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, 2003
                                       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 Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
                                Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to 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, 2003

                                Table of Contents
                                                                            Page
                                                                            ----

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

                                     PART I.

ITEM 1.  BUSINESS..............................................................3

ITEM 2.  PROPERTIES...........................................................19

ITEM 3.  LEGAL PROCEEDINGS....................................................20

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................23

                           PART II.

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
         RELATED STOCKHOLDER MATTERS..........................................23

ITEM 6.  SELECTED FINANCIAL DATA..............................................23

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF
         FINANCIAL CONDITION AND RESULTS OF OPERATIONS........................25

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
         ABOUT MARKET RISK....................................................36

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................36

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
         ACCOUNTING AND FINANCIAL DISCLOSURE..................................36

ITEM 9A. DISCLOSURE CONTROLS AND PROCEDURES...................................36

                           PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP..................38

ITEM 11. EXECUTIVE COMPENSATION...............................................40

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
         MANAGEMENT...........................................................46

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................46

                           PART IV.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES...............................46

                                       i

<PAGE>

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
         AND REPORTS ON FORM 8-K..............................................48


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    the outcome of litigation to which the Partnership is a
                    party;

               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.



                                       2
<PAGE>

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.

                                    PART I.

ITEM 1.  BUSINESS

Introduction

          Iroquois Gas Transmission System, L.P., or the Partnership, is a
Delaware limited partnership. It owns and operates a 412-mile interstate natural
gas transmission pipeline from the Canada-United States border near Waddington,
New York to South Commack, Long Island, New York including an approximate
36-mile mainline extension from Northport, New York through the Long Island
Sound to Hunts Point, 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 interconnects 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 was organized
in 1989 and 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, 2003, the Partnership had 35
shippers with long-term firm reserved transportation service contracts for 1,113
thousands of dekatherms per day. As of December 31, 2003, approximately 82% of
the Partnership's subscribed pipeline capacity was contracted under firm
reserved transportation service contracts that continue through at least
November 1, 2011.

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



                                       3
<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 Corporation           NorthEast Transmission              19.4%
                                      Company
                                  KeySpan IGTS Corp.                  1.0%

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

    National Energy & Gas         JMC-Iroquois, Inc.                  4.93%
    Transmission, Inc.            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, or 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 10, 1989, as amended and restated on February 28, 1997, 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 412
miles from the Canada-United States border near Waddington, New York to South
Commack, Long Island, New York and includes the recently completed
Eastchester/New York City expansion of its pipeline system, consisting of an
approximate 36-mile mainline extension, referred to as the Eastchester
Extension, running from the mainline on Long Island near Northport, New York,
through the Long Island Sound to Hunts Point, 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. Also as part of the Eastchester Extension, the
Partnership added two new compressor stations at Boonville and Dover, New York,
additional compression at the existing Croghan and Wright



                                       4
<PAGE>

compressor station and cooling facilities at the Wright and Athens, New York
compressor stations. As of December 31, 2003, the Partnership had firm
reserved transportation contracts in place to deliver 1,113 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 21 delivery meters with a combined capacity of
approximately 6.3 MMDth/d. Each meter station consists of a separate control
building that contains gas measurement equipment and electrical and
instrumentation devices. 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 interconnections with the New York Facilities
System at South Commack, Long Island and Hunts Point, New York. 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 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 six years, the average availability
of the Partnership's compressor units has ranged from 95% to 99%. 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 mainline pipeline system is
subscribed under firm reserved transportation service contracts with 35
shippers. Under the firm reserved transportation service contracts, the pipeline
receives natural gas on behalf of shippers at designated receipt points and
transports the gas on a firm basis up to each shipper's maximum



                                       5
<PAGE>

daily quantity. As of December 31, 2003, approximately 82% 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 Corporation and National
Energy & Gas Transmission, Inc. (f/k/a PG&E National Energy Group), through
their affiliates, each accounted for more than 10% of the Partnership's revenues
for the year ended December 31, 2003. Approximately 48% of the Partnership's
existing pipeline system firm reserved capacity was contracted to affiliates of
the Partnership's partners as of December 31, 2003.

          As of the Eastchester Expansion in-service date of February 5, 2004,
six shippers had contracted for service on the expansion totaling 210 MDth/d.
Approximately 71% of this capacity is contracted through at least February 1,
2013. On January 2, 2004 the Partnership submitted a request to the FERC to
establish incremental rates for the Eastchester Expansion shippers and secondary
access rates for existing shippers to deliver at Hunts Point, New York. The new
rates were requested to take effect on February 2, 2004. The filing requested a
single incremental rate applied to delivery of gas to Eastchester shippers with
the cost borne entirely in the monthly demand charge and thereby eliminating a
commodity charge. Existing shippers could deliver gas to Hunts Point by paying a
charge up to the difference between the Eastchester Rate and their existing
rate. By order issued on January 30, 2004, the FERC accepted the rate filing
making the rates effective July 1, 2004 subject to refund and subject to the
outcome of hearings.

          On April 8, 2003, in the Partnership's Docket No. RP03-304, the FERC
approved an incremental fuel charge for Eastchester shippers up to a limit of
4.5% of their receipt quantity. Fuel charged to Eastchester shippers may be up
to 4.5 times the rate charged to the Partnership's existing shippers and will
apply to the Eastchester contracts regardless of the delivery point selected and
to existing shippers who choose to deliver gas to Hunts Point, New York.

          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
2003 and 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, 2003, the weighted average
credit rating of the Partnership's shippers which are rated or have parental
guarantees or letters of credit in place, representing 88.8% of the



                                       6
<PAGE>

pipeline system's contracted capacity, was A3 (based on Moody's Investor
Services) and A- (based on Standard and Poor's (S&P)). The weighted average
credit rating of all shippers, including those who have made other credit
support arrangements that the Partnership finds satisfactory, was A3 (Moody's)
and BBB+ (S&P). The weighted average credit rating was determined by converting
the S&P and Moody's ratings into internal numerical ratings ranging from 1 to
22, with 1 being equivalent to AAA/Aaa by S&P and Moody's and 22 being D or
Default by S&P and Moody's. For purposes of this analysis, those non-rated
shippers who have made other credit support arrangements were either assigned an
assumed investment grade rating, or the ratings of their parent were used.


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.



                                       7
<PAGE>

          In February 2004, the Partnership concluded construction of the
Eastchester Extension. The new line, located primarily in the Long Island Sound
and progressing down the East River, proceeds on land for approximately 4,000
feet, connecting with the northern section of the gas distribution facilities of
the Consolidated Edison Company of New York, or ConEd. Under precedent
agreements, which contained conditions that had to be satisfied before a
contract for firm transportation service was 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 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 various 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.

          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 in-service date of the completed Eastchester
Extension was February 5, 2004, and the Partnership's management believes that
the final construction costs will be approximately $334 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.

          Initial Eastchester throughput for the full month of February 2004
averaged 44 MDth/d or 21% of the contracted capacity, although full demand
charges are being paid by the shippers. The Partnership believes this initial
percentage is due to the February 5 in-service date of the project and the
incremental fuel assessed to the Eastchester contracts. Capacity utilization
will likely be somewhat seasonal and will increase when the New York City prices
are high enough to offset the higher cost of fuel. Utilization should increase
over time as market demand grows.

          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



                                       8
<PAGE>

of Athens Generating. On May 14, 2003, the Partnership applied for and received
from the FERC a deferral of the completion of construction until December 3,
2004. Athens Generating is owned by Gen Holdings I, LLC, a subsidiary of
National Energy & Gas Transmission, Inc. (NEGT). On January 16, 2003, NEGT
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. (See Note 7 to the Consolidated Financial Statements.)

          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 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 fuel 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, including Brookfield Project
shippers utilizing the Eastchester facilities, will be required to pay
incremental fuel costs.

          Based on communications with its prospective customers regarding the
timing of their needs for new firm transportation service, the Partnership has
determined that a temporary deferral of the construction of the Brookfield
Project was necessary. On April 22, 2003, the Partnership requested an eighteen
month extension from the FERC to extend the construction completion time of the
Brookfield Project to October 31, 2005. On May 14, 2003, the FERC granted the
Partnership's request and extended the construction completion date to November
1, 2005. Both original Brookfield Project Shippers, PPL Energy Plus, LLC and
Astoria Energy LLC have terminated their precedent agreements with the
Partnership. For additional information, see Note 7 to the Consolidated
Financial Statements included elsewhere in this annual report.

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



                                       9
<PAGE>

with respect to virtually all aspects of its business, including transportation
of gas, rates and charges, construction of new facilities, extension or
abandonment of service and facilities, accounts and records, depreciation and
amortization policies, the acquisition and disposition of facilities, the
initiation and discontinuation of services, and certain other matters. The
Partnership, where required, holds certificates of public convenience and
necessity issued by the FERC covering its facilities, activities and services.

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

          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



                                       10
<PAGE>

light of the FERC's decision to seek comments on its negotiated rate policies
from companies in the natural gas industry.

          Regulatory Proceedings. After extensive negotiations between the
Partnership, its customers and other interested parties, on August 29, 2003, the
Partnership filed with the FERC an offer of Stipulation and Settlement Agreement
in Docket No. RP03-589, which implements four scheduled reductions to the
Partnership's rates. The central objective of the negotiations was to extend the
principles underlying the Partnership's December 17, 1999 settlement in Docket
No. RP94-72, et al., which established the rates under which the Partnership
currently provides service. By order dated October 24, 2003, the FERC approved
the settlement. The principal elements of the settlement are:

               o    a reduction in maximum demand rates phased-in over a
                    four-year period that began on January 1, 2004;

               o    neither the settlement rates nor any principles underlying
                    the settlement apply to the Eastchester Extension, which was
                    certificated in Docket No. CP00-232-000;

               o    the ability of the Partnership to file a rate case under
                    Section 4 of the Natural Gas Act is limited to establishing
                    rates for the Eastchester Extension, while parties retain
                    all rights to challenge the Partnership's proposed
                    Eastchester rates. Additionally, the settlement provides
                    that the Partnership will establish, in a separate
                    proceeding, a maximum recourse tariff rate for
                    non-Eastchester shippers that use the Eastchester Extension.
                    Eastchester shippers would also pay the applicable
                    incremental fuel charge approved by the FERC in an
                    unpublished delegated letter order issued April 8, 2003 in
                    Docket No. RP03-304-000.

               o    a rate moratorium under which the Partnership may not file
                    an application to increase rates pursuant to the Natural Gas
                    Act prior to July 1, 2007, with any subsequent increase
                    effective no earlier than January 1, 2008. Further, no party
                    may file for reductions in rates pursuant to the Natural Gas
                    Act prior to March 1, 2007 or receive such reductions prior
                    to January 1, 2008 (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
                    during the term of the settlement.

          The settlement establishes the Partnership's base tariff recourse
rates, or settlement rates, for the years 2004, 2005, 2006 and 2007. The
settlement rates reflect annual step-downs, which over the term of the
settlement will reduce the Partnership's transportation rates by approximately
13%, i.e., the 100% load factor interzone rate will be reduce from the existing
level of $0.4234 per Dth, to the January 1, 2007 level of $0.3700 per Dth, for a
total cumulative



                                       11
<PAGE>

reduction of $0.0534 per Dth. Based on 2004 long-term firm service contracts,
the settlement will result in reductions in revenues of $3.8 million in 2004,
$1.5 million in 2005, $1.0 million in 2006 and $2.5 million in 2007. Under the
settlement, the first step-down in rates becomes effective on July 1, 2004.

          Eastchester Extension Rate Case filed with the FERC. The Partnership
received final approval and was issued a certificate to construct the
Eastchester Extension on December 26, 2001 in Docket No. CP00-232-000.
Construction on the extension was completed in late January 2004 and the project
commenced service on February 5, 2004. In anticipation of the in-service date,
on January 2, 2004, the Partnership submitted its rate filing pursuant to
Section 4 of the Natural Gas Act (NGA), 15 U.S.C. ss. 717c, and Part 154 (18
C.F.R. Part 154) of the regulations of the FERC.

          The Partnership's rate filing, Docket No. RP04-136-000, establishes
incremental rates for the Eastchester Extension as well as resulting secondary
access rates for delivery to the Eastchester delivery point by existing
non-Eastchester shippers. The Partnership is proposing an Eastchester rate of
$0.8444 per Dth on a 100% load factor basis, which would increase annual
revenues from Eastchester service by $17.0 million based on a total cost of
service of $70.9 million. The proposed Eastchester rates were developed using a
base period consisting of 12 months of actual experience through September 30,
2003, as adjusted for known and measurable changes projected to occur during the
test period ending June 30, 2004. By order issued on January 30, 2004, the FERC
accepted the rate filing making the rates effective July 1, 2004 subject to
refund and subject to the outcome of hearings.

          On February 17, 2004, a pre-hearing conference before the FERC
resulted in a procedural schedule outlining the various phases of the
Partnership's rate filing proceeding with an anticipated final order due by the
end of the second quarter of 2005.

          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 have
greater flexibility in tailoring the firm reserved services they offer to
customers and customers 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.

          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. In response to various interim orders issued by the FERC,
the Partnership submitted numerous additional compliance filings in 2003, which
were ultimately accepted by the FERC.



                                       12
<PAGE>

Management believes all Order No. 637 requirements have been met. See Note 7 to
the Consolidated Financial Statements included elsewhere in this annual report.

          Rulemaking on FERC's Standard of Conduct for Transportation Providers.
On November 25, 2003, the FERC issued Order No. 2004 in FERC Docket No. RM01-10.
According to the FERC, Order No. 2004 adopts new standards of conduct that apply
uniformly to interstate natural gas pipelines and public utilities and that
replace standards of conduct currently in effect. The standards of conduct are
designed to ensure that transmission providers do not provide preferential
access to service or information to affiliated entities. Under the schedule
adopted by the FERC, on February 9, 2004 the Partnership submitted its plan and
schedule for implementing Order No. 2004. By June 1, 2004 the Partnership will
post its revised standards of conduct on its internet website, identifying the
procedures established for implementing the FERC's requirements. Management does
not believe that the requirements of Order No. 2004 will have a material impact
on the Partnership.

Safety Regulations

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

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

Environmental Matters

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



                                       13
<PAGE>

          Current Operations. At each of the Partnership's five 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. Additionally, IPOC intends to
monitor environmental standards and controls at all new facilities.

          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.
In the future, it is IPOC's intention to seek removal from this list. 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, 2003, IPOC had 123 employees.

