars)
FOR THE YEARS ENDED DECEMBER 31               2002        2001          2000

OPERATING REVENUES                          $126,320     $128,270     $127,234

OPERATING EXPENSES:
  Operation and maintenance                   26,112       22,108       21,119
  Depreciation and amortization               23,684       23,847       23,609
  Taxes other than income taxes               11,206       10,953       11,156
                                            --------     --------     --------
    Total Operating Expenses                  61,002       56,908       55,884
                                            --------     --------     --------
OPERATING INCOME                              65,318       71,362       71,350
                                            --------     --------     --------

OTHER INCOME/(EXPENSES):
  Interest income                                416        1,412        2,203
  Allowance for equity funds used
    during construction                        2,319          444          126
  Other, net                                     (27)         (27)        (505)
                                            --------     --------     --------
                                               2,708        1,829        1,824
                                            --------     --------     --------

Income Before Interest Charges
  and Taxes                                   68,026       73,191       73,174

INTEREST EXPENSE:
  Interest expense                            27,892       28,736       31,283
  Allowance for borrowed funds
    used during construction                  (2,744)        (669)        (144)
                                            --------     --------     --------
    Net Interest Expense                      25,148       28,067       31,139

INCOME BEFORE TAXES                           42,878       45,124       42,035

PROVISION FOR TAXES                           16,911       18,275       17,083
                                            --------     --------     --------
NET INCOME                                   $25,967      $26,849      $24,952
                                            ========     ========     ========

   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                                       2002               2001

CURRENT ASSETS:
  Cash and temporary cash investments              $21,620            $21,715
  Accounts receivable - trade, net                   6,384              6,480
  Accounts receivable - affiliates                   5,470              5,267
  Other current assets                               3,838              3,505
                                                  --------           --------
    Total Current Assets                            37,312             36,967
                                                  --------           --------

NATURAL GAS TRANSMISSION PLANT:
  Natural gas plant in service                     796,647            776,961
  Construction work in progress                    125,951             40,659
                                                  --------           --------
                                                   922,598            817,620
  Accumulated depreciation and amortization       (301,123)          (284,401)
                                                  --------           --------
    Net Natural Gas Transmission Plant             621,475            533,219
                                                  --------           --------

OTHER ASSETS AND DEFERRED CHARGES:
  Regulatory assets - income tax related            14,080             13,298
  Regulatory assets - other                          1,661              1,850
  Other assets and deferred charges                 14,857              6,411
                                                  --------           --------
    Total Other Assets and Deferred Charges         30,598             21,559
                                                  --------           --------
    TOTAL ASSETS                                  $689,385           $591,745
                                                  ========           ========

   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                                         2002          2001

CURRENT LIABILITIES:
  Accounts payable                                   $ 16,703      $ 7,655
  Accrued interest                                      6,839        2,909
  Current portion of long-term debt (Note 3)           22,222       22,222
  Accrued property taxes                                3,780        4,001
  Other current liabilities                             3,999        3,377
                                                     --------      --------
   Total Current Liabilities                           53,543       40,164
                                                     --------      --------
LONG-TERM DEBT (NOTE 3)                               385,000      344,444
                                                     --------      --------
OTHER NON-CURRENT LIABILITIES:
  Unrealized loss-interest rate hedge (Note 2)          4,635        1,783
  Other non-current liabilities                         2,281        1,292
                                                     --------      --------
    Total Other Non-Current Liabilities                 6,916        3,075
                                                     --------      --------
AMOUNTS EQUIVALENT TO
 DEFERRED INCOME TAXES:
  Generated by Partnership                            100,355       88,623
  Payable by Partners                                 (86,275)     (75,325)
  Related to Other Comprehensive Income                (2,227)          --
                                                     --------      --------
    Total Amounts Equivalent to Deferred
    Income Taxes                                       11,853       13,298
                                                     --------      --------
COMMITMENTS AND CONTINGENCIES (NOTE 7)                     --           --
   TOTAL LIABILITIES                                  457,312      400,981
PARTNERS' EQUITY                                      232,073      190,764
                                                     --------      --------
  TOTAL LIABILITIES AND
  PARTNERS' EQUITY                                   $689,385     $591,745
                                                     ========     ========

