UNITED STATES

                       SECURITIES AND EXCHANGE COMMISSION

                              Washington, DC 20549

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

                                   FORM 10-K/A



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


                   For the fiscal year ended December 31, 2004

                                       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>



                                EXPLANATORY NOTE

     Iroquois or "the Partnership" is filing this amendment to its Annual Report
on Form 10-K to restate the Partnership's consolidated financial statements for
the years ended December 31, 2002, 2003 and 2004. Iroquois previously did not
exclude from capital expenditures reported in the consolidated statement of cash
flows, capital expenditures that were unpaid and included in accounts payable at
the end of the reporting period. Thus capital expenditures were reported in the
consolidated statement of cash flows on an accrual basis rather than on a cash
basis which is inconsistent with the requirements of SFAS No. 95, "Statement of
Cash Flows". This error resulted in an over/understatement of cash flows from
investing activities with an equal over/understatement of cash flows from
operating activities. This restatement did not impact the Partnership's
previously reported balance sheets or statements of income. Iroquois is also
filing amendments to its Quarterly Reports on Form 10-Q for the quarters ended
March 31, June 30, and September 30 of 2004 to correct this error.

     Based on the Public Company Accounting Oversight Board's definition of
"material weakness," restatement of financial statements included in prior
filings with the SEC is a strong indicator of the existence of a "material
weakness" in the design or operation of internal control over financial
reporting. The restatement of the Partnership's consolidated financial
statements as a result of the error described above has led management to
conclude that a material weakness existed in the Partnership's internal control
over financial reporting as of December 31, 2004. In accordance with the rules
of the SEC, the affected items of the Form 10-K, Items 6, 7, 8 and 9A of Part
II, are being amended.

     No attempt has been made in this Form 10-K/A to update other disclosures
presented in the original report on Form 10-K, except as required to reflect the
effects of the restatement. This Form 10-K/A does not reflect events occurring
after the filing of the 2004 Form 10-K or modify or update those disclosures,
including the exhibits to the Form 10-K affected by subsequent events; however,
this Form 10-K/A includes as exhibits 31.1, 31.2 and 32 new certifications by
the Partnership's principal executive officer and principal financial officer as
required by Rule 12b-15 promulgated under the Securities Exchange Act of 1934,
as amended. Accordingly, this Form 10-K/A should be read in conjunction with the
Partnership's filings made with the SEC subsequent to the filing of the original
Form 10-K for the year ended December 31, 2004, including any amendments to
those filings.


<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.


          Form 10-K Annual Report, for the year ended December 31, 2004

                                Table of Contents
                                                                            Page

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

                                     PART I.

ITEM 1.   BUSINESS.............................................................2
ITEM 2.   PROPERTIES..........................................................18
ITEM 3.   LEGAL PROCEEDINGS...................................................19
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................24


                                    PART II.


ITEM 5.   MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
            MATTERS...........................................................25
ITEM 6.   SELECTED FINANCIAL DATA.............................................25
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS.............................................27
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..........38
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................38
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
            FINANCIAL DISCLOSURE..............................................38
ITEM 9A.  CONTROLS AND PROCEDURES.............................................38
ITEM 9B.  OTHER INFORMATION...................................................39


                                    PART III.


ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP.................39
ITEM 11.  EXECUTIVE COMPENSATION..............................................42
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT......45
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................46
ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES..............................46


                                    PART IV.


ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES..........................47




<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.

     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

                                       1

<PAGE>


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, except as required by law, 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, or
TransCanada, 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, 2004, the Partnership had 36
shippers with long-term firm reserved transportation service contracts for 1,279
thousands of dekatherms per day, or MDth/d. As of December 31, 2004,
approximately 85% of the Partnership's subscribed pipeline capacity was
contracted under firm reserved transportation service contracts that continue
through at least November 1, 2014.


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

                                       2

<PAGE>

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

  TransCanada PipeLines              TransCanada Iroquois Ltd.            29.0%

     Limited                         TCPL Northeast Ltd.                 11.96%


  KeySpan Corporation                NorthEast Transmission Company       19.4%

                                     KeySpan IGTS Corp.                   1.0%


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


  Cogentrix Energy, Inc.             JMC-Iroquois, Inc.                   4.93%
                                     Iroquois Pipeline Investment, LLC    0.84%


  Energy East Corporation            TEN Transmission Company             4.87%


  New Jersey Resources Corporation   NJNR Pipeline Company                3.28%


     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 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

                                       3

<PAGE>



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 compressor stations and cooling facilities at
the Wright and Athens, New York compressor stations. As of December 31, 2004,
the Partnership had firm reserved transportation contracts in place to deliver
1,279 MDth/d of natural gas.

     Metering Stations and Interconnects. The Partnership receives natural gas
from the TransCanada Canadian Mainline at the Canada-United States border near
Waddington, New York and delivers gas in New York and Connecticut through meters
tied to local distribution companies and 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 Bcf/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 Canadian Mainline. 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 meter stations and mainline valves 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.