Risk Factors

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

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

          As of December 31, 2003, approximately 82% of the subscribed capacity
of the Partnership's pipeline system was contracted through at least November 1,
2011. The Partnership cannot give any assurances that it will be able to extend
or replace these contracts at the end of their initial terms 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:



                                       14
<PAGE>

               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 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 and continuing in 2003, the energy
industry, which includes the Partnership's firm transportation shippers,
experienced significant credit and liquidity issues and credit rating agency
downgrades.

          On July 8, 2003, PG&E Corporation reported that NEGT (f/k/a PG&E
National Energy Group) and a number of its subsidiaries filed voluntary
petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. These
subsidiaries include, PG&E Energy Trading Holdings Corporation, PG&E Energy
Trading-Gas Corporation, PG&E Energy Trading-Power Corporation, PG&E ET
Investments Corporation, and US Gen New England, Inc. (US Gen NE).

          US Gen NE had two firm transportation service agreements with the
Partnership, one for 40,702 Dth/d which expires on November 1, 2013 and one for
12,000 Dth/d which expires on April 1, 2018. The total monthly demand charges
for both contracts was $0.5 million. On September 5, 2003, the bankruptcy court
authorized the rejection of US Gen NE's two firm transportation contracts. The
Partnership has remarketed a portion of the capacity on a short-term basis and
plans to continue to remarket and resell this capacity in the future. There can
be no assurance, however, that shippers will not default on their payment
obligations for transportation services provided in the future.



                                       15
<PAGE>

          The Partnership's rates are calculated on the basis of an assumed
contracted capacity and its revenue projections assume that shippers will pay
these rates as required by their contracts. A prolonged economic downturn in the
energy industry or a broader economic downturn affecting the 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 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 the Partnership's 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 incurred 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



                                       16
<PAGE>

to find replacement sources of natural gas for the pipeline system's capacity.
The Partnership cannot give any assurances as to the availability of additional
sources of gas that can interconnect with its pipeline system.

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

               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.

Lawsuits against the Partnership could adversely affect its operating results

          In the course of expanding its natural gas pipeline and related
facilities, the Partnership faces typical construction risks, including, but not
limited to, risks relating to the existence of sensitive property owned by third
parties and environmental and geological problems. In constructing the
Eastchester Extension, the Partnership faced particular risks associated with
the construction of a large, mainly underwater, pipeline. During construction,
certain undersea electric transmission cables owned by the Long Island Power
Authority and Connecticut Light and Power Company were allegedly damaged and/or
severed as a result of an allision with an



                                       17
<PAGE>

anchor deployed by the DSV Mr. Sonny, a work vessel owned and operated by a
subcontractor taking part in the construction of the Eastchester Extension.
Additionally, the 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 disruption of
power transmission over the line and leakage of dielectric fluid. NYPA alleges
that the damage was caused by an anchor of Horizon's pipeline lay barge, the
GULF HORIZON, which was in the vicinity of NYPA's cable and was involved in work
in the Eastchester Extension at the time of the casualty. As a result of these
incidents, litigation is currently pending against the Partnership. It is
unknown at this time whether there will be material adverse effects on the
Partnership's financial condition as a result of this litigation. For additional
information about this litigation, see "Item 3. Legal Proceedings" below. For a
description of additional legal proceedings in which the Partnership is
currently involved, see Note 7 to the Consolidated Financial Statements
appearing elsewhere in this annual report.

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



                                       18
<PAGE>

expenditures on such abandoned expansions. Also, a proposed expansion may cost
more than planned to complete and such excess costs may not be recoverable.

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

          The Partnership's operations are subject to federal, state and local
laws and regulations relating to the protection of the environment 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. On December 19, 2003, the
Partnership exercised an option to cancel approximately 4,300 square feet of
that space through written notification to the landlord of the Shelton office
and by making a one-time payment to the landlord of approximately $50,000. The
cancellation of that portion of the lease will become effective on January 1,
2005. 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, 2006. The Partnership believes that its facilities are adequate for
its 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.



                                       19
<PAGE>

ITEM 3.  LEGAL PROCEEDINGS

          On November 16, 2002, certain undersea electric transmission cables
owned by Long Island Lighting Company d/b/a The Long Island Power Authority, or
LIPA, and Connecticut Light and Power Company, or CL&P, were allegedly damaged
and/or severed when an anchor deployed by the DSV MR. SONNY, a work vessel
taking part in the construction of the Eastchester Extension, allegedly allided
with the cables. The MR. SONNY allegedly is owned by Cal Dive International,
Inc., a subcontractor of the Partnership's general contractor, Horizon Offshore
Contractors, Inc.

          On December 6, 2002, Cal Dive commenced a maritime limitation of
liability action in the United States District Court for the Eastern District of
New York, seeking exoneration from or limitation of liability in respect of this
incident. LIPA, CL&P, the Partnership, Horizon, and Thales GeoSolutions Group,
Ltd. (another of Horizon's subcontractors), have all filed claims in the
limitation action. In addition, LIPA, CL&P and their subrogated underwriters
(the "Cable Interests") filed third-party claims against the Partnership and its
operating subsidiary, IPOC, as well as Horizon and Thales, seeking recovery for
its alleged losses. The Partnership filed cross claims against Horizon and
Thales for indemnification in respect of the Cable Interests' claims, and
Horizon filed a third-party claim against Thales. The Cable Interests
subsequently agreed to dismiss their claim against IPOC, but without prejudice
to their right to re-file that claim if they deem necessary.

          The Cable Interests are claiming a total of $34.2 million in damages,
consisting of $14.4 million for repairs and repair related costs, including LIPA
and CL&P internal costs and overheads of $4.7 million, as well as $19.9 million
in consequential damages.

          In addition to the foregoing, the Partnership has been advised that
the Town of Huntington, New York may assert a claim against the Partnership
alleging violations of certain municipal ordinances on the basis of a claim that
dielectric fluid was released from the cable as a result of the incident.

          Under the terms of the construction contract between Horizon and the
Partnership, Horizon is obligated to indemnify the Partnership for Horizon's
negligence associated with the construction of the Eastchester Extension.
Horizon is also contractually responsible for its subcontractors' negligence. As
required by the contract, Horizon named the Partnership as an additional named
insured under Horizon's policies of insurance. The Partnership understands that
it is covered under Horizon's policies to the extent that Horizon has assumed
liability to the Partnership under the contract. Based on Horizon's subcontracts
with Thales and Cal Dive, the Partnership may also be entitled to coverage as an
additional insured party under those parties' policies of insurance. In
addition, Thales's underwriters have sent a letter to Thales, which was
forwarded to the Partnership's counsel on March 12, 2004, agreeing to indemnify
the Partnership in accordance with the indemnity provision in the Horizon/Thales
contract. This indemnity is subject to the policies' terms and limit of
$10,000,000.00. The details of this arrangement are being negotiated. 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.



                                       20
<PAGE>

          On February 27, 2003, the New York Power Authority, or NYPA, informed
the Partnership that one of four cables that comprised 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 disruption of power transmission over the line and
leakage of dielectric fluid. NYPA alleges that the damage was caused by an
anchor of Horizon's pipeline lay barge, the GULF HORIZON, which was in the
vicinity of NYPA's cable and was involved in work in the Eastchester Extension
at the time of the casualty.

          By letter dated March 25, 2003, counsel representing NYPA and LIPA
informed the Partnership that they intend to hold the Partnership, Horizon and
Horizon's subcontractor, Thales, jointly and severally liable for the full
extent of their damages, which they allege includes emergency response costs,
repair of the damaged electrical cable, loss of use and disruption of service,
and certain other as yet unspecified damages arising out of or relating to the
incident.

          The Partnership is a party to an agreement with NYPA, which provides,
among other things, that the Partnership will indemnify NYPA for damage to the
Y-49 cables, which results from the Partnership's or its contractors'
negligence, acts, omissions or willful misconduct. Under the terms of the
construction contract between Horizon and the Partnership, Horizon is obligated
to indemnify the Partnership for Horizon's negligence associated with the
construction of the Eastchester Extension. Horizon is also contractually
responsible for its sub-contractor's negligence. Pursuant to the contract,
Horizon named the Partnership as an additional named insured under Horizon's
policies of insurance. The Partnership is still investigating whether Horizon's
insurance is adequate to cover the Partnership for its potential losses in this
matter. The Partnership may also be entitled to indemnity as an additional
insured under Thales' policies of insurance, although this matter is also still
subject to further investigation. The Partnership has placed Horizon and its
underwriters on notice that it intends to hold Horizon responsible. The
Partnership has further requested that Horizon assume its defense and hold it
harmless in respect of this claim; however, to date, Horizon has rejected this
request. The Partnership has also placed its own insurance underwriters on
notice and is currently investigating the applicability of all available
insurance coverages.

         On August 15, 2003, Horizon commenced a maritime limitation of
liability action in the United States District Court for the Southern District
of Texas, Houston Division, captioned In the Matter of Horizon Vessels Inc., as
owner of the GULF HORIZON, seeking exoneration from or limitation of liability
in connection with this incident. NYPA and LIPA (collectively, the "Y-49 Cable
Interests") also have filed claims in the limitation action asserting total
damages of approximately $21 million. On November 12, 2003, the Partnership
filed an Answer in Horizon's action, requesting that the limitation of liability
action be dismissed and/or that the limitation injunction be lifted to permit
the Partnership to pursue its claims against Horizon in the forum of its choice,
or, in the alternative, that Horizon be denied limitation rights under the
Limitation Act. The Partnership also filed a claim in Horizon's limitation
action seeking indemnity for any liability it may be found to have to the Y-49
Cable Interests as a result of the NYPA cable incident as well as all losses
suffered by the Partnership as a result thereof, and, on a protective basis,
seeking full damages for Horizon's breaches and deficient performance under the
Partnership/Horizon construction contract, which claims are unrelated to the
NYPA cable



                                       21
<PAGE>

incident. Thales also has filed a claim in the Horizon limitation action seeking
indemnity for any liability it may be found to have to the Y-49 Cable Interests
or the Partnership. The Y-49 Cable Interests and the Partnership both have filed
motions to transfer the Texas action to the United States District Court for the
Eastern District of New York. Thales has joined in those motions. By order
entered February 27, 2004, the court denied the motions to transfer. However, in
doing so, the court confirmed that the Partnership could pursue its contract
claims against Horizon outside of the limitation action.

          The Partnership is still in the process of investigating this incident
and evaluating its rights, obligations and responsibilities. Given the
preliminary stage of this matter, 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.

          The Partnership has also learned that as part of the Eastchester
construction there may have been one or more violations by the contractor of the
exclusionary zones established around certain specified areas of possible
cultural resources, namely underwater archeological sites such as shipwrecks,
along the pipeline's marine route and the contractor may have placed anchors
outside the authorized construction corridor. At this time, the Partnership has
no information that any sites were in fact damaged and the Partnership's
investigation in this matter is ongoing. The Partnership has informed the FERC
and the New York State Office of Parks, Recreation and Historic Preservation of
this matter. At this time, the Partnership is unable to determine if there will
be any material adverse effect on the Partnership's financial condition and
results of operations due to this matter.

Eastchester-Horizon Suit

          On January 20, 2004, Horizon filed a complaint against the Partnership
and IPOC in the Supreme Court of the State Of New York, New York County (Index
No. 04/600140). The complaint alleges that the Partnership wrongfully terminated
its agreement with Horizon to perform the Eastchester construction work in Long
Island Sound and that the Partnership committed other breaches of such agreement
in conjunction with the Eastchester construction work. The complaint seeks
damages in excess of $40.0 million. The Partnership is in the process of
preparing a rigorous defense to Horizon's claims; it has served an answer and
will file substantial claims in state and/or federal court against Horizon for
Horizon's actions during the Eastchester construction work. Given the
preliminary stage of this matter, the Partnership is unable at this time to
assess the likelihood of a favorable or unfavorable outcome and/or the amount or
range of recovery or loss, if any, resulting from Horizon's claims and the
Partnership's counterclaims.

Cal Dive International, Inc.

          On March 1, 2004 and in a duplicate filing on March 9, 2004, Cal Dive
International, Inc. ("Cal Dive") filed a Mechanic's Lien totaling $3.3 million
in the offices of the Clerk of Bronx and Suffolk Counties, respectively. Cal
Dive was in privity with Horizon Offshore Contractors,



                                       22
<PAGE>

Inc. ("Horizon") and provided services to Horizon during the Eastchester
construction work. The Partnership instructed Horizon to address the lien notice
pursuant to its contractual obligations. The Partnership also demanded further
information from Cal Dive on the particulars of its lien. The Partnership does
not believe it owes Cal Dive any monies and plans to vigorously contest the
validity of the liens. Furthermore, the Partnership, in compliance with Section
6.2(c)(ii) of its Second Supplemental Indenture, dated August 13, 2003, intends
to post a bond to discharge the Mechanic's Lien.

Capobianco, A. vs. Iroquois Gas & Consolidated Edison Company of New York

          On January 28, 2004, Anthony Capobianco filed a complaint against
Iroquois Gas Transmission System, L.P., Iroquois Pipeline Operating Company and
Consolidated Edison Company of New York in the Supreme Court of the State of New
York, New York County (Index No. 101366/04). The complaint alleges that Mr.
Capobianco, an employee of Hallen Construction Company, Inc. ("Hallen"),
sustained personal injuries resulting from an electrical current causing severe
electrical shock while performing his duties as part of the construction of the
Hunts Point segment of the Partnership's Eastchester project. Hallen was the
Partnership's contractor employed to construct that segment of the project. The
claim is asserted for damages in the amount of $10.0 million. The Partnership
has notified its insurance carriers and an answer has been filed to the
complaint. Given the preliminary nature of this matter, at this time, the
Partnership is unable to determine the likelihood of an unfavorable outcome
and/or the amount or range of loss, if any, in the event of an unfavorable
outcome.