   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                             2002       2001        2000

CASH FLOWS FROM OPERATING ACTIVITIES:
 <S>                                                      <C>         <C>         <C>
  Net Income                                              $25,967     $26,849     $24,952
  Adjusted for the following:
    Depreciation and amortization                          23,684      23,847      23,609
    Allowance for equity funds used
      during construction                                  (2,319)       (444)       (126)
    Deferred regulatory assets-income tax related            (782)        336        (867)
    Amounts equivalent to deferred income taxes               782        (336)        867
    Income and other taxes payable by Partners             16,911      18,275      17,083
    Other assets and deferred charges                      (8,446)        718      (5,567)
    Other non-current liabilities                             257         803          --
    Changes in Working Capital:
        Accounts receivable                                  (107)      1,575        (944)
       Other current assets                                  (544)       (367)        284
       Accounts payable                                     9,048       4,016         346
       Accrued interest                                     3,930          --      (1,872)
       Other liabilities                                      401       1,993        (584)
                                                        ---------     -------    ---------

NET CASH PROVIDED BY
OPERATING ACTIVITIES:                                      68,782      77,265      57,181
                                                        ---------     -------    ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures                                   (109,433)    (36,340)     (8,268)
                                                        ---------     -------    ---------
   NET CASH USED FOR INVESTING ACTIVITIES                (109,433)    (36,340)     (8,268)
                                                        ---------     -------    ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
  Partner distributions                                        --     (22,000)   (100,000)
  Long-term debt borrowings                               205,000          --     400,000
  Repayments of long-term debt                           (164,444)    (22,223)   (347,775)
  Short-term borrowings (repayments)                           --          --      (3,500)
                                                        ---------     -------    ---------
    NET CASH PROVIDED BY / (USED FOR)
    FINANCING ACTIVITIES                                   40,556     (44,223)    (51,275)
                                                        ---------     -------    ---------

DECREASE IN CASH AND
  TEMPORARY CASH INVESTMENTS                                  (95)     (3,298)     (2,362)

CASH AND TEMPORARY CASH INVESTMENTS
   AT BEGINNING OF YEAR                                    21,715      25,013      27,375
                                                        ---------     -------    ---------
</TABLE>

                                      F-6
<PAGE>
<TABLE>
<CAPTION>

<S>                                                       <C>         <C>         <C>
CASH AND TEMPORARY CASH
  INVESTMENTS AT END OF YEAR                              $21,620     $21,715     $25,013

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
  CASH PAID FOR INTEREST                                  $23,060     $28,011     $32,628
</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


        PARTNERS' EQUITY                                (thousands of dollars)

        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                     (1,783)
                                                               -----------

        Balance at December 31, 2001                             $190,764

          Net income 2002                                          25,967
          Taxes payable by Partners                                16,911
          Equity distributions to Partners                              -
          Other comprehensive loss, net of tax                     (1,569)
                                                               -----------

        Partners' Equity
        BALANCE AT DECEMBER 31, 2002                             $232,073
                                                                 ========



                                      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 that owns and operates 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, 2002, 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%). 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. There were no cash distributions to Partners during 2002. Total cash
distributions of $22.0 million and $100.0 million were made during 2001 and
2000.

         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 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.



                                      F-9
<PAGE>

         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 $21.6 million at December
31, 2002 and $21.7 million at December 31, 2001 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, 2002, construction work in progress included
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.

         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.



                                      F-10
<PAGE>

         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.

         New Accounting Standards

         In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("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.
Implementation of this standard will not 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-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 did not have a material impact on the Company's financial position
or results of operations.