                                       4

<PAGE>



Transportation Services and Shippers

     The design capacity of the Partnership's mainline pipeline system is
subscribed under firm reserved transportation service contracts with 36
shippers. Under the firm reserved transportation service contracts, the pipeline
receives natural gas on behalf of shippers at designated receipt points and
transports the gas on a firm basis up to each shipper's maximum daily quantity.
As of December 31, 2004, approximately 85% of the subscribed capacity of the
Partnership's pipeline system was contractually committed through at least
November 1, 2014. 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 rate 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, through
their affiliates, accounted for more than 23% of the Partnership's revenues for
the year ended December 31, 2004. Approximately 49% of the Partnership's
existing pipeline system firm reserved capacity was contracted to affiliates of
the Partnership's partners as of December 31, 2004.

     On February 5, 2004, the Partnership placed into service the Eastchester
Expansion Project. As of December 31, 2004, five shippers had contracted for
service on the Eastchester Expansion totaling 230 MDth/d. Approximately 74% of
this capacity is contracted through at least February 1, 2013. The Partnership
has entered into negotiated rate contracts with each of the five shippers, which
provide for cost recovery primarily through a monthly demand charge, thereby
resulting in minimal cost risk associated with volume throughput.

     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. In the past three years, 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, 2004, the weighted average credit rating of the
Partnership's shippers which are rated or have parental guarantees or letters of
credit in place, representing 87.9% of the pipeline system's contracted
capacity, was A3 (based on Moody's Investor Services) and A-

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<PAGE>




(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
15% 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 2011. The bulk of the growth in the northeastern United States is
expected to occur in the electric generation sector.

     Natural gas demand in the Northeast is highly seasonal. The peak months for
natural gas demand occur in the winter season for residential, commercial, and
industrial sectors. For the electrical generation sector, the peak months occur
in the summer season. The summer peaking needs of electric generators help
balance seasonality and level out our pipeline's throughput.

     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.

     The Partnership's short-term financial condition is dependent on the
availability of sufficient and competitively priced supply at Waddington, New
York, the interconnect between the facilities of TransCanada and the
Partnership. With the placement into service by the Partnership of its
Eastchester Extension Project, Waddington has experienced an additional demand
for natural gas in the amount of 230 MDth/d, for which there has been no
corresponding upstream expansion on the TransCanada Canadian Mainline. As a
result, the Partnership's level of revenues that are associated with
discretionary services, such as interruptible and short term firm
transportation, are subject to erosion due to the supply/demand mismatch at
Waddington. It is anticipated that over the next several years, TransCanada will
be expanding its facilities to enable the delivery of incremental volumes of
natural gas to Waddington, thus reducing the risk associated with this
particular component of the Partnership annual revenue stream.

                                       6

<PAGE>




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

        o economic conditions;

        o fuel conservation measures;

        o competition from alternative energy sources;

        o climatic conditions;

        o legislation or governmental regulations; and

        o technological advances in fuel economy and energy generation devices.

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

     In 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. 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 final construction costs were approximately $334 million, rather than the
$210 million estimated during the FERC certification process. This will reduce
the Partnership's margins that were anticipated when the project application was
filed with the FERC.

     The Eastchester contracted throughput for 2004 was approximately 210 MDth/d
in the summer and 230 MDth/d in the winter. Capacity utilization is seasonal and
is expected to 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 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., or 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


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<PAGE>


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.

     The Partnership continued to market this project to potential customers and
continued to evaluate its feasibility, however, because the Partnership was
unable to secure customers prior to the December 3, 2004 construction extension
deadline, the project was cancelled and the $2.3 million in capital expenditures
was written off and charged to expense. (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.

     Based on communications with its prospective customers regarding the timing
of their needs for new firm transportation service, the Partnership had
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. (See Note 7 to the Consolidated Financial Statements.)

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. Although the Partnership has been
successful in increasing its penetration of the greater New York City
marketplace via its Eastchester Project, this marketplace remains extremely
competitive as the traditional gulf coast pipelines continue to expand their
respective facilities to deliver incremental volumes of natural gas to serve
market growth, particularly that resulting from the increase in natural gas
fired electric generation. Another large segment of the Partnership's
marketplace that is susceptible to competition is the dual-fuel electric
generation market which typically avails itself of shorter term discretionary
transportation products. These facilities also have the ability to generate
electricity from No. 6 low sulpher residual oil which continues to be more
economic than the generation of electricity from natural gas. The Partnership
also faces competition with respect to the availability of natural gas supply at
Waddington, NY, its interconnect with the facilities of the TransCanada system
and also the only source for physical receipt of gas into the Iroquois system.
As the eastern Canadian provinces of Ontario and Quebec continue to develop
natural gas fired electric generation facilities, the markets served by the
Partnership will continue to compete directly with these Canadian markets for
natural gas supplies, primarily originating from the Western Canadian
Sedimentary Basin, and delivered by Transcanada to the eastern portion of the
North American continent. Furthermore, in recent years, the FERC has issued
orders designed to increase competition in the


                                        8

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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, or the Natural Gas
Act. Under the Natural Gas Act and the Natural Gas Policy Act of 1978, the FERC
has jurisdiction over the Partnership with respect to virtually all aspects of
its business, including transportation of gas, rates and charges, construction
of new facilities, extension or abandonment of service and facilities, accounts
and records, depreciation and amortization policies, the acquisition and
disposition of facilities, the initiation and discontinuation of services, and
certain other matters. The Partnership, where required, holds certificates of
public convenience and necessity issued by the FERC covering its facilities,
activities and services.