          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



                                       23
<PAGE>

December 31, 2003, 2002, 2001, 2000 and 1999 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,
                                                   ------------------------------------------------------
                                                   2003         2002         2001        2000        1999
                                                   ----         ----         ----        ----        ----
                                                          (In thousands of dollars, except ratios)
    Income Statement Data:
<S>                                               <C>            <C>         <C>         <C>        <C>
    Operating revenues...................         $132,009       $126,320    $128,270    $127,234   $123,919
    Operating expenses:
        Operation and maintenance........           26,081         26,112      22,108      21,119     21,534
        Depreciation and amortization....           24,090         23,684      23,847      23,609     21,976
        Taxes other than income taxes....           12,333         11,206      10,953      11,156     11,449
                                                ----------      ---------   ---------   ---------  ---------
          Total operating expenses.......           62,504         61,002      56,908      55,884     54,959
    Operating income.....................           69,505         65,318      71,362      71,350     68,960
    Other income and (expenses)..........            8,850          2,708       1,829       1,824      1,419
                                                ----------      ---------   ---------   ---------  ---------
    Income before interest charges, taxes and
    cumulative effect of change in accounting
    principle                                       78,355         68,026      73,191      73,174     70,379
        Net interest expense.............           24,819         25,148      28,067      31,139     30,621
                                                ----------      ---------   ---------   ---------  ---------
    Income before taxes and cumulative effect
    of change in accounting principle....           53,536         42,878      45,124      42,035     39,758
        Provisions for taxes(1)..........           21,435         16,911      18,275      17,083     15,580
                                                ----------      ---------   ---------   ---------  ---------
    Income before cumulative effect
    of change in accounting principle               32,101         25,967      26,849      24,952     24,178
                                                ----------      ---------   ---------   ---------  ---------
    Cumulative effect of change in accounting
    principle, net of tax                            3,715              -           -           -          -
                                                ----------      ---------   ---------   ---------  ---------
    Net Income                                    $ 35,816       $ 25,967    $ 26,849    $ 24,952   $ 24,178
                                                ==========      =========   =========   =========  =========

    Cash Flow Data:

    Net cash from operating
        activities.......................          $75,046       $ 68,782    $ 77,265    $ 57,181   $ 57,961
    Capital expenditures.................         $153,100       $109,433     $36,340      $8,268     $7,718

    Balance Sheet Data
    (at End of Period):
        Net property, plant and equipment         $759,343       $621,475    $533,219    $520,172   $534,806
    Total assets.........................         $848,705       $689,385    $591,745    $584,368   $594,851
    Long-term debt, including
        current maturities...............         $470,000       $407,222    $366,666    $388,889   $336,664
    Partners' capital....................         $312,643       $232,073    $190,764    $169,423   $227,388
</TABLE>
_________________________________

(1)     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.



                                       24
<PAGE>

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

Overview

          The Partnership owns and operates a 412-mile interstate natural gas
transmission pipeline that extends from the Canada-United States border near
Waddington, New York to South Commack, Long Island, New York and includes the
Eastchester Extension. 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.

          The Partnership began constructing the Eastchester Extension on April
19, 2002. As part of the Eastchester Extension, the Partnership made
modifications to its three existing compressor stations and constructed two new
compressor stations in Dover, New York and Boonville, New York. 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, Eastchester Extension was
placed into service on February 5, 2004. Management believes that final project
construction costs will be approximately $334 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.

          The Partnership receives revenues under long-term firm reserved
transportation service contracts with shippers in accordance with service rates
approved by the FERC. On December 17, 1999, the Partnership filed with the FERC
a settlement of various outstanding rate matters (Docket Nos. RP97-126 and
RP94-72). Pursuant to the settlement the parties agreed to a rate moratorium
whereby, with limited exceptions, no new rates could be placed in effect on the
Partnership's system until January 1, 2004. In light of the expiration of the
1999 rate moratorium, the Partnership renegotiated its effective transportation
rates with its customers and on August 29, 2003 filed a new four-year rate
settlement with the FERC in Docket No. RP03-589. On October 24, 2003, the FERC
approved the settlement which, as noted below, approved new settlement rates for
the Partnership's existing mainline customers and, with limited exception,
provided that no change to the mainline settlement rates may be placed in effect
on the Partnership's mainline system until December 31, 2007.

          The settlement establishes the Partnership's base tariff recourse
rates, or settlement rates, for the years 2004, 2005, 2006, and 2007. The
settlement rates reflect annual step-downs, which over the term of the
settlement will reduce the Partnership's transportation rates by



                                       25
<PAGE>

approximately 13% (e.g., the 100% load factor interzone rate will be reduced
from the existing level of $0.4234 per Dth, to the January 1, 2007 level of
$0.3700 per Dth, for a total cumulative reduction of $0.0534 per Dth). Based on
long-term firm service contracts as of December 31, 2003, the settlement will
result in reductions in revenues of $3.8 million in 2004, $1.5 million in 2005,
$1 million in 2006 and $2.5 million in 2007. Under the settlement the first
step-down in rates becomes effective on July 1, 2004. The settlement does not
establish any rates, terms or conditions for the Eastchester Extension.

          Outlook

          While the gas-fired electric generation building cycle has slowed in
New England, there is a significant effort by the state of New York to encourage
additional gas-fired generation within the state, as demonstrated by the recent
solicitation for generating capacity by Consolidated Edison, the Long Island
Power Authority and the New York Power Authority. The development of additional
gas supply remains a challenge for the natural gas industry. However, the
announcement of several new liquefied natural gas (LNG) terminals in the
Northeast increases the potential for new gas supply to the region and enhances
the opportunity for further penetration of natural gas into energy markets.

          Obtaining permits for projects in the Northeast remains a significant
challenge. This however, may benefit the Partnership given its recent completion
of a new meter delivery point into New York City through its Eastchester
Extension, since companies with an existing infrastructure will have an
advantage over companies proposing new infrastructure, in light of the risks in
obtaining permits.

Results of Operations

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

                                                         Year ended
                                                        December 31,
                                                 -------------------------------
  Revenues and Volumes Transported
                                                   2003       2002       2001
                                                   ----       ----       ----

  Revenues (dollars in millions)
           Long-term firm reserved service        $115.6     $114.8     $119.1
           Short-term firm (1)                       8.8        4.1        5.5
           Interruptible/other (1)                   7.6        7.4        3.7
                                                     ---        ---        ---
                    Total revenues                $132.0     $126.3     $128.3

  Volumes Transported (millions of dekatherms)
           Long-term firm reserved service         289.7      300.7      281.8
           Short-term firm (1)                      23.1       11.4       15.7
           Interruptible/other (1)                  32.4       32.3       20.6
                                                    ----       ----       ----
                    Total volumes transported      345.2      344.4      318.1

                                       26
<PAGE>

(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

          As discussed above, 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 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.

          2003 compared to 2002

          Total revenues increased by $5.7 million, or 4.5%, to $132.0 million
for 2003 from $126.3 million for the prior year. This increase was largely due
to an increase in short-term firm revenues of approximately $4.7 million,
attributable primarily to increased volumes for short-term firm service
resulting from stronger market demand for natural gas due to colder weather
during the first quarter of 2003 as compared to the same period in 2002.
Long-term firm revenues increased by $0.8 million primarily due to additional
capacity provided by the mainline compression portion of the Eastchester
facilities and a new negotiated rate long-term firm contract in the first
quarter of 2003, partially offset by the rate decrease effective January 1, 2003
of approximately $0.01 per Dth. The Partnership's firm revenues are primarily
derived from long-term contracts and are not directly impacted by fluctuations
in volumes.

          2002 compared to 2001

          Total revenues decreased by $2.0 million, or 1.6%, to $126.3 million
for 2002 from $128.3 million for the prior year. Long-term firm revenues for
2002 decreased $4.3 million from the prior year primarily due to a rate decrease
of $.024 cents per Dth in 2002. The rate decrease resulted in a $6.1 million
decrease in long-term firm revenues for 2002 which was partially offset by new
long-term firm contracts in place in 2002. Short-term firm revenues for 2002
decreased $1.4 million from the prior year while interruptible/other revenues
increased $3.7 million over 2001 levels due primarily to a shift in demand for
services from short-term firm to interruptible.

          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



                                       27
<PAGE>

mainline, metering and compression facilities. The Partnership expects that
there will be normal increases in payroll, benefits and insurance expenses due
to expected inflationary trends.

          2003 compared to 2002

          Operation and maintenance expense was $26.1 million for each of 2003
and 2002. Operation and maintenance expense for 2003 included a $0.7 million
write-off related to the Partnership's investment in its Western Leg project as
well as increases related to insurance, regulatory expenses, outside services
expense and rent expense. Operation and maintenance expense for 2002 included a
$2.2 million write-off related to the Partnership's investment in its Eastern
Long Island, or ELI, project which had been withdrawn from FERC certification.

          2002 compared to 2001

          Operation and maintenance expense increased by $4.0 million, or 18.1%,
to $26.1 million for 2002 from $22.1 million for 2001. The increase was due to
the write-off of the ELI project in 2002, increased payroll and benefits expense
as well as higher outside service and insurance costs in 2002.

          Taxes Other Than Income Taxes

          Taxes other than income taxes consist primarily of municipal property
taxes and payroll taxes. With the Eastchester Extension being placed into
service in 2004, the Partnership expects that municipal property taxes will
continue to increase as municipalities begin to place that property on their tax
rolls.

          As of December 31, 2003, the Partnership changed its method of
accounting for municipal property taxes to provide a better matching of property
tax expense with the receipt of services provided by the municipalities. Most
municipalities in Connecticut assess property values as of October 1 of each
year (lien date) with payments due the following July 1, for the year beginning
that July 1. Most New York municipalities assess property values as of July 1
(lien date) with payments due the following January 1 for the year beginning
that January 1. New York school districts also follow a similar process.

          Through the calendar year ended December 31, 2002, the Partnership
accrued property taxes based on estimated assessments beginning on the lien
date. For the calendar year ended December 31, 2003, the Partnership began to
recognize the actual property tax expense over the same period that the towns
recognize the income from those taxes. The cumulative effect of this change in
accounting for municipal property taxes, all of which is recognized in the
quarter ended December 31, 2003 is a reduction to expense of approximately $6.2
million before income taxes and $3.7 million after income taxes, and is
reflected on the income statement as a cumulative effect of change in accounting
principle. If the Partnership had accounted for property taxes in this manner
for 2002 and 2001, the amounts that would have been reported as property tax
expense for these years would not have been significantly different than what is
actually reported. This one-time change in accounting principle is not expected
to have a significant effect on future property tax expense.




                                       28
<PAGE>

          2003 compared to 2002

          Taxes other than income taxes increased by $1.1 million, or 9.8%, to
$12.3 million for 2003 from $11.2 million for 2002 primarily due to increased
assessments, partially reflecting the in-service of modifications to existing
compressor stations added as part of the Eastchester Extension in 2002.

          2002 compared to 2001

          Taxes other than income taxes increased by $0.2 million, or 1.8%, to
$11.2 million for 2003 from $11.0 million for 2002, partially due to increases
in property assessments.

          Other Income and Expenses

          Other income includes certain investment income and the net of income
and expense adjustments not recognized elsewhere.

          2003 compared to 2002

          Other income and expenses increased by $6.2 million, or 229.6%, to
$8.9 million for 2003 from $2.7 million for 2002, primarily as a result of an
increase in allowance for equity funds used during construction, or Equity
AFUDC, of $6.4 million to $8.7 million for 2003 from $2.3 million for 2002. This
increase was due primarily to the Partnership's expenditures for the Eastchester
Extension. The increase was partially offset by a decrease in interest income of
approximately $0.2 million in 2003 compared to 2002 primarily due to a decrease
in the interest rate realized from investments as well as lower average cash
balances during 2003.

          2002 compared to 2001

          Other income and expenses increased by $0.9 million, or 50.0%, to $2.7
million for 2002 from $1.8 million for 2001, primarily as a result of an
increase in Equity AFUDC of $1.9 million to $2.3 million for 2002 from $0.4
million for 2001. This increase was due primarily to the Partnership's
expenditures for the Eastchester Extension. The increase was partially offset by
a decrease in interest income of approximately $1.0 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 Expense

          Interest expense relates primarily to borrowings associated with the
Partnership's construction projects, most recently the Eastchester Extension.


                                       29
<PAGE>

          2003 compared to 2002

          Interest expense increased $5.5 million, or 19.7%, to $33.4 million
for 2003 from $27.9 million for 2002. The increase in interest expense reflects
an increase in the Partnership's average debt balance due to borrowings
associated with construction of the Eastchester Extension. A $170.0 million bond
offering was completed in August 2002 at which time $144.2 million was used to
pay down the Partnership's existing bank facility, which included a $22.2
million prepayment. The Partnership's credit agreement was amended to permit the
Partnership to draw on that facility, up to an aggregate of $120.0 million, to
match construction expenditures. As of December 31, 2003, this amount had been
fully drawn by the Partnership. The details of the bond offering are discussed
in Note 3 to the Consolidated Financial Statements.

          Allowance for borrowed funds used during construction increased $5.8
million to $8.5 million for 2003 as compared to 2002 primarily due to the
Partnership's expenditures for the Eastchester Extension.

          2002 compared to 2001

          Interest expense decreased $0.8 million to $27.9 million for 2002 from
$28.7 million in 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. This decrease was partially offset by an increase
in interest expense in the second half of 2002, reflecting an increase in the
Partnership's average debt balance due primarily to the $170.0 million bond
offering which was completed in August 2002.

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

          Income Taxes

          Provision for taxes increased $4.5 million in 2003 compared to 2002
due primarily to an increase in taxable income. Provision for taxes decreased
$1.4 million in 2002 compared to 2001 due primarily to a decrease in taxable
income.

Liquidity and Capital Resources

          The Partnership's primary source of financing has been cash flow from
operations, its offerings of senior notes, bank borrowings and partner equity
contributions. 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 increased by $6.2 million to
$75.0 million in 2003 from $68.8 million in 2002 and decreased by $8.5 million
to $68.8 million in 2002 from $77.3 million in 2001, primarily due to the
effects of an increase in debt issuance costs, in 2002, associated with the
financing completed on August 14, 2002 related to the Eastchester Extension,



                                       30
<PAGE>

as more fully described below. Additionally, the revenue increase from 2002 to
2003 also contributed to the increase in net cash provided by operating
activities.

          Net cash flow related to financing activities increased by $52.2
million to $92.8 million in 2003 from $40.6 million in 2002 due to the net
effects of the 2002 Eastchester Extension financing more fully described below.
Net cash flow related to financing activities increased by $84.8 million to
$40.6 million in 2002 from ($44.2) million in 2001, due to the Eastchester
Extension financing. No new borrowings were made in 2001.