         In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities", ("SFAS 146") which nullifies
Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)". The provisions of SFAS No. 146 are
effective for exit or disposal activities that are initiated after December 31,
2002. Implementation of this standard is not expected to have a material impact
on the Company's financial position or results of operations.

         FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others" is effective for the year ended December 31, 2002. FASB Interpretation
No. 45 elaborates on the disclosures to be made by a guarantor about its
obligations under certain guarantees it has issued. It also clarifies that a
guarantor is required to recognize, at the inception of a guarantee, a liability
for the fair value of the obligation undertaken in issuing the guarantee. The
initial recognition and initial measurement provisions of FASB Interpretation
No. 45 are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002, however the disclosure requirements are effective with
respect to the 2002 financial statements contained in this annual report. The




                                      F-11
<PAGE>

application of this Interpretation is not expected to materially impact the
financial position, results of operations, or cash flows of the Company.

                  Other Comprehensive Income

         Comprehensive Income consisted of the following:

         At December 31,                                   2002         2001
         ---------------                                   ----         ----

         NET INCOME:                                     $ 25,967     $ 26,849
                                                         --------     --------
         OTHER COMPREHENSIVE LOSS:
         Unrealized loss on interest rate hedge            (1,644)      (2,991)
         Tax effect                                           642        1,207
                                                         --------     --------
         Unrealized loss on interest rate hedge,
           net of tax                                      (1,002)      (1,783)
                                                         --------     --------
         Additional minimum liability on pension plan        (944)          --
         Tax effect                                           377           --
                                                         --------     --------
         Additional minimum liability on pension plan,
           net of tax                                        (567)          --
                                                         --------     --------
         Comprehensive Income                            $ 24,398     $ 25,066

         NOTE 3

         FINANCING:

         On May 30, 2000, Iroquois completed a private offering of $200.0
million of 8.68% senior unsecured notes due 2010, which were exchanged in a
registered offering for notes with substantially identical terms on September
25, 2000 ("8.68% Senior Notes"). Also on May 30, 2000, Iroquois entered into a
credit agreement with certain financial institutions providing for a term loan
facility of $200.0 million ("Term Loan Facility") and a $10.0 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. Prior to the amendment discussed below,
the Term Loan Facility was scheduled to be amortized over nine years. The
proceeds from the 8.68% Senior Notes and the Term Loan Facility were used to
repay borrowings under prior loan agreements, terminate related interest rate
swap agreements, make a cash distribution to Iroquois' partners of $40.0
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 the $0.9 million 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 its credit facilities. This



                                      F-12
<PAGE>

interest rate swap agreement was effective on August 30, 2000 with a termination
date on the last business day in May 2009. Pursuant to the terms of this
interest rate swap agreement, Iroquois 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 with a termination date 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. The two interest swap agreements were
amended on August 14, 2002 to match the term of the amended credit agreement
which was also completed on that date. As of December 31, 2002 and December 31,
2001, the aggregate notional principal amount of these two swaps was $36.1
million and $41.7 million, respectively. The fair value of these interest rate
swaps, net of taxes at December 31, 2002 and December 31, 2001, was ($2.8)
million and ($1.8) million, respectively.

         On June 19, 2002, the Company entered into forward interest rate
agreements with two major financial institutions in the aggregate notional
amount of $120.0 million. On July 31, 2002, the Company entered into additional
forward interest rate agreements with the same institutions in the aggregate
notional amount of $50.0 million. The forward interest rate agreements were
entered into to hedge the underlying interest rate for the unsecured senior
notes which the Company issued on August 14, 2002. Upon the closing of the
financing transaction, the forward interest rate agreements were terminated and
the Company paid $5.8 million to settle those contracts. Iroquois has deferred
and is amortizing this amount over the life of the senior notes.