          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 provided 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
and additional partner equity contributions, were used to finance the remaining
construction of the Eastchester Extension and for general corporate purposes. As
of December 31, 2003, the full amount of the second tranche of term loans of
$120.0 million was drawn. As of December 31, 2003, the debt outstanding under
the Partnership's amended credit agreement net of scheduled debt repayments was
$100.0 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 December 31, 2003 and December 31,
2002, the aggregate notional principal amount of these two swaps was $30.6
million and $36.1 million, respectively. The fair value of these interest rate
swaps, net of taxes at December 31, 2003 and December 31, 2002, was ($2.0)
million and ($2.8) 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.



                                       31
<PAGE>

          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, 2003, the outstanding principal balance on the revolving credit
facility was $10.0 million. As of December 31, 2002, there were no amounts
outstanding under this facility.

          Capital expenditures for 2003 were $153.1 million, compared to $109.4
million in 2002, reflecting primarily the increased construction activity
related to the Eastchester Extension during the year. In addition, there were
expenditures associated with a compressor station site, general plant purchases
and other miscellaneous projects. Capital expenditures in 2002 also consisted of
expenditures relating to the Eastchester Extension, expenditures associated with
a meter station and interconnect, a compressor station, general plant purchases
and other miscellaneous projects. In 2001, capital expenditures of $36.4 million
were related to the Eastchester Extension, as well as general plant purchases
and other minor projects.

          Total capital expenditures for 2004 are estimated to be approximately
$30.9 million, including approximately $27.7 million for the completion of the
Eastchester Extension. The remaining capital expenditures planned for 2004 are
primarily for various general plant purchases. The Partnership expects to fund
its 2004 capital expenditures through internal sources, including cash from
operations and increased equity (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
2003 or 2002. Total cash distributions to partners of $22.0 million were made
during 2001. Partners made equity contributions to the Partnership during 2003,
which, in the aggregate, totaled $20.0 million. There were no equity
contributions made in 2002 or 2001.

Off-Balance Sheet Transactions

          At December 31, 2003, 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, 2003 (in thousands of dollars).


                                       32
<PAGE>
<TABLE>
<CAPTION>

                                      Less than                                    More than
                         Total         1 Year      1 to 3 Years   3 to 5 Years      5 Years
                         -----         ------      ------------   ------------      -------
<S>                    <C>             <C>            <C>            <C>            <C>
Long-Term Debt         $480,000        $32,222        $44,444        $44,564        $358,770

Transportation by
Others (1)               25,920          3,240          6,480          6,480           9,720

Operating Leases         10,028            920          1,513          1,488           6,107

Pension
Contributions             1,251          1,251             __             __              __
                       --------        -------        -------        -------        --------
Total Contractual
Obligations            $517,199        $37,633        $52,437        $52,532        $374,597
                       ========        =======        =======        =======        ========
</TABLE>

(1) Rates are based on known 2004 levels. Beyond 2004, demand rates are subject
    to change.


New Accounting Standards

          In April 2003, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149
primarily amends SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," to clarify the definition of a derivative and to require
derivative instruments that include up-front cash payments to be classified as
financing activity in the statement of cash flows. SFAS No. 149 is effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The adoption of SFAS No. 149 did
not have a material impact on the Partnership's financial condition or results
of operations.

          In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards for how an issuer classifies and measures in its
financial statements certain financial instruments with characteristics of both
liabilities and equity. SFAS No. 150 requires an issuer to classify a financial
instrument as a liability if that financial instrument embodies an obligation of
the issuer. The adoption of SFAS No. 150 did not have a material impact on the
Partnership's financial condition or results of operations.

          In December 2003, the FASB issued SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits, an amendment of
FASB Statements No. 87, 88, and 106." SFAS No. 132 requires that expanded
disclosures on pension and other post retirement benefit plans be included in
financial statements for fiscal years ending on or after Dec. 15, 2003. The
Partnership has adopted SFAS No. 132. See Note 10.

          In January 2003, the FASB issued FIN 46R, "Consolidation of Variable
Interest Entities." FIN 46R provides guidance on the identification of, and the
financial reporting for,



                                       33
<PAGE>

          entities over which control is achieved through means other than
voting rights, known as "variable interest entities." FIN 46R provides guidance
for determining whether consolidation is required. Certain variable interest
entities must be consolidated by the primary beneficiary if the equity investors
in the entity do not have the characteristics of a controlling financial
interest or do not have sufficient equity at risk for the entity to finance its
activities without additional subordinated financial support from other parties.
FIN 46R was effective immediately for all new variable interest entities created
or acquired after Jan. 31, 2003. The Partnership did not have any interests in
any variable interest entities during any of the current reporting periods. The
application of FIN 46R had no material impact on the Partnership's financial
condition or results of operations.

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.

          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, 2003 and 2002, the Partnership recorded regulatory
assets of $20.6 million and $15.7 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.



                                       34
<PAGE>

          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 $30.6 million, and a fair
value of ($2.0) 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 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, litigation and business developments that cause
operating and financial uncertainties.


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.



                                       35
<PAGE>

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


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

          The financial instruments held or issued by the Partnership are for
purposes other than trading or speculation. The Partnership is exposed to risk
resulting from interest rate changes on its variable-rate debt. 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, 2003, the Partnership had
$110.0 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 $0.8 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.

ITEM 9A. DISCLOSURE CONTROLS AND PROCEDURES



                                       36
<PAGE>

Evaluation of Disclosure Controls and Procedures

          As of the end of the period covered by 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 effectiveness 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 Rule 15d-15 under the Securities Exchange Act of 1934) are designed
to ensure that information required to be disclosed by the Partnership in
reports that it files or submits under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported, within the time periods specified
in the SEC's rules and forms 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.




                                       37
<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.
<TABLE>
<CAPTION>

       Name                     Age                 Position
       ----                     ---                 --------

<S>                              <C>   <C>
E.J. "Jay" Holm 59 President
Paul Bailey                      57    Vice President and Chief Financial Officer
Jeffrey A. Bruner                45    Vice President, General Counsel and Secretary
Herbert A. Rakebrand III*        47    Vice President, Marketing and Transportation
</TABLE>

          E.J. "Jay" Holm is President of IPOC. Jay Holm replaced Craig Frew and
began his duties as President of the Iroquois Pipeline Operating Company on
April 15, 2003. Mr. Holm has over 30 years of experience in the natural gas
business. From 1968-1982, Mr. Holm served in several management and operations
positions at Northern Natural Gas. He joined Tenneco/El Paso in June 1982, where
he served as Vice President, Northern Operations from 1987-1990, when he became
President of the Kern River Transmission Company. In 1995, Mr. Holm became Sr.
Vice President, Customer Service and Business Development for Tenneco Energy/El
Paso. In 1998, he relocated to Perth, Western Australia, to become CEO of Epic
Energy. In January 2001, Mr. Holm assumed a new assignment as CEO of El Paso's
Eastern Pipeline Group. The following year, he became COO of El Paso Global LNG.
Mr. Holm also served as a Director of the Houston Hospice and Houston Society
for the Performing Arts before coming to Iroquois in Connecticut.

          Paul Bailey is Vice President and Chief Financial Officer of IPOC. Mr.
Bailey has 21 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 24 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. Rakebrand resigned as Vice President of Marketing and Transportation of
IPOC effective as of March 31, 2004. A successor has not yet been appointed.

                                       38
<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.

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             46         Dominion Resources, Inc.                         Dominion Iroquois, Inc.

  Carl A. Taylor                39         Energy East                                      TEN Transmission Company


  Richard A. Rapp               54         KeySpan Corporation                              NorthEast Transmission
                                                                                            Company, KeySpan IGTS
                                                                                            Corp.

  Joseph P. Shields             47         New Jersey Natural Gas Company                   NJNR Pipeline Company

  Peter Lund                    45         National Energy & Gas Transmission, Inc.         JMC-Iroquois, Inc.
                                                                                            Iroquois Pipeline
                                                                                            Investment, LLC

  Dean K. Ferguson              34         TransCanada Pipelines Limited                    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.

          Carl A. Taylor is President of NYSEG Solutions, EnergyEast Solutions
and TEN Transmission Company.

          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.



                                       39
<PAGE>

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

          Peter Lund has been Vice President-Pipeline Marketing and Development
of National Energy & Gas Transmission, Inc. (NEGT), and one of its subsidiary
companies, Gas Transmission Northwest Corporation, since June 1995. Lund also
serves in the same capacity for North Baja Pipeline, LLC, another NEGT owned gas
transmission company. Before joining Gas Transmission Northwest Corporation in
1988, Lund worked as a resource analyst for Pacific Gas and Electric Company and
was a mineral exploration geologist for various firms. Mr. Lund is a board
member and chair-elect of the Western Energy Institute, a board member of the
Private Industry Sponsors of the Canadian Energy Research Institute and a board
member and former president of the Northwest Gas Association. Mr. Lund has been
a member of the management committee of the Partnership since 1999.

          Dean K. Ferguson is Director, Gas Transmission East at TransCanada
Pipelines Limited. Since 1996, Mr. Ferguson has held a number of supervisory and
management positions with TransCanada in the areas of business development and
commercial operations of the pipeline business.

Code of Ethics

          The Partnership does not have a Code of Ethics because it conducts all
of its operations through its wholly owned subsidiary, IPOC. IPOC has a Code of
Business Ethics that applies to its principal executive officer, principal
financial officer and controller, as well as all of its other employees. A copy
of the Code of Business Ethics has been filed as an exhibit to this report. The
Code of Business Ethics can also be found at www.Iroquois.com under the section
entitled, "Corporate Information." Certain amendments to or waivers of the Code
of Business Ethics that apply to IPOC's principal executive officer, principal
financial officer or controller will be disclosed through a posting on this
website.

ITEM 11. EXECUTIVE COMPENSATION

          Summary Compensation Table. The following summary compensation table
sets forth information regarding compensation for fiscal years 2003, 2002 and
2001 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.


                                       40
<PAGE>

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

<S>            <C>                   <C>          <C>                      <C>        <C>                <C>
  Craig R. Frew(4)                   2003         $96,026.49               $0         ---                $125,841.81
       President                     2002         270,169.12       108,100.00         ---                 232,725.00
                                     2001         297,231.80       160,000.00         ---                 137,347.00

  Edward J. Holm(4)                  2003        $214,748.79          $98,658     $153,009.10                     $0
       President

  Paul Bailey                        2003        $197,050.67       $43,936.00         ---                $113,026.57
       Vice President and Chief      2002         193,089.42        57,000.00         ---                 106,122.20
       Financial Officer             2001         186,200.04        84,000.00         ---                  64,181.70

  Jeffrey A. Bruner                  2003        $167,335.08       $44,172.00         ---                 $67,886.42
       Vice President, General       2002         157,103.91        39,100.00         ---                  59,409.00
       Counsel and Secretary         2001         150,000.24        60,000.00         ---                  37,180.77

  Herbert A. Rakebrand III(5)        2003        $190,479.02       $41,974.00         ---                 $89,766.90
       Vice President, Marketing     2002         190,895.76        54,400.00         ---                  79,268.01
       and Transportation            2001         177,107.86        65,000.00         ---                  48,668.00

  David J. Warman(6)                 2003        $101,490.92               $0         ---                $207,557.50
       Vice President,               2002         144,853.33        35,000.00         ---                  58,584.92
       Engineering                   2001         131,257.96        54,000.00         ---                  36,162.50
       and Operations
</TABLE>

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

(1)       Amounts reported for the 2001, 2002 and 2003 fiscal years,
          respectively, include salary paid in lieu of vacation for the
          following: Mr. Frew -- $3,492.70, $0 and $1,695.83; Mr. Bailey -- $0,
          $3,165.40 and $3,328.05; Mr. Bruner -- $0, $653.85, and $7,755.92; Mr.
          Rakebrand -- $4,307.70, $9,455.28 and $5,409.72; and Mr. Warman --
          $1,657.84, $4,884.93 and $13,876.08. The amount reported for the 2003
          fiscal year for Mr. Holm includes $10,633.33 for salary paid in lieu
          of vacation.

(2)       Disclosure is not required of any perquisites or other personal
          benefits since the amount of any such benefits for each named
          executive officer is less than $50,000 and less than 10% of the total
          annual salary and bonus reported for the named executive officer,
          except disclosure includes reimbursement of certain relocation
          expenses of $149,383.92 and an automobile allowance of $3,625.18 for
          Mr. Holm for the 2003 fiscal year.

(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. The general terms of the long-term
          incentive plan are discussed below in a separate section. For fiscal
          year 2003, the named executive officers became entitled to receive the
          following amounts under the long-term incentive plan: Mr. Frew became
          entitled to receive $120,096.00; Mr. Holm became entitled to receive
          $0; Mr. Bailey became entitled to receive $103,256.00; Mr. Bruner
          became entitled to receive $59,823.00; Mr. Rakebrand became entitled
          to receive $80,429.00; and Mr. Warman became entitled to receive $0.
          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

                                       41
<PAGE>

          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 2001, 2002 and 2003
          fiscal years, respectively, under the 401(k) Plan: Mr. Frew received
          $8,500, $10,000 and $4,745.81; Mr. Bailey received $8,500, $9,580.70
          and $9,770.57; Mr. Bruner received $7,582.77, $7,907.00 and $8,063.42;
          Mr. Rakebrand received $8,500, $9,147.50 and $9,337.90; and Mr. Warman
          received $6,564.50, $7,082.92 and $4,429.50. Mr. Holm received an
          amount equal to $0 during the 2003 fiscal year under the 401(k) Plan.
          The following amounts were received during the 2001, 2002 and 2003
          fiscal years, respectively, under the Supplemental Plan: Mr. Frew
          received $2,000, $2,000 and $1,000; Mr. Bailey received $714.70,
          $894.50 and $0, and Mr. Rakebrand received $0, $224.51 and $0. In
          addition, in consideration for the various conditions and promises set
          forth in the applicable separation agreement, Mr. Warman will receive
          payments in an amount equal to $203,128.00 to be paid in five equal
          installments during the one-year period from the date of resignation.

(4)       Mr. Frew retired as President of Iroquois Pipeline Operating Company
          effective as of April 30, 2003. Mr. Holm replaced Mr. Frew as
          President of Iroquois Pipeline Operating Company effective as of April
          15, 2003. Please see the description above under "Executive Officers"
          for Mr. Holm's biography.

(5)       Mr. Rakebrand resigned as Vice President, Marketing and Transportation
          effective as of March 31, 2004. In connection with Mr. Rakebrand's
          resignation as an executive officer of IPOC, he entered into a
          separation agreement with IPOC, which is described below under
          "Separation Agreements with Certain Executive Officers" and is filed
          as Exhibit 10.11 to the Partnership's 2003 Annual Report on Form 10-K.