         On August 14, 2002, Iroquois issued $170.0 million of 6.1% senior
unsecured notes ("6.1% Senior Notes") that mature on October 31, 2027. The
proceeds from the sale of the notes were used to repay a portion of the first
tranche of term loans under the Company's amended credit agreement. This
agreement provides for borrowings from time to time against a second tranche of
term loans, which, with cash from operations, are being used to finance the
construction of the Company's Eastchester Extension and for general corporate
purposes. The Company's amended credit facilities provide for a second tranche
of term loans in an aggregate amount not to exceed $120.0 million to be drawn
over a twelve month period. In addition, the amended credit agreement provides
for a change to the fixed rate on the interest swap agreement to 6.875% and
changed the maturity date of the Term Loan Facility to June 30, 2008.

         At December 31, 2002 and December 31, 2001, the outstanding principal
balance on the 8.68% Senior Notes was $200.0 million. At December 31, 2002, the
outstanding principal balance on the 6.1% Senior Notes was $170.0 million. At
December 31, 2002 and December 31, 2001, the outstanding principal balance on
the Term Loan Facility was $37.2 million and $166.7 million, respectively. As of
December 31, 2002 and December 31, 2001, there were no amounts outstanding under
the revolving credit facility. The combined schedule of repayments at December
31, 2002 is as follows (millions of dollars):



                                      F-13
<PAGE>

                                 Year                 Scheduled Repayment
                                 ----                 -------------------

                                 2003                      $ 22.2
                                 2004                      $ 15.0
                                 2005                      $ --
                                 2006                      $ --
                                 2007                      $ --
                                 Thereafter                $370.0


         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.

         As of December 31, 2002 and December 31, 2001, 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. As of December 31, 2002 and December
31, 2001, the carrying amounts and estimated fair values of the Company's
long-term debt including current maturities were as follows (in thousands of
dollars):



                                      F-14
<PAGE>



                                          Carrying
                             Year          Amount         Fair Value
                             ----          ------         ----------

                             2002         $407,222          $439,322
                             2001         $366,666          $384,550

         NOTE 6

         GAS TRANSPORTATION CONTRACTS:

         As of December 31, 2002, Iroquois was providing firm reserved
transportation service to 34 shippers of 1064.4 MDth/d of natural gas, which
breaks down as follows:


                             Remaining
                             Term in Years           Quantity in MDth/d
                             -------------           ------------------
                             1-5                           142.7
                             6-10                          631.3
                             11-15                         196.4
                             16-20                          94.0
                                                      ----------
                             Total                       1,064.4
                                                      ===========

         The long-term firm service gas transportation contracts expire between
May 1, 2003 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 $.048 cents per Dth (approximately $.01 cent in 2001, an
additional $.024 cents in 2002 and an additional $.014 cents in 2003). In 2001
and 2002 the settlement resulted in reductions in revenue of $2.4 million and
$6.1 million, respectively. Based on 2002 long-term firm service contracts, the
settlement will result in reductions in revenues of $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.



                                      F-15
<PAGE>

         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, 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. In an order issued October 31, 2002
the Commission generally accepted Iroquois' December 10 filing. On November 15,
2002 Iroquois submitted an additional filing in compliance with the October 31
Order. That compliance filing was opposed in part by one of Iroquois' shippers.
By order dated February 6, 2003, the Commission accepted Iroquois' November 15
filing with one minor exception-Iroquois was required to revise the tariff
definition of "Segment". This compliance filing was submitted on February 19,
2003 and is still pending before the Commission. In addition, filings in
compliance with the Commission's policies on segmentation and flexible point
rights were submitted on November 26, 2002 and December 31, 2002. These three
compliance filings are still pending before the Commission. 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,
as subsequently modified, Iroquois would construct and operate certain
facilities, including additional compression facilities and approximately 36
miles of pipeline and associated facilities from Northport, Long Island to the
Bronx, New York. Those proposed facilities would provide 230 MDth/d of natural
gas per day to the New York City area. The Partnership 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 Commission certificate required 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. However, certain Eastchester shippers, that were obligated under
the precedent agreements to execute firm transportation service agreements,
indicated an unwillingness to do so. Therefore, on February 28, 2002, the




                                      F-16
<PAGE>

Partnership filed a request with the Commission to modify the condition in the
December 26 Order and to permit the Partnership to commence construction with
executed service contracts for 65% of the full 230 MDth/d of service. This
request was granted by the Commission in an order dated March 13, 2002. The
Company currently has contracted with shippers for 210 MDth/d of service on the
Eastchester facilities.