(6)       Mr. Warman resigned as Vice President, Engineering and Operations
          effective as of July 31, 2003. In connection with Mr. Warman's
          resignation as an executive officer of IPOC, he entered into a
          separation agreement with IPOC, which is described below under
          "Separation Agreements with Certain Executive Officers" and is filed
          as Exhibit 10.12 to the Partnership's 2003 Annual Report on Form 10-K.

Long-Term Incentive Plan Awards 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 human
resources committee, which is a sub-committee of the management 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


                                       42
<PAGE>

forfeited and no payment will be paid with respect to such forfeited Performance
Units. 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 2003.

<TABLE>
<CAPTION>
                                 Long-Term Incentive Plan Awards in Last Fiscal Year
                                                                                   Estimated Future Payouts
                                                     Performance Period Until          Under Non-Stock
Name                         Number of Units           Maturation or Payout         Price-Based Plan (1)
----                         ---------------           --------------------         --------------------
<S>                                    <C>                         <C>                           <C>
                                       0                            0                            $0
Craig R. Frew
                                     150                 2003-2005(2)                     $138,234
Edward J. Holm                        75                 2003-2006(3)                      $65,216
                                      75                 2003-2007(4)                      $57,572

                                      60                 2003-2005(2)                      $55,294
Paul Bailey                           30                 2003-2006(3)                      $26,086
                                      30                 2003-2007(4)                      $23,029

                                      45                 2003-2005(2)                      $41,470
Jeffrey A. Bruner                   22.5                 2003-2006(3)                      $19,565
                                    22.5                 2003-2007(4)                      $17,272

                                      60                 2003-2005(2)                      $55,294
Herbert A. Rakebrand III              30                 2003-2006(3)                      $26,086
                                      30                 2003-2007(4)                      $23,029

</TABLE>

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

     (1)  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.

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

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

     (4)  Grants vest in full on December 31, 2007.

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 and Bailey take into account their
years of service with TransCanada Pipelines Limited. The benefits under the


                                       43
<PAGE>

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 2004 at
age 65, based on the straight-life annuity form of benefit payment and not
subject to deduction or offset. In calculating the benefits shown in the
following table, salaries were assumed to remain level and hypothetical account
balances were assumed to grow at 5.5% per year.


                               Pension Plan Table
<TABLE>
<CAPTION>

                                                        Years of Service
--------------------------------------------------------------------------------------------------------------
   Remuneration                15                20                 25                30                35
--------------------------------------------------------------------------------------------------------------
     <S>                      <C>               <C>               <C>               <C>              <C>
     150,000                  41,644            61,364             88,473           118,618           160,292
     200,000                  57,053            84,196            121,453           163,096           220,559
     250,000                  72,462           107,028            154,432           207,574           280,825
     300,000                  87,872           129,860            187,411           252,052           341,093
     350,000                 103,281           152,692            220,390           296,529           401,359
     400,000                 118,691           175,524            253,369           341,008           461,625
     450,000                 134,100           198,356            286,348           385,486           521,890
     500,000                 149,509           221,188            319,327           429,964           582,157
</TABLE>

          The number of years of credited service, as of December 31, 2003, for
Messrs. Holm, Bailey, Bruner, and Rakebrand are 0.67, 21.33, 11.58, and 12.33,
respectively. The number of years of credited service for Mr. Frew, as of April
15, 2003, the date of his resignation, was 26.75. The number of years of
credited service for Mr. Warman, as of July 31, 2003, the date of his
resignation, was 21. These numbers include the credited service with TransCanada
Pipelines Limited pursuant to the excess pension plan.

Supplemental Executive Retirement Agreements

          Mr. Bailey is party to a supplemental executive retirement agreement,
dated July 1, 1997, that provides a guaranteed retirement benefit of 40% 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. Bailey is entitled to pursuant to
the IPOC pension plan and excess pension plan, certain TransCanada Pipelines
pension plans, the IPOC 401(k) plan and his social security benefits.

          Mr. Frew is also a party to a similar supplemental executive
retirement agreement, dated July 1, 1997; however, Mr. Frew's guaranteed
retirement benefit is 60% of his three-year average annual compensation,
including salary and bonus for the three highest consecutive calendar years
during his employment with IPOC. There were no payments due to Mr. Frew in
connection with his resignation pursuant to the supplemental executive
retirement agreement, and there are no ongoing obligations by the Partnership in
connection with the supplemental executive retirement agreement for Mr. Frew.



                                       44
<PAGE>

Separation Agreements with Certain Executive Officers

          Separation Agreement with Mr. Rakebrand. In connection with Mr.
Rakebrand's resignation as an executive officer of IPOC effective as of March
31, 2004, he entered into a separation agreement with IPOC. The separation
agreement generally provides that in consideration of the various conditions and
promises set forth therein: (1) he would receive an aggregate amount equal to
$328,677 to be paid in five equal installments during the one-year period from
the date of resignation and (2) IPOC would pay the cost for COBRA insurance
continuation until the earlier of a one-year period from resignation or Mr.
Rakebrand becomes eligible for coverage under another employer's plan. The
foregoing description of the separation agreement does not purport to be
complete and is qualified in its entirety by reference to such agreement, which
is filed as Exhibit 10.11 to the Partnership's 2003 Annual Report on Form 10-K.

          Separation Agreement with Mr. Warman. In connection with Mr. Warman's
resignation as an executive officer of IPOC effective as of July 31, 2003, he
entered into a separation agreement with IPOC. The separation agreement
generally provides that in consideration of the various conditions and promises
set forth therein: (1) he would receive an aggregate amount equal to the payment
referenced in the "All Other Compensation" column in the Summary Compensation
Table above to be paid in five equal installments during the one-year period
from the date of resignation and (2) IPOC would make monthly payments for Mr.
Warman's medical coverage through COBRA until August 2004. The foregoing
description of the separation agreement does not purport to be complete and is
qualified in its entirety by reference to such agreement, which is filed as
Exhibit 10.12 to the Partnership's 2003 Annual Report on Form 10-K.

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.


                                       45
<PAGE>


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 Corporation            NorthEast Transmission Company      18.07%         1.33%             19.4%

                                 Keyspan IGTS Corp.                   1.0%            --              1.0%

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

  National Energy & Gas          JMC-Iroquois, Inc.                  4.57%           .36%             4.93%
  Transmission, Inc.             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 48% of natural gas under long-term firm
contract was transported by affiliates of partners for the year ended December
31, 2003.

PART IV.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

          The following table sets forth the aggregate fees incurred for audit
services rendered by PricewaterhouseCoopers LLP in connection with the
consolidated financial statements and reports for 2003 and 2002 and for other
services rendered during 2003 and 2002 on behalf of the Partnership:

                                       46
<PAGE>



         Fee Category                     2003               2002
         ------------                     ----               ----
         Audit Fees                     141,500            178,925
         Audit-Related Fees              21,000             21,000
         Tax Fees                        39,500             26,416
         All Other Fees                      __                 __
                                   --------------      --------------
         Total Fees:                    202,000            226,341

Audit Fees

          Audit fees consist of fees incurred for professional services rendered
for the audits of the Partnership's annual consolidated financial statements and
reviews of the interim condensed consolidated financial statements included in
quarterly reports. In 2002, audit fees also included fees incurred for review of
the Partnership's refinancing documents.

Audit-Related Fees

          Audit-related fees consist of fees incurred for assurance and related
services that are reasonably related to the performance of the audit or review
of the Partnership's consolidated financial statements and are not reported
under "Audit Fees." These services include benefit plan audits.

Tax Fees

          Tax fees consist of the following:

                                    2003            2002
                                    ----            ----
               Tax Compliance      19,500           19,500
               Tax and Advice      20,000            6,916
                                 ----------       ----------
               Total               39,500           26,416

All Other Fees

          All other fees consist of fees for all other services other than those
reported above. The Partnership did not incur any of these fees in 2002 or 2003.





                                       47
<PAGE>

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

     (a)  1.   Financial Statements

               The Index to Financial Statements Page F-1 is incorporated herein
               by reference as the list of financial statements required as part
               of this report.

          2.   Financial Statement Schedules

               None.

          3.   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.



                                       48
<PAGE>

  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.

  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.

  10.11        Separation Agreement between Herbert Rakebrand III and Iroquois
               Pipeline Operating Company.

  10.12        Separation Agreement between David Warman and Iroquois Pipeline
               Operating Company.

  14.1         Code of Ethics.

  12.1*        Statements regarding computation of ratios.

  21.1*        List of Subsidiaries of the Partnership.

  31.1         Rule 15d-14(a) Certification of Principal Executive Officer.

  31.2         Rule 15d-14(a) Certification of Chief Financial Officer.

  32.1         Section 1350 Certifications.


                                       49
<PAGE>
_____________________________

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

**        Previously filed as an exhibit to the Partnership's Annual Report
          on Form 10-K for the year ended December 31, 2002.

(b)       Reports on Form 8-K

          Current Report on Form 8-K filed October 3, 2003 (Item 5).
          Current Report on Form 8-K/A filed October 3, 2003 (Item 5).





                                       50
<PAGE>



                                   SIGNATURES

         Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

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


Date: March 29, 2004          By:   /s/ Paul Bailey
                                   ---------------------------------------
                                   Name:  Paul Bailey
                                   Title: Vice President and
                                          Chief Financial Officer


                              By:   /s/ Jay Holm
                                   ---------------------------------------
                                   Name:  E.J. "Jay" Holm
                                  Title:  President

          Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on March 29, 2004.

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

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

/s/ Jay Holm                          President of Iroquois Pipeline
----------------------------          Operating Company
E.J. "Jay" Holm

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

/s/ Carl A. Taylor                    Representative on the Management Committee
----------------------------
Carl A. Taylor

/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/ Dean K. Ferguson                  Representative on the Management Committee
----------------------------
Dean K. Ferguson

/s/ Joseph P. Shields                 Representative on the Management Committee
----------------------------
                                       51
<PAGE>

Joseph P. Shields




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


                                       52

<PAGE>


                          INDEX TO FINANCIAL STATEMENTS

                                                                            Page
                                                                            ----

Report of Independent Auditors...............................................F-2

Financial Statements

         Consolidated Statements of Income for the years
             ended December 31, 2003, 2002 and 2001..........................F-3

         Consolidated Balance Sheets as of
             December 31, 2003 and 2002......................................F-4

         Consolidated Statements of Cash Flows for the years
             ended December 31, 2003, 2002 and 2001..........................F-6

         Statements of Changes in Partners' Equity for the
             years ended December 31, 2003, 2002, 2001 and 2000..............F-8

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






                                      F-1
<PAGE>



                         REPORT OF INDEPENDENT AUDITORS

          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, 2003 and 2002, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2003 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

                                                                January 30, 2004



                                      F-2
<PAGE>
                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
                        CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>

                                                                          (thousands of dollars)
FOR YEAR ENDED DECEMBER 31                                         2003              2002            2001

<S>                                                             <C>                 <C>             <C>
OPERATING REVENUES                                              $132,009            $126,320        $128,270

OPERATING EXPENSES:
  Operation and maintenance                                       26,081              26,112          22,108
  Depreciation and amortization                                   24,090              23,684          23,847
  Taxes other than income taxes                                   12,333              11,206          10,953
                                                                 -------             -------         -------

    Total Operating Expenses                                      62,504              61,002          56,908
                                                                 -------             -------         -------

OPERATING INCOME                                                  69,505              65,318          71,362
                                                                 -------             -------         -------

OTHER INCOME/(EXPENSES):
  Interest income                                                    226                 416           1,412
  Allowance for equity funds used
    during construction                                            8,670               2,319             444
  Other, net                                                         (46)                (27)            (27)
                                                                 -------             -------         -------
                                                                   8,850               2,708           1,829
                                                                 -------             -------         -------

INCOME BEFORE INTEREST CHARGES, TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE                                                         78,355              68,026          73,191
                                                                 -------             -------         -------

INTEREST EXPENSE:
  Interest expense                                                33,384              27,892          28,736
  Allowance for borrowed funds
    used during construction                                      (8,565)             (2,744)           (669)
                                                                 -------             -------         -------

    Net Interest Expense                                          24,819              25,148          28,067
                                                                 -------             -------         -------

INCOME BEFORE TAXES AND CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE                                           53,536              42,878          45,124

PROVISION FOR TAXES                                               21,435              16,911          18,275
                                                                 -------             -------         -------

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
                                                                  32,101              25,967          26,849



                                      F-3
<PAGE>

ACCOUNTING PRINCIPLE
CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE,
NET OF TAX                                                         3,715                  __              __
                                                            ------------------- --------------- ----------------
NET INCOME                                                       $35,816             $25,967         $26,849
                                                            =================== =============== ================
</TABLE>


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



                                      F-4
<PAGE>



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


ASSETS                                            (thousands of dollars)
AT DECEMBER 31                                  2003                  2002

CURRENT ASSETS:
  Cash and temporary cash investments           $36,344               $21,620
  Accounts receivable - trade, net                7,080                 6,384
  Accounts receivable - affiliates                5,495                 5,470
  Other current assets                            6,413                 3,838
                                              -------------        -------------
    Total Current Assets                         55,332                37,312
                                              -------------        -------------

NATURAL GAS TRANSMISSION PLANT:
  Natural gas plant in service                  802,220               796,647
  Construction work in progress                 280,528               125,951
                                              -------------        -------------
                                              1,082,748               922,598
  Accumulated depreciation and amortization    (323,405)             (301,123)
                                              -------------        -------------
    Net Natural Gas Transmission Plant          759,343               621,475
                                              -------------        -------------

OTHER ASSETS AND DEFERRED CHARGES:
  Regulatory assets - income tax related         19,174                14,080
  Regulatory assets - other                       1,473                 1,661
  Other assets and deferred charges              13,383                14,857
                                              -------------        -------------
    Total Other Assets and Deferred Charges      34,030                30,598
                                              -------------        -------------
    TOTAL ASSETS                               $848,705              $689,385
                                              =============        =============


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



                                      F-5
<PAGE>



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


LIABILITIES AND PARTNERS' EQUITY                     (thousands of dollars)
AT DECEMBER 31                                       2003              2002