         On April 19, 2002, the Company began constructing its Eastchester
Expansion Project, and a portion of the upstream facilities have been placed
into service. Construction of the Long Island Sound portion of the project
commenced in October, 2002. As a result of delays in obtaining certain
construction authorizations and permits and delays related to construction
incidents, the projected in-service date of the entire Eastchester Expansion
Project is now late summer or early fall of 2003, and management believes that
final project construction costs will be at least $250.0 million, rather than
the $210.0 million estimated during the Commission's certificate process, and
will likely reduce the Company's initial margins that were anticipated when the
project application was initially filed with the FERC. See additional comments
under "Legal Proceedings - Other".

         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 MDth/d of
firm transportation to Athens Generating Company, L. P. ("Athens Generating")
with whom Iroquois has executed a firm transportation agreement for this
service. Athens Generating is constructing a natural gas fired electric
generation facility in the Town of Athens, New York. On June 3, 2002, the
Commission issued a certificate authorizing Iroquois to construct the Athens
Project facilities. The Company anticipates having adequate capacity on its
system to serve the initial 70MDth/d transportation needs of the Athens
Generating facility. Therefore, in an attempt to better rationalize the capacity
on its system, Iroquois intends to defer the commencement of construction of the
second Athens compressor unit. Athens Generating is owned by Gen Holdings I,
LLC, a subsidiary of PG&E National Energy Group, Inc. On January 16, 2003, PG&E
National Energy Group announced that it has agreed to cooperate with any
reasonable proposal by its lenders regarding the disposition of certain
generating assets, including Athens Generating, in connection with defaults
under various debt agreements.

         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 up to 85MDth/d per day of firm
transportation service to southern Long Island and the New York City Area. The
Partnership would provide firm transportation service to the shippers with whom
it has executed precedent agreements. On October 31, 2002 the Commission issued
a certificate authorizing Iroquois to construct the Brookfield facilities. On
December 2, 2002 Iroquois filed a request for clarification or rehearing
concerning the rate that would be paid by shippers on the Brookfield Project who
delivered gas to the Eastchester delivery point. On February 5, 2003 the




                                      F-17
<PAGE>

Commission issued its order on clarification, which granted in part Iroquois'
request by clarifying that all shippers that utilize the Eastchester expansion
are required to pay the incremental fuel costs. The ultimate rate paid by
shippers to the Eastchester delivery point will be determined in a future rate
proceeding. Iroquois is currently assessing the market for this project to
determine if the November 1, 2004 in-service date should be delayed.

         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 were designed to provide approximately 175
MDth/d of firm transportation service to the eastern end of Long Island, New
York.

         On April 8, 2002 Iroquois filed a motion to consolidate its Eastern
Long Island project with Islander East Pipeline Company, L.L.C.'s ("Islander
East") application pending at the Commission and to convene a comparative
evidentiary hearing on the two projects. This motion was denied by the
Commission in the September 19, 2002 issuance of a preliminary determination on
non-environmental issues. On that same date, the Commission issued a certificate
of public convenience and necessity to Islander East. On October 4, 2002
Iroquois filed a motion with the Commission requesting deferral of consideration
of the ELI Project based on the Commission's September 19, 2002 orders on the
ELI and the Islander East Projects. On October 10, 2002, the Commission granted
Iroquois' motion for deferral of the ELI Project and directed Iroquois to
provide the Commission with an update on the status of the Project by not later
than January 31, 2003. On February 7, 2003, Iroquois notified the Commission
that, after extensive discussions with the ELI project shippers, it determined
that insufficient market support exists to continue to pursue the ELI Project
application and it moved to withdraw the certificate application. As of December
31, 2002 the Company expensed approximately $2.2 million in costs related to the
ELI project.

         Legal Proceedings-Other

         On November 16, 2002, certain undersea electric transmission cables
owned by the Long Island Power Authority, or LIPA, and Connecticut Light and
Power Company, or CL&P, were allegedly damaged and/or destroyed as a result of
an allision with an anchor deployed by the DSV Mr. Sonny, a work vessel taking
part in the construction of the Eastchester Extension. In a letter dated January
8, 2003, attorneys for LIPA and CL&P advised that LIPA and CL&P intend to hold
Horizon Offshore Contractors, Inc. (the Iroquois' general marine contractor),
Thales Geo Solution Group, Ltd. (Horizon's subcontractor), owners of DSV Mr.
Sonny, Iroquois and IPOC jointly and severally liable for the full extent of
their damages, including emergency response costs, repair of the electrical
cables, loss of use and disruption of services to customers, and any other
damages of whatever nature arising from or related to the incident. LIPA and
CL&P estimate that repair costs will be $33.8 million. In addition, Iroquois has
been informed that the Town of Huntington, New York, may assert a claim against
the Partnership alleging violations of



                                      F-18
<PAGE>

certain municipal ordinances on the basis of a claim that dielectric fluid was
released from the cable as a result of this incident.

         Under the terms of the construction contract between Horizon and
Iroquois, Horizon is required to indemnify Iroquois for Horizon's negligence
associated with the construction of the Eastchester Extension. Pursuant to the
contract, Horizon named Iroquois as an additional named insured under Horizon's
policies of insurance. Iroquois understands that Iroquois is covered under such
policies to the extent that Horizon has assumed the liabilities under the
contract with Iroquois. In any event, Iroquois believes it is adequately insured
by its own insurers. Therefore, based on its initial investigation, Iroquois'
management believes that this matter will not have a material adverse effect on
the Partnership's financial condition or results of operations.

         On February 27, 2003, the New York Power Authority, or NYPA, informed
Iroquois that one of four cables that comprise its Y-49 facility, which is a 600
megawatt undersea electrical power interconnection between Westchester County
and LIPA's transmission system at Sands Point, New York, allegedly sustained
damage causing a rupture and leakage of dielectric fluid. NYPA has suggested
that the damage to the Y-49 cables may have been caused by an anchor of the
Horizon pipeline lay barge Gulf Horizon while constructing the Eastchester
Extension. Iroquois is a party to an agreement with NYPA which provides, among
other things, that in the event of damage to Y-49 cables resulting from
Iroquois' or its contractor's negligence, acts, omissions or willful misconduct,
Iroquois will indemnify NYPA for repair costs and the costs of replacement
electrical capacity while the Y-49 cables are out of service, subject to NYPA's
duty to mitigate damages.

         At this time, NYPA has not commenced litigation against Iroquois or
otherwise made a specific written claim for specified damages against Iroquois
as a result of this incident. Iroquois is currently investigating the incident
and evaluating its rights, obligations and responsibilities with regard to the
incident. Given the preliminary stage of this matter, at this time, Iroquois is
unable to assess the likelihood of an unfavorable outcome and/or the amount or
range of loss, if any, in the event of an unfavorable outcome. Under the terms
of the construction contract between Horizon and Iroquois, Horizon is required
to indemnify Iroquois for Horizon's negligence associated with the construction
of the Eastchester Extension. Pursuant to the contract, Horizon named Iroquois
as an additional named insured under their policies of insurance. Iroquois
understands that Iroquois is covered by such policies to the extent that Horizon
has assumed the liabilities under the contract with Iroquois. Iroquois is
currently investigating the applicability of all available insurance coverage.