CURRENT LIABILITIES:
  Accounts payable                                  $21,424         $ 16,703
  Accrued interest                                    4,626            6,839
  Current portion of long-term debt (Note 3)         32,222           22,222
  Accrued property taxes                                  -            3,780
  Other current liabilities                           7,425            3,999
                                              -------------        ------------
   Total Current Liabilities                         65,697           53,543
                                              -------------        ------------
LONG-TERM DEBT (NOTE 3)                             447,778          385,000
                                              -------------        ------------
OTHER NON-CURRENT LIABILITIES:
  Unrealized loss-interest rate hedge (Note 2)        3,263            4,635
  Other non-current liabilities                       1,821            2,281
                                              -------------        ------------
    Total Other Non-Current Liabilities               5,084            6,916
                                              -------------        ------------
AMOUNTS EQUIVALENT TO
 DEFERRED INCOME TAXES:
  Generated by Partnership                          122,220          100,355
  Payable by Partners                              (103,046)         (86,275)
  Related to Other Comprehensive Income              (1,671)          (2,227)
                                              -------------        ------------
    Total Amounts Equivalent to Deferred
    Income Taxes                                     17,503           11,853
                                              -------------        ------------
COMMITMENTS AND CONTINGENCIES (NOTE 7)
   TOTAL LIABILITIES                                536,062          457,312
                                              -------------        ------------
PARTNERS' EQUITY                                    312,643          232,073
                                              -------------        ------------
  TOTAL LIABILITIES AND
  PARTNERS' EQUITY                                 $848,705         $689,385
                                              =============        ============


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



                                      F-6
<PAGE>



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


<TABLE>
<CAPTION>

                                                                                    (thousands of dollars)
FOR THE YEARS ENDED DECEMBER 31                                              2003              2002            2001

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                          <C>              <C>               <C>
  Net Income                                                                 $35,816          $25,967           $26,849
  Adjusted for the following:
    Depreciation and amortization                                             24,090           23,684            23,847
    Allowance for equity funds used
      during construction                                                     (8,670)          (2,319)             (444)
    Deferred regulatory assets-income tax related                             (5,094)            (782)              336
    Amounts equivalent to deferred income taxes                                5,094              782              (336)
    Income and other taxes payable by Partners                                23,916           16,911            18,275
    Other assets and deferred charges                                          1,551           (8,446)              718
    Other non-current liabilities                                               (515)             257               803
    Changes in Working Capital:
       Accounts receivable                                                      (721)            (107)            1,575
       Other current assets                                                   (2,575)            (544)             (367)
       Accounts payable                                                        4,721            9,048             4,016
       Accrued interest                                                       (2,213)           3,930                --
       Other liabilities                                                        (354)             401             1,993
                                                                        -------------     -----------      ------------
NET CASH PROVIDED BY
OPERATING ACTIVITIES:                                                         75,046           68,782            77,265
                                                                        -------------     -----------      ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures                                                      (153,100)        (109,433)          (36,340)
                                                                        -------------     -----------      ------------
   NET CASH USED FOR INVESTING ACTIVITIES                                   (153,100)        (109,433)          (36,340)
                                                                        -------------     -----------      ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Partner distributions                                                           --               --           (22,000)
  Long-term debt borrowings                                                   95,000          205,000                --
  Repayments of long-term debt                                               (22,222)        (164,444)          (22,223)
  Partner contributions                                                       20,000               --                --
                                                                        -------------     -----------      ------------
    NET CASH PROVIDED BY/(USED FOR)
    FINANCING ACTIVITIES                                                      92,778           40,556           (44,223)
                                                                        -------------     -----------      ------------
NET INCREASE/(DECREASE) IN CASH AND
  TEMPORARY CASH INVESTMENTS                                                  14,724              (95)           (3,298)

CASH AND TEMPORARY CASH INVESTMENTS
   AT BEGINNING OF YEAR                                                       21,620           21,715            25,013
                                                                        -------------     -----------      ------------


                                      F-7
<PAGE>

CASH AND TEMPORARY CASH
  INVESTMENTS AT END OF YEAR                                                 $36,344          $21,620           $21,715
                                                                        -------------     -----------      ------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
  CASH PAID FOR INTEREST                                                     $33,969          $23,060           $28,011
                                                                        =============     ===========      =============
</TABLE>

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



                                      F-8
<PAGE>




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


        PARTNERS' EQUITY                             (thousands of dollars)

        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
          Other comprehensive loss, net of tax                  (1,569)
                                                            -----------

        BALANCE AT DECEMBER 31, 2002                          $232,073

          Net income 2003                                       35,816
          Taxes payable by Partners                             23,916
          Equity contributions from Partners                    20,000
          Other comprehensive income, net of tax                   838
                                                                ------

        PARTNERS' EQUITY
        BALANCE AT DECEMBER 31, 2003                          $312,643
                                                              ========




                                      F-9
<PAGE>



                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

          NOTE 1

          DESCRIPTION OF PARTNERSHIP:

          Iroquois Gas Transmission System, L.P., (the "Partnership" or the
"Company") is a Delaware limited partnership that owns and operates a natural
gas transmission pipeline from the Canada-United States border near Waddington,
NY, to South Commack, Long Island, NY and Hunt's Point, New York. 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, 2003, 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%), KeySpan IGTS Corp.
(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 2003 or 2002.
Total cash distributions of $22.0 million were made during 2001.

          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-10
<PAGE>

          Cash and Temporary Cash Investments

          The Partnership 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 $36.3 million at December
31, 2003 and $21.6 million at December 31, 2002 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, which includes primarily vehicles,
leasehold improvements and computer equipment, is depreciated on a straight-line
basis over five years.

          Construction Work In Progress

          At December 31, 2003, 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. The Partnership's approved rates, however, include an allowance
for taxes (calculated as if it were a corporation) and the FERC requires the
Partnership to record such taxes in the Partnership records to reflect the taxes
payable by the Partners as a result of the Partnership's operations. These taxes
are recorded without regard as to whether each Partner can utilize its share of
the Partnership 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.

          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-11
<PAGE>

          Change in Method of Accounting for Municipal Property Taxes

          As of December 31, 2003, the Company changed its method of accounting
for municipal property taxes to provide a better matching of property tax
expense with the receipt of services provided by the municipalities. Most
municipalities in Connecticut assess property values as of October 1 of each
year (lien date) with payments due the following July 1, for the year beginning
that July 1. Most New York municipalities assess property values as of July 1
(lien date) with payments due the following January 1 for the year beginning
that January 1. New York school districts also follow a similar process.

          Through the calendar year ended December 31, 2002, the Company accrued
property taxes based on estimated assessments beginning on the lien date. For
the calendar year ended December 31, 2003, the Company began to recognize the
actual property tax expense over the same period that the towns recognize the
income from those taxes. The cumulative effect of this change in accounting for
municipal property taxes, all of which is recognized in the quarter ended
December 31, 2003 is a reduction to expense of approximately $6.2 million before
income taxes and is reflected on the income statement as a cumulative effect of
change in accounting principle. If the Partnership had accounted for property
taxes in this manner for 2002 and 2001, the amounts that would have been
reported as property tax expense for these years would not have been
significantly different than what is actually reported. This one-time change in
accounting principle is not expected to have a significant effect on future
property tax expense.


          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. These estimates may involve determining the economic useful
lives of the Partnership's assets, the fair values used to determine possible
asset impairment charges, provisions for uncollectible accounts receivable,
exposures under contractual indemnifications, calculations of pension expense
and various other recorded or disclosed amounts. The Partnership believes that
its estimates for these items are reasonable, but cannot assure you that actual
amounts will not vary from estimated amounts.


          New Accounting Standards

          In April 2003, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149
primarily amends SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," to clarify the definition of a derivative and to require
derivative instruments that include up-front cash payments to be classified as
financing activity in the statement of cash flows. SFAS No. 149 is effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated



                                      F-12
<PAGE>

after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact
on the Company's financial condition or results of operations.

          In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards for how an issuer classifies and measures in its
financial statements certain financial instruments with characteristics of both
liabilities and equity. SFAS No. 150 requires an issuer to classify a financial
instrument as a liability if that financial instrument embodies an obligation of
the issuer. The adoption of SFAS No. 150 did not have a material impact on the
Company's financial condition or results of operations.

          In December 2003, the FASB issued SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits, an amendment of
FASB Statements No. 87, 88, and 106." SFAS No. 132 requires that expanded
disclosures on pension and other post retirement benefit plans be included in
financial statements for fiscal years ending on or after Dec. 15, 2003. The
Company has adopted SFAS No. 132. See Note 10.

          In January 2003, the FASB issued FIN 46R, "Consolidation of Variable
Interest Entities." FIN 46R provides guidance on the identification of, and the
financial reporting for, entities over which control is achieved through means
other than voting rights, known as "variable interest entities." FIN 46R
provides guidance for determining whether consolidation is required. Certain
variable interest entities must be consolidated by the primary beneficiary if
the equity investors in the entity do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. FIN 46R was effective immediately for all new
variable interest entities created or acquired after Jan. 31, 2003. The Company
did not have any interests in any variable interest entities during any of the
current reporting periods. The application of FIN 46R had no material impact on
the Company's financial condition or results of operations.



                                      F-13
<PAGE>

          Other Comprehensive Income

          Comprehensive Income consisted of the following (in thousands of
dollars):

        At December 31,                                2003          2002
        ---------------                                ----          ----

        NET INCOME:                                  $32,111      $ 25,967
                                                  -----------   ------------
        OTHER COMPREHENSIVE INCOME (LOSS):
        Unrealized loss on interest rate hedge,
           net of tax                                   (345)       (2,207)
        Reclassification to net income, net of tax     1,171         1,205
        Unrealized gain (loss) on interest rate
           hedge, net of reclassification
           adjustment                                    826        (1,002)
        Additional minimum liability on
           pension plan, net of tax                      (34)         (567)
        Unrealized gain on supplemental
           pension plan, net of tax                       46            __
                                                  -----------   ------------
        Comprehensive Income                         $32,949      $ 24,398
                                                  ===========   ============

          NOTE 3

          FINANCING:

          On May 30, 2000, the Partnership 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, the Partnership 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. Prior to the amendment discussed below, the
Term Loan Facility was scheduled to be amortized over nine years.

          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 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, the Partnership
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



                                      F-14
<PAGE>

the term of the amended credit agreement which was also completed on that date.
As of December 31, 2003 and December 31, 2002, the aggregate notional principal
amount of these two swaps was $30.6 million and $36.1 million, respectively. The
fair value of these interest rate swaps, net of taxes at December 31, 2003 and
December 31, 2002, was ($2.0) million and ($2.8) 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. The Partnership has
deferred and is amortizing this amount over the life of the senior notes.

          On August 14, 2002, the Partnership 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 provided for borrowings from time to time against a second tranche of
term loans, which, with cash from operations, were used to finance the
construction of the Company's Eastchester Extension and for general corporate
purposes. The Company's amended credit facilities provided 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, 2003 and December 31, 2002, the outstanding principal
balance on the 8.68% Senior Notes was $200.0 million. At December 31, 2003 and
December 31, 2002, the outstanding principal balance on the 6.1% Senior Notes
was $170.0 million. At December 31, 2003 and December 31, 2002, the outstanding
principal balance on the Term Loan Facility was $100.0 million and $37.2
million, respectively. As of December 31, 2003, the outstanding principal
balance on the revolving credit facility was $10.0 million. As of December 31,
2002, there were no amounts outstanding under this facility.

          The combined schedule of repayments at December 31, 2003 is as follows
(millions of dollars):



                                      F-15
<PAGE>

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

            2004                         $  32.2
            2005                         $  22.2
            2006                         $  22.2
            2007                         $  22.3
            2008                         $  22.3
            Thereafter                   $ 358.8


          NOTE 4

          CONCENTRATIONS OF CREDIT RISK:

          The Partnership's 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 that require 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, 2003 and December 31, 2002, 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, 2003 and
December 31, 2002, the carrying amounts and estimated fair values of the
Company's long-term debt including current maturities were as follows (in
thousands of dollars):

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

             2003           $480,000           $541,568
             2002           $407,222           $439,322




                                      F-16
<PAGE>


          NOTE 6

          GAS TRANSPORTATION CONTRACTS:

          As of December 31, 2003, the Partnership was providing firm reserved
transportation service to 35 shippers of 1,113 MDth/d of natural gas, which
breaks down as follows:


                 Remaining                 Quantity in
                 Term in Years               MDth/d
                 -------------         ------------------
                 1-5                         164.2
                 6-10                        701.4
                 11-15                       247.4
                                      ---------------------
                 Total                       1,113

          The long-term firm service gas transportation contracts expire between
November 1, 2004 and August 1, 2018.


          NOTE 7

          COMMITMENTS AND CONTINGENCIES:

          Regulatory Proceedings

          FERC Docket No. RP97-126, RP94-72 et al and RP03-589.
          -----------------------------------------------------

          On December 17, 1999 the Partnership filed with the FERC a settlement
of various outstanding rate matters (Docket Nos. RP97-126 and RP94-72). Pursuant
to the settlement the parties agreed to a rate moratorium whereby, with limited
exceptions, no new rates could be placed in effect on the Partnership's system
until January 1, 2004. In light of the expiration of the 1999 rate moratorium,
the Partnership renegotiated its effective transportation rates with its
customers and on August 29, 2003 filed a new four-year rate settlement with the
FERC in Docket No. RP03-589. On October 24, 2003, the FERC approved said
settlement which, as noted below, approved new Settlement Rates for the
Partnership's existing mainline customers and, with limited exception, provided
that no change to the mainline Settlement Rates could be placed in effect on the
Partnership's mainline system until December 31, 2007.

          The settlement establishes the Partnership's base tariff recourse
rates (Settlement Rates) for the years 2004, 2005, 2006, and 2007. The
Settlement Rates reflect annual step-downs, which over the term of the
Settlement will reduce the Partnership's transportation rates by approximately
13 % (e.g., the 100% load factor interzone rate will be reduce from the existing
level of $0.4234 per Dth, to the January 1, 2007 level of $0.3700 per Dth, for a
total cumulative



                                      F-17
<PAGE>

reduction of $0.0534 per Dth). Based on 2004 long-term firm service contracts as
of December 31, 2003, the settlement will result in reductions in revenues of
$3.8 Million in 2004, $1.5 million in 2005, $1.0 million in 2006 and $2.5
million in 2007. Under the settlement the first step-down in rates becomes
effective on July 1, 2004.