         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, which
requires annual payments escalating 5% per year over the 39-year term of the
lease, which expires in 2030. In addition, Iroquois leases various equipment
under non-cancelable operating leases. During the years ended December 31, 2002,
2001 and 2000, Iroquois made payments of $0.9, $1.0 and $1.0 million per year
respectively under operating leases which were recorded as rental expense.
Future minimum rental payments under operating lease arrangements are as follows
(millions of dollars):


                                      F-19
<PAGE>


                                      Year                         Amount
                                      ----                         ------
                                      2003                          $ 1.0
                                      2004                          $ 0.9
                                      2005                          $ 0.8
                                      2006                          $ 0.8
                                      2007                          $ 0.8
                                      Thereafter                    $ 6.8


         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 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.
              2002                Federal        State             Total
              ----                -------        -----             -----
              Current            $ 4,007        $ 1,954          $ 5,961
              Deferred            10,070            880           10,950
                                 -------        -------          -------
              Total              $14,077        $ 2,834          $16,911
                                 =======        =======          =======

                                   U.S.
              2001                Federal        State             Total
              ----                -------        -----             -----
              Current            $ 6,431        $ 2,751          $ 9,182
              Deferred             8,054          1,039            9,093
                                 -------        -------         --------
              Total              $14,485        $ 3,790          $18,275
                                 =======        =======         ========

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

         For the years ended December 31, 2002, 2001 and 2000, the effective tax
rate differs from the Federal statutory rate due principally to the impact of
state taxes.



                                      F-20
<PAGE>

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

                                                  2002         2001       2000
        ------------------------------------------------------------------------
        Depreciation                           $11,121      $ 8,157    $ 8,410
        Gain/loss on disposal of asset             934           --         --
        Deferred regulatory asset                  (75)         (76)       (76)
        Property taxes                             (80)          (3)        (1)
        Accrued expenses                           (51)        (240)        --
        Alternative minimum tax credit            (585)       1,141        277
        Other                                     (314)         114        352
                                               -------      -------    -------
        Total deferred taxes                   $10,950      $ 9,093    $ 8,962
                                               =======      =======    =======

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

        At December 31,                                 2002           2001
        -----------------------------------------------------------------------
        DEFERRED TAX ASSETS:
        Alternative minimum tax credit                $ 1,939       $ 1,354
        Accrued expenses                                1,103         1,052
                                                    ---------     ---------
        Total deferred tax assets                       3,042         2,406

        DEFERRED TAX LIABILITIES:
        Depreciation and related items                (87,619)      (75,588)
        Deferred regulatory asset                        (656)         (732)
        Property taxes                                   (794)         (875)
        Legal costs                                        --             1
        Other                                            (859)       (1,172)
                                                    ---------     ---------
        Total deferred tax liabilities                (89,928)      (78,367)
                                                    ---------     ---------
        Net deferred tax liabilities                  (86,886)      (75,960)
                                                    ---------     ---------
        Less deferral of tax rate change                  611           636
                                                    ---------     ---------
        Deferred taxes-operations                     (86,275)      (75,324)
        Deferred tax related to equity AFUDC          (13,469)      (12,662)
        Deferred tax related to change in tax rate       (611)         (636)
                                                    ---------     ---------
        Total deferred taxes                        $(100,355)    $ (88,623)
                                                    =========     =========
        Deferred tax related to other
        comprehensive income                      $    (2,227)           --
                                                    =========     =========

                                      F-21
<PAGE>

         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
below net of payables, if any.

         The following table summarizes Iroquois' related party transactions
(millions of dollars):
                                                                        Revenue
                                          Payments      Due (to)/from    from
                                          to Related    Related         Related
        2002                              Parties       Parties         Parties
        ------------------------------------------------------------------------

        TransCanada Iroquois Ltd.            $ 0.1        $ (0.2)          $--
        Dominion Iroquois, Inc.               --             0.1           0.3
        NorthEast Transmission Company        --             1.2          12.9
        JMC-Iroquois, Inc.                    --             1.6          17.9
        TEN Transmission Company              --             1.1          12.3
        NJNR Pipeline Company                 --             0.5           6.9
        LILCO Energy Systems, Inc.            --             1.0          13.0
                                            ------        ------         ------
                          Totals             $ 0.1        $  5.3         $63.3
                                            ======        ======         =====

                                                                       Revenues
                                          Payments      Due from       from
                                          to 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.            --            0.9             1.1
                                           -----          -----           ------
                          Totals             $--          $ 5.3           $55.3
                                           =====          =====           ======
         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



                                      F-22
<PAGE>

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. A Rabbi
Trust, which is included in other assets and deferred charges on the Company's
balance sheets, has been established to partially cover this obligation. The
Rabbi Trust is an irrevocable trust which can be used to satisfy creditors.

         At December 31, 2002, the Company recorded an additional minimum
liability of $0.9 million, which is included in Other Noncurrent liabilities on
the Consolidated Balance Sheet. This minimum liability resulted from a decrease
in the fair value of plan assets, which was due primarily to declining stock
market values, and a decrease in the discount rate and expected asset return
assumptions.

         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):


                                                 2002     2001       2000
          ----------------------------------------------------------------------
          Service cost                        $ 687     $ 597     $ 504
          Interest cost                         194       137        98
          Expected return on plan assets       (211)     (144)      (92)
          Amortization of prior service cost     22        22        22
          Recognition of net actuarial loss      22         6         2
                                              -----     -----     -----
          Net periodic pension cost           $ 714     $ 618     $ 534
                                              =====     =====     =====

         The following tables represent the two Plans' combined funded status
reconciled to amounts included in the consolidated balance sheets as of December
31, 2002 and 2001 (thousands of dollars):
<TABLE>
<CAPTION>


                Change in Benefit Obligation                            2002              2001
                                                                   ---------------- -----------------
                <S>                                                  <C>              <C>
                Benefit obligation at beginning of year              $  2,570         $  1,945
                Service cost                                              687              597
                Interest cost                                             194              137
                Actuarial gain/(loss)                                     410              (67)
                Benefits paid                                              --              (42)
                                                                     --------         ---------
                Benefit obligation at end of year                    $  3,861         $  2,570
                                                                     ========         ========

                Change in Plan Assets                                   2002              2001
                                                                   ---------------- -----------------
                Fair value of plan assets at beginning of year        $ 2,237          $ 1,455
                Actual return on plan assets                             (202)             (39)
                Employer contribution                                     448              863
                Benefits paid                                              --              (42)
                                                                      -------          -------
                Fair value of plan assets at end of year              $ 2,483          $ 2,237
                                                                      =======          =======

                Reconciliation of Funded Status                         2002              2001
                                                                   ---------------- -----------------
                Funded status                                       $  (1,378)         $  (333)

</TABLE>


                                      F-23
<PAGE>

<TABLE>
<CAPTION>

                <S>                                                  <C>              <C>
                Unrecognized net actuarial loss                         1,009              208
                Unrecognized prior service cost                           125              147
                Additional minimum liability                           (1,083)            (119)
                                                                    ---------          -------
                Accrued benefit cost                                $  (1,327)         $   (97)
                                                                    =========          =======
</TABLE>


         The weighted average assumptions used in developing the projected
benefit obligations at December 31, 2002 were:

                                              2002     2001    2000
                                            ------------------------------
          Discount rate                       6.5%     7.0%    7.0%
          Expected return on plan assets      9.0%     9.0%    9.0%
          Increase in future compensation     4.0%     4.5%    5.0%

         For 2003, the expected return on plan assets percentage used to develop
the projected benefit obligation was reduced to 8.0%.



                                      F-24