          FERC Docket No. RP04-136-000
          ----------------------------

          On January 2, 2004 the Partnership filed a Section 4 rate change
proceeding, consistent with the settlement in Docket No. RP03-589, limited to
rates for service on the Eastchester Extension Project as certificated by FERC
in Docket No. CP00-232. The Eastchester Project was in-service on February 5,
2004. The Partnership proposes a rate of $0.8444 per Dth on a 100% load-factor
basis (as compared with the Partnership's existing 100% load-factor inter-zone
rate of $0.4234 per Dth, which will serve as the initial rate per the
certificate order). The increased rate reflects, among other things, an increase
in plant costs from the certificate estimate of $210.0 million to a level of
approximately $334 million. The higher plant costs are the result of a number of
factors, including delays in obtaining construction permits and authorizations;
unanticipated environmental costs; a failed directional drill; higher than
expected labor costs; and construction incidents associated with constructing
the Project in a highly congested marine corridor. Various Partnership customers
have filed motions in response to the Partnership's requested rate change. On
January 30, 2004 the FERC issued an order accepting the rates and making them
effective July 1, 2004, subject to refund and subject to the outcome of
hearings. On February 17, 2004, a pre-hearing conference before the FERC
resulted in a procedural schedule outlining the various phases of the
Partnership's rate filing proceeding with an anticipated final order due by the
end of the second quarter of 2005. The final rate for service on the Eastchester
facilities will not be known until the conclusion of the regulatory process.
Because of the preliminary nature of this proceeding, it is impossible at this
time to determine the outcome or the effect on the Partnership's financial
position.

          FERC Order No. 637
          ------------------

          On February 9, 2000, the FERC issued Order No. 637 in Docket Nos.
RM98-10 and RM98-12. According to the FERC, 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 FERC filings to 1) remove the price cap applicable to pipeline capacity
released by firm shippers to new shippers for an experimental two year period,
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,
the Partnership submitted filings in (respectively) Docket Nos. RP00-411 and
RP00-529 to implement the provisions of Order No. 637. In response to various
interim orders issued by the FERC, the Partnership submitted numerous additional
compliance filings in 2003, which were ultimately accepted by the FERC.
Management believes all Order No. 637 requirements have been met.


                                      F-18
<PAGE>


          FERC Order No. 2004
          -------------------

          On November 25, 2003 the FERC issued Order No. 2004 in FERC Docket No.
RM01-10. According to the FERC, Order No. 2004 adopts new standards of conduct
that apply uniformly to interstate natural gas pipelines and public utilities
and that replace standards of conduct currently in effect. The standards of
conduct are designed to ensure that transmission providers do not provide
preferential access to service or information to affiliated entities. Under the
schedule adopted by the FERC, on February 9, 2004 the Partnership submitted its
plan and schedule for implementing Order No. 2004. By June 1, 2004 the
Partnership will post its revised standards of conduct on its internet website,
identifying the procedures established for implementing the FERC's requirements.
Management does not believe that the requirements of Order No. 2004 will have a
material impact on the Partnership.

          Eastchester Certificate Application (FERC Docket No. CP00-232)
          --------------------------------------------------------------

          On April 28, 2000, the Partnership filed an application with the FERC
to construct and operate its "Eastchester Extension Project". Under this
proposal, as subsequently modified, the Partnership 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 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 FERC issued a certificate authorizing the
Partnership to construct and operate the Eastchester facilities ("December 26
Order"). A condition in the FERC 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, failed to do so.
Therefore, on February 28, 2002, the Partnership filed a request with the FERC
to modify the condition in the December 26 Order and to permit the Partnership
to commence construction with executed long-term service contracts for 65% of
the full 230 MDth/d of service. This request was granted by the FERC in an order
dated March 13, 2002. The Partnership currently has contracted with shippers for
210 MDth/d of service (170 Mdth/d of which is long-term) on the Eastchester
facilities.

          On April 19, 2002, the Company began constructing its Eastchester
Expansion Project. Construction of the Long Island Sound portion of the project
commenced in October 2002. Final project construction costs have increased and
are currently estimated at approximately $334 million, rather than the $210.0
million estimated during the FERC's certificate process and will likely reduce
the initial margins that were anticipated when the project application was
initially filed with the FERC. The project was completed and began service on
February 5, 2004. See additional comments under FERC Docket No. RP04-136 (above)
and Legal Proceedings - Other (below).


                                      F-19
<PAGE>


          Athens Project (FERC Docket No. CP02-20-000)
          --------------------------------------------

          On November 8, 2001, the Partnership filed an application with the
FERC to construct and operate its "Athens Project". Under this proposal, the
Partnership 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 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 facilities. However, the Partnership
anticipated having adequate capacity on its system to serve the initial 70
MDth/d transportation needs of the Athens Generating facility. As a result of
this evaluation, capacity was made available on an interim basis, allowing the
Partnership to defer the commencement of construction of the Athens Project. By
letter dated April 22, 2003, the Partnership requested a 1-year extension from
the FERC of the deadline for completion of construction of the Athens Project,
or until December 3, 2004. On May 14, 2003, the FERC granted the Partnership's'
request for the 1-year extension. As of December 31, 2003 the Partnership had
incurred approximately $1.9 million in construction expenditures related to the
Athens Project.

          Brookfield Project (FERC Docket No. CP02-31-000)
          -----------------------------------------------

          On October 31, 2002 the FERC issued a certificate authorizing the
Partnership to construct the Brookfield Project facilities.

          Based on communications with its prospective customers regarding the
timing of their needs for new firm transportation service, the Partnership has
determined that a temporary deferral of the construction of the Brookfield
Project is necessary. Specifically, Astoria Energy LLC, or Astoria, the largest
shipper for the Brookfield Project, had requested that its service be deferred
until November 1, 2005. On February 28, 2003, the Partnership and Astoria
executed an amendment to their precedent agreements reflecting this deferral.
However, on August 1, 2003, Astoria elected to terminate its precedent
agreements with the Partnership.

          The Partnership plans, however, to continue to work directly with
Astoria regarding its future natural gas transportation requirements pending
Astoria's financing of its proposed electric generating facility for which it
has a power purchase agreement with Consolidated Edison Company of New York,
Inc.

          The other original Brookfield Project shipper, PPL Energy Plus, LLC,
or PPL, has also elected to terminate its precedent agreement, and the
Partnership is currently remarketing the Brookfield Project capacity entitlement
relinquished by PPL to other potential shippers. Additionally, the Partnership
is exploring other services and products that may negate the need to find a
replacement shipper. As of December 31, 2003, the Partnership had incurred
approximately $2.5 million in construction expenditures related to the
Brookfield Project, primarily related to the purchase of the Brookfield site.

          In anticipation of these developments, on April 22, 2003, the
Partnership requested an eighteen month extension from the FERC to extend the
construction completion time of the



                                      F-20
<PAGE>

Brookfield Project to October 31, 2005. On May 14, 2003, the FERC granted the
Partnership's request and extended the construction completion date to November
1, 2005.

          On June 27, 2003, the Partnership purchased real property at 60 High
Meadow Road, Brookfield, CT, which was previously approved by the FERC as
suitable for construction of the Brookfield compressor station. In accordance
with the FERC approval, the site must be remediated before construction takes
place. Site remediation is not expected to have a material adverse impact on the
Partnership's operating results or financial condition. The Connecticut
Department of Environmental Protection is currently reviewing the project's site
remediation plan and scope of work schedule.

          Legal Proceedings-Other

          Eastchester Construction Incidents
          ----------------------------------

          On November 16, 2002, certain undersea electric transmission cables
owned by Long Island Lighting Company d/b/a The Long Island Power Authority, or
LIPA, and Connecticut Light and Power Company, or CL&P, were allegedly damaged
and/or severed when an anchor deployed by the DSV MR. SONNY, a work vessel
taking part in the construction of the Eastchester Extension, allegedly allided
with the cables. The MR. SONNY allegedly is owned by Cal Dive International,
Inc., a subcontractor of the Partnership's general contractor, Horizon Offshore
Contractors, Inc.

          On December 6, 2002, Cal Dive commenced a maritime limitation of
liability action in the United States District Court for the Eastern District of
New York, seeking exoneration from or limitation of liability in respect of this
incident. LIPA, CL&P, the Partnership, Horizon, and Thales GeoSolutions Group,
Ltd. (another of Horizon's subcontractors), have all filed claims in the
limitation action. In addition, LIPA, CL&P and their subrogated underwriters
(the "Cable Interests") filed third-party claim against the Partnership and its
operating subsidiary, IPOC, as well as Horizon and Thales, seeking recovery for
its alleged losses. The Partnership filed cross-claims against Horizon and
Thales for indemnification in respect of the Cable Interests' claims, and
Horizon filed a third-party claims against Thales. The Cable Interests
subsequently agreed to dismiss their claim against IPOC, but without prejudice
to their right to re-file that claim if they deem necessary.

          The Cable Interests are claiming a total of $34.2 million in damages,
consisting of $14.4 million for repairs and repair related costs, including LIPA
and CL&P internal costs and overheads of $4.7 million, as well as $19.9 million
in consequential damages.

          In addition to the foregoing, the Partnership has been advised that
the Town of Huntington, New York may assert a claim against the Partnership
alleging violations of certain municipal ordinances on the basis of a claim that
dielectric fluid was released from the cable as a result of the incident.

          Under the terms of the construction contract between Horizon and the
Partnership, Horizon is obligated to indemnify the Partnership for Horizon's
negligence associated with the



                                      F-21
<PAGE>

construction of the Eastchester Extension. Horizon is also contractually
responsible for its subcontractors' negligence. As required by the contract,
Horizon named the Partnership as an additional named insured under Horizon's
policies of insurance. The Partnership understands that it is covered under
Horizon's policies to the extent that Horizon has assumed liability to the
Partnership under the contract. Based on Horizon's subcontracts with Thales and
Cal Dive, the Partnership may also be entitled to coverage as an additional
insured party under those parties' policies of insurance. In addition, Thales's
underwriters have sent a letter to Thales, which was forwarded to the
Partnership's counsel on March 12, 2004, agreeing to indemnify the Partnership
in accordance with the indemnity provision in the Horizon/Thales contract. This
indemnity is subject to the policies' terms and limit of $10,000,000.00. The
details of this arrangement are being negotiated. 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 Company'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 comprised 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 disruption of power transmission over the line and
leakage of dielectric fluid. NYPA alleges that the damage was caused by an
anchor of Horizon's pipeline lay barge, the GULF HORIZON, which was in the
vicinity of NYPA's cable and was involved in work in the Eastchester Extension
at the time of the casualty.

          By letter dated March 25, 2003, counsel representing NYPA and LIPA
informed the Partnership that they intend to hold the Partnership, Horizon and
Horizon's subcontractor, Thales, jointly and severally liable for the full
extent of their damages, which they allege includes emergency response costs,
repair of the damaged electrical cable, loss of use and disruption of service,
and certain other as yet unspecified damages arising out of or relating to the
incident.

          The Partnership is a party to an agreement with NYPA, which provides,
among other things, that the Partnership will indemnify NYPA for damage to the
Y-49 cables, which results from the Partnership's or its contractors'
negligence, acts, omissions or willful misconduct. 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. Horizon is also contractually
responsible for its sub-contractor's negligence. Pursuant to the contract,
Horizon named the Partnership as an additional named insured under Horizon's
policies of insurance. The Partnership is still investigating whether Horizon's
insurance is adequate to cover the Partnership for its potential losses in this
matter. The Partnership may also be entitled to indemnity as an additional
insured under Thales' policies of insurance, although this matter is also still
subject to further investigation. The Partnership has placed Horizon and its
underwriters on notice that it intends to hold Horizon responsible. The
Partnership has further requested that Horizon assume its defense and hold it
harmless in respect of this claim; however, to date, Horizon has rejected this
request. The Partnership has also placed its own insurance underwriters on
notice and is currently investigating the applicability of all available
insurance coverages.



                                      F-22
<PAGE>

          On August 15, 2003, Horizon commenced a maritime limitation of
liability action in the United States District Court for the Southern District
of Texas, Houston Division, captioned In the Matter of Horizon Vessels Inc., as
owner of the GULF HORIZON, seeking exoneration from or limitation of liability
in connection with this incident. NYPA and LIPA (collectively, the "Y-49 Cable
Interests") also have filed claims in the limitation action asserting total
damages of approximately $21 million. On November 12, 2003, the Partnership
filed an Answer in Horizon's action, requesting that the limitation of liability
action be dismissed and/or that the limitation injunction be lifted to permit
the Partnership to pursue its claims against Horizon in the forum of its choice,
or, in the alternative, that Horizon be denied limitation rights under the
Limitation Act. The Partnership also filed a claim in Horizon's limitation
action seeking indemnity for any liability it may be found to have to the Y-49
Cable Interests as a result of the NYPA cable incident as well as all losses
suffered by the Partnership as a result thereof, and, on a protective basis,
seeking full damages for Horizon's breaches and deficient performance under the
Partnership/Horizon construction contract, which claims are unrelated to the
NYPA cable incident. Thales also has filed a claim in the Horizon limitation
action seeking indemnity for any liability it may be found to have to the Y-49
Cable Interests or the Partnership. The Y-49 Cable Interests and the Partnership
both have filed motions to transfer the Texas action to the United States
District Court for the Eastern District of New York. Thales has joined in those
motions. By order entered February 27, 2004, the court denied the motions to
transfer. However, in doing so, the court confirmed that the Partnership could
pursue its contract claims against Horizon outside of the limitation action.

          The Partnership is still in the process of investigating this incident
and evaluating its rights, obligations and responsibilities. Given the
preliminary stage of this matter, 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.

          The Partnership has also learned that as part of the Eastchester
construction there may have been one or more violations by the contractor of the
exclusionary zones established around certain specified areas of possible
cultural resources, namely underwater archeological sites such as shipwrecks,
along the pipeline's marine route and the contractor may have placed anchors
outside the authorized construction corridor. At this time, the Partnership has
no information that any sites were in fact damaged and the Partnership's
investigation in this matter is ongoing. The Partnership has informed the FERC
and the New York State Office of Parks, Recreation and Historic Preservation of
this matter. At this time, the Partnership is unable to determine if there will
be any material adverse effect on the company's financial condition and results
of operations due to this matter.

          Eastchester-Horizon Suit

          On January 20, 2004, Horizon filed a complaint against the Partnership
and IPOC in the Supreme Court of the State of New York, New York County (Index
No. 04/600140). The complaint alleges that the Partnership wrongfully terminated
its agreement with Horizon to perform the Eastchester construction work in Long
Island Sound and that the Partnership committed other breaches of such agreement
in conjunction with the Eastchester construction work. The complaint seeks
damages in excess of $40.0 million. The Partnership is in the



                                      F-23
<PAGE>

process of preparing a rigorous defense to Horizon's claims; it has served an
answer and will file substantial claims in state and/or federal court against
Horizon for Horizon's actions during the Eastchester construction work. Given
the preliminary stage of this matter, the Partnership is unable at this time to
assess the likelihood of a favorable or unfavorable outcome and/or the amount or
range of recovery or loss, if any, resulting from Horizon's claims and the
Partnership's counterclaims.

Cal Dive International, Inc.
----------------------------

          On March 1, 2004 and in a duplicate filing on March 9, 2004, Cal Dive
International, Inc. ("Cal Dive") filed a Mechanic's Lien totaling $3,261,510.05
in the offices of the Clerk of Bronx and Suffolk Counties, respectively. Cal
Dive was in privity with Horizon Offshore Contractors, Inc. ("Horizon") and
provided services to Horizon during the Eastchester construction work. The
Partnership instructed Horizon to address the lien notice pursuant to its
contractual obligations. The Partnership also demanded further information from
Cal Dive on the particulars of its lien. The Partnership does not believe it
owes Cal Dive any monies and plans to vigorously contest the validity of the
liens. Furthermore, the Partnership, in compliance with Section 6.2(c)(ii) of
its Second Supplemental Indenture, dated August 13, 2003, intends to post a bond
to discharge the Mechanic's Lien.

Capobianco, A. vs. Iroquois Gas & Consolidated Edison Company of New York
-------------------------------------------------------------------------

          On January 28, 2004, Anthony Capobianco filed a complaint against the
Partnership, Iroquois Pipeline Operating Company ("Iroquois") and Consolidated
Edison Company of New York in the Supreme Court of the State of New York, New
York County (Index No. 101366/04). The complaint alleges that Mr. Capobianco, an
employee of Hallen Construction Company, Inc. ("Hallen"), sustained personal
injuries resulting from an electrical current causing severe electrical shock
while performing his duties as part of the construction of the Hunts Point
segment of the Partnership's Eastchester project. Hallen was Iroquois'
contractor employed to construct that segment of the project. The claim is
asserted for damages in the amount of $10.0 million. Iroquois has notified its
insurance carriers and an answer has been filed to the complaint. Given the
preliminary nature of this matter, at this time, the Partnership is unable to
determine the likelihood of an unfavorable outcome and/or the amount of range of
loss, if any, in the event of an unfavorable outcome.

National Energy & Gas Transmission Inc. (NEGT) and its Subsidiaries' Bankruptcy
-------------------------------------------------------------------------------
Filing
------

          On July 8, 2003, PG&E Corporation reported that NEGT and a number of
its subsidiaries filed voluntary petitions for reorganization under Chapter 11
of the U.S. Bankruptcy Code. These subsidiaries include, PG&E Energy Trading
Holdings Corporation, PG&E Energy Trading-Gas Corporation, PG&E Energy
Trading-Power Corporation, PG&E ET Investments Corporation, and US Gen New
England, Inc. (US Gen NE).

          US Gen NE had two firm transportation service agreements with the
Partnership, one for 40,702 Dth/d, which expires on November 1, 2013, and one
for 12,000 Dth/d, which expires on April 1, 2018. The total monthly demand
charges for both contracts were $0.5 million. On September 5, 2003, the
bankruptcy court authorized the rejection of US Gen NE's two firm



                                      F-24
<PAGE>

transportation contracts. The Partnership has remarketed a portion of the
capacity on a short-term basis and plans to continue to remarket and resell this
capacity in the future.

          On October 15, 2003, the Partnership filed a proof of claim with the
bankruptcy court for $49.8 million, representing the present value of the two
rejected contracts.

          The Partnership is also involved in various other legal proceedings.
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.


          Leases

          The Partnership leases its office space under operating lease
arrangements. The leases expire at various dates through 2011 and are renewable
at the Partnership's option. The Partnership 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, the
Partnership leases various equipment under non-cancelable operating leases.
During the years ended December 31, 2003, 2002 and 2001, the Partnership made
payments of $1.2, $0.9 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):

              Year                           Amount
              ----                           ------
              2004                             .9
              2005                             .8
              2006                             .8
              2007                             .7
              2008                             .7
              Thereafter                      6.1


          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.




                                      F-25
<PAGE>





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

                         U.S.
     2003              Federal          State                   Total
     -------------------------------------------------------------------------
     Current          $  4,812          $2,334                $  7,146
     Deferred           12,950           1,339                  14,289
                      --------        --------                ---------
     Total            $ 17,762          $3,673                $ 21,435
                      ========        ========                =========

                        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
                      ========          ======                ========

          For the years ended December 31, 2003, 2002 and 2001, the effective
tax rate differs from the Federal statutory rate due principally to the impact
of state taxes.

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

                                      2003        2002        2001
------------------------------------------------------------------------------
Depreciation                       $  9,142     $11,121     $ 8,157
Gain/loss on disposal of asset          (67)        934          --
Deferred regulatory asset               (75)        (75)        (76)
Property taxes                          128         (80)         (3)
Accrued expenses                         47         (51)       (240)

Alternative minimum tax credit        1,025        (585)      1,141
Other                                 4,089        (314)        114
                                   --------     --------    --------
Total deferred taxes               $ 14,289     $10,950     $ 9,093
                                   ========     ========    =======

          Not included in the above two tables for 2003 are the deferred taxes
associated with the cumulative change in accounting principle related to
municipal property taxes. Those taxes amounted to $2.5 million.

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

                                      F-26
<PAGE>



       At December 31,                                    2003            2002
       ------------------------------------------------------------------------
       DEFERRED TAX ASSETS:
       Alternative minimum tax credit                    $  914         $1,939
       Accrued expenses                                   1,056          1,103
                                                          -----          -----
       Total deferred tax assets                          1,970          3,042

       DEFERRED TAX LIABILITIES:
       Depreciation and related items                   (96,670)       (87,619)
       Deferred regulatory asset                           (580)          (656)
       Property taxes                                    (3,404)          (794)
       Other                                             (4,947)          (859)
                                                     ------------   -----------
       Total deferred tax liabilities                  (105,602)       (89,928)
                                                     ------------   -----------
       Net deferred tax liabilities                    (103,632)       (86,886)
                                                     ------------   -----------
       Less deferral of tax rate change                     586            611
                                                     ------------   -----------
       Deferred taxes-operations                       (103,046)       (86,275)
       Deferred tax related to equity AFUDC             (18,587)       (13,469)
       Deferred tax related to change in tax rate          (586)          (611)
                                                     ------------   -----------
       Total deferred taxes                           $(122,220)     $(100,355)
                                                     ============   ===========
       Deferred tax related to other
       comprehensive income                           $  (1,671)     $  (2,227)
                                                     ============   ===========

          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 the Partnership's related party
transactions (millions of dollars):

                                      Payments     Due (to)/from   Revenue
                                      to Related   Related         from Related
  2003                                Parties      Parties         Parties
  ------------------------------------------------------------------------------
  TransCanada Iroquois Ltd.              $ 0.1       $  --           $   --
  Dominion Iroquois, Inc.                   --          0.1             1.2
  NorthEast Transmission Company           1.0          2.1            24.4
  JMC-Iroquois, Inc.                        --          0.8            16.0
  TEN Transmission Company                  --          1.7            12.0
  NJNR Pipeline Company                     --          0.8             6.7
                    Totals               $ 1.1       $  5.5           $60.3
                                       ==========  ==========      ============



                                      Payments      Due from        Revenues
                                      to Related    Related         from Related
  2002                                Parties       Parties         Parties
  -----------------------------------------------------------------------------


                                      F-27
<PAGE>

  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
                                    =========== ===========       ===========

          NOTE 10

          RETIREMENT BENEFIT PLANS:

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

          During 1997 and 1998 the Company also adopted excess benefit plans
("EBPs") that provide retirement benefits to executive officers and other key
management staff. The EBPs recognize total compensation and service that would
otherwise be disregarded due to Internal Revenue Code limitations on
compensation in determining benefits under the regular retirement plan. The EBPs
are not considered to be funded for ERISA purposes and benefits are paid when
due from general corporate assets. 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.

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


                                        2003      2002       2001
 ---------------------------------------------------------------------
 Service cost                           $811      $687      $597
 Interest cost                           246       194       137
 Expected return on plan assets         (245)     (211)     (144)
 Amortization of prior service cost       12        22        22
 Recognition of net actuarial loss        57        22         6
                                      --------  --------  ------------
 Net periodic pension cost
 before FAS 88                          $881      $714      $618
                                      ========  ========  ============
 Recognized FAS 88
 settlement/curtailment amount         $ (87)    $ --      $ --
                                      ========  ========  =============



                                      F-28
<PAGE>

          The following tables represent the two Plans' combined funded status
reconciled to amounts included in the consolidated balance sheets as of December
31, 2003 and 2002 (thousands of dollars):
<TABLE>
<CAPTION>

   Change in Benefit Obligation                             2003              2002
                                                       ---------------- -----------------
  <S>                                                      <C>              <C>
   Benefit obligation at beginning of year                 $3,861           $2,570
   Service cost                                               811              687
   Interest cost                                              246              194
   Actuarial gain                                             346              410
   Curtailments and settlements                              (108)              --
   Benefits paid                                              (46)              --
                                                       ---------------- -----------------
   Benefit obligation at end of year                       $5,110           $3,861
                                                       ================ =================

   Change in Plan Assets                                    2003              2002
                                                       ---------------- -----------------
   Fair value of plan assets at beginning of year          $2,483           $2,237
   Actual return on plan assets                               632             (202)
   Employer contribution                                    1,032              448
   Benefits paid                                              (46)              --
                                                       ---------------- -----------------
   Fair value of plan assets at end of year                $4,101           $2,483
                                                       ================ =================

   Reconciliation of Funded Status                          2003              2002
                                                       ---------------- -----------------
   Funded status                                          $(1,009)         $(1,378)
   Unrecognized net actuarial loss                            966            1,009
   Unrecognized prior service cost                             37              125
   Accrued benefit cost                                     $  (6)           $(244)
                                                       ================ =================
</TABLE>

          Amounts recognized in the consolidated balance sheets at December 31st
consist of (thousands of dollars):

                                                 2003              2002
                                            ===================================
   Prepaid benefit cost                         $  --           $    --
   Accrued benefit cost                        (1,005)            (1,327)
   Intangible assets                               --                --
   Accumulated other comprehensive income         999              1,083
                                            ---------------  ------------------
   Net amount recognized                        $  (6)         $    (244)
                                            ===============  ==================

          The accumulated benefit obligation for the Company's retirement
benefit plans was $5.1 million and $3.7 million at December 31, 2003 and 2002,
respectively.

          Information for pension plans with an accumulated benefit obligation
in excess of plan assets (thousands of dollars):


                                             2003              2002
                                           --------         ------------
     Projected benefit obligation           $5,110             $3,861
     Accumulated benefit obligation         $5,099             $3,706


                                      F-29
<PAGE>

     Fair value of plan assets              $4,101             $2,483


          Additional Information (thousands of dollars):

                                             2003              2002
                                           --------        -------------
         Increase in minimum liability
         included in other comprehensive
         income                               $56               $944


          The following table summarizes the weighted average assumptions used
to determine benefit obligations as of December 31st (rates shown are rates at
end of measurement period):

                                             2003         2002
                                           --------     ---------
         Discount rate                       6.00%          6.50%
         Rate of compensation increase       4.00%          4.00%


          The following table summarizes the weighted average assumptions used
to determine the net periodic benefit cost for years ended December 31st (rates
shown are rates at beginning of measurement period):

                                              2003           2002         2001
                                            ---------      --------    ---------
 Discount rate                                6.50%          7.00%        7.00%
 Expected long-term return on plan assets     8.00%          9.00%        9.00%
 Rate of compensation increase                4.00%          4.50%        5.00%


          The expected long-term rate of return assumption was developed using a
variety of factors including long-term historical return information, the
current level of expected returns and general industry expectations. Adjustments
are made to the expected long-term rate of return assumption when deemed
necessary based upon revised expectations of future investment performance of
the overall capital markets.

          Plan Assets

          The following table sets forth the Company's pension plans weighted
average asset allocations at December 31, 2003 and December 31, 2002.


                    Asset Category                2003         2002
                    --------------------------------------------------
                    U.S. Equities                  45%            44%
                    International Equities         11%            10%
                    Real Estate                     5%             5%
                    U.S. Fixed Income              37%            39%



                                      F-30
<PAGE>

                    Other                           2%             2%


          The Company's investment goal is to obtain a competitive risk adjusted
return on the pension plan assets commensurate with prudent investment practices
and the plan's responsibility to provide retirement benefits for its
participants, retirees and their beneficiaries. The Plan's asset allocation
targets are strategic and long term in nature and are designed to take advantage
of the risk reducing impacts of asset class diversification. The Plan's target
asset allocations are as follows:


                    Asset Category                 2003           2002
                   ---------------------------------------------------
                    U.S. Equities                   45%            45%
                    International Equities          10%            10%
                    Real Estate                      5%             5%
                    U.S. Fixed Income               38%            38%
                    Other                            2%             2%

          Plan assets are periodically rebalanced to their asset class targets
to reduce risk and to retain the portfolio's strategic risk/return profile.
Investments within each asset category are further diversified with regard to
investment style and concentration of holdings.

Contributions:

The Company expects to contribute $1.3 million to its pension plan in 2004.





                                      F-31

<PAGE>

                                    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.



                                       48
<PAGE>

  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.

  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.

  10.11        Separation Agreement between Herbert Rakebrand III and Iroquois
               Pipeline Operating Company.

  10.12        Separation Agreement between David Warman and Iroquois Pipeline
               Operating Company.

  14.1         Code of Ethics.

  12.1*        Statements regarding computation of ratios.

  21.1*        List of Subsidiaries of the Partnership.

  31.1         Rule 15d-14(a) Certification of Principal Executive Officer.

  31.2         Rule 15d-14(a) Certification of Chief Financial Officer.

  32.1         Section 1350 Certifications.


                                       49
<PAGE>
_____________________________

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

**        Previously filed as an exhibit to the Partnership's Annual Report
          on Form 10-K for the year ended December 31, 2002.