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

     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


                                        9

<PAGE>


motion or based on a complaint filed by a customer of a pipeline or other
interested person, the FERC may initiate a proceeding seeking to compel a
pipeline to change any rate or term or condition of service which is on file. If
the FERC determines that an existing rate or condition is unjust, unreasonable,
unduly discriminatory or preferential then any rate reduction or change in
service term or condition which is ordered at the conclusion of such a
proceeding is generally effective prospectively from the date of the order
requiring such change.

     The nature and degree of regulation of natural gas companies have changed
significantly during the past 10 years, and there is no assurance that further
substantial changes will not occur or that existing policies and rules will not
be applied in a new or different manner, particularly in light of the FERC's
decision to seek comments on its negotiated rate policies from companies in the
natural gas industry.

     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. 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


                                       10

<PAGE>




        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% (e.g., the 100% load
factor interzone rate will be reduced from the then 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 2003 long-term firm service contracts,
the settlement resulted in reductions in revenues of $3.8 million in 2004, and
will result in reductions in revenues of $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 became 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 proposed 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 served as the initial rate per the certificate
order). The increased rate reflected, among other things, an increase in plant
costs from the certificate estimate of $210 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 customers 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.

     On June 15 and July 8, 2004, settlement conferences were convened at the
FERC's offices to attempt to negotiate a settlement of the issues in the rate
case. As a result of those conferences, the parties reached a settlement in
principle of all issues that was supported or not opposed by all participants to
the proceeding. On July 15, 2004 the Partnership submitted a motion to the
Presiding Administrative Law Judge to suspend the procedural schedule to allow
the parties to formalize the settlement agreement; such motion was granted by
the judge on July 16. Following additional discussions and negotiations with the
parties, the Partnership submitted a comprehensive settlement agreement on
August 12, 2004. The settlement agreement provides for recourse rates of $0.66
per Dth for the period July 1, 2004 through December 31, 2007 and $0.635 per Dth
for the period January 1, 2008 through December 31, 2011. In addition, the
Partnership will not include in future rates any future legal fees (incurred
after June 30, 2004)

                                       11

<PAGE>



incurred in litigation regarding construction incidents associated with the
original Eastchester Project. A moratorium on rate changes, as spelled out more
fully in the settlement agreement, will also be in effect through December 31,
2011. The settlement agreement was approved by the FERC on October 13, 2004 and
became final on November 13, 2004.

     In addition to settling the Eastchester recourse rates as set forth above,
the Partnership has also entered into negotiated rate agreements with all of the
initial shippers on the Eastchester Extension Project. The negotiated rates on a
100% load-factor equivalent basis range between $0.47 and $0.63 per Dth
depending on whether the agreement was signed pre or post construction and the
length of the negotiated contract.

     The recourse rates and negotiated individual Eastchester shipper rates,
coupled with cost overruns experienced on the Eastchester Project, will reduce
the Partnership's margins that were anticipated when the project application was
filed with FERC.

     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.
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. As required by said schedule, on June 1, 2004 the
Partnership posted its revised standards of conduct on its internet website,
identifying the procedures established for implementing the FERC's requirements.
Additionally, as required by the order, on September 22, 2004, the Partnership
developed and posted on its website, a written procedure implementing its
standards of conduct and trained all its employees subject to the standard.
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
1968, 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 Improvement Act of 2002 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

                                       12

<PAGE>




amendments also narrowed the scope of gas pipeline exemptions pertaining to
underground storage tanks under the Resource Conservation and Recovery Act. The
Partnership believes its operations comply in all material respects with the
NGPSA; however, the industry, including the Partnership, could be required to
incur additional capital expenditures and increased costs depending upon
regulations issued by the Department of Transportation under the NGPSA and/or
future pipeline safety legislation.

Environmental Matters

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

     Current Operations. At each of the Partnership's 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.

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, 2004, IPOC had 115 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, 2004, approximately 85% of the subscribed capacity of
the Partnership's pipeline system was contracted through at least November 1,
2014. 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:


                                       13

<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 the last three years, 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.


                                       14

<PAGE>



     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. On March 2, 2005, representatives of the Partnership and US
Gen NE agreed in principal to a Settlement Agreement to resolve the claim. The
settlement is in the process of being approved by both parties. (See Note 7 to
the Consolidated Financial Statements.)

     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.

     In addition, on July 21, 2004 the United States Court of Appeals for the
District of Columbia Circuit issued an opinion in BP West Coast Products, LLC v.
FERC, 374 F. 3d 1263 (D.C. Cir. 2004) that addressed the FERC's policies
relating to recovery of income taxes by an

                                       15

<PAGE>



oil pipeline limited partnership. Under the FERC's pre-existing policy,
partnerships were allowed to include income taxes in jurisdictional rates. In BP
West Coast, however, the DC Circuit held that the FERC had not adequately
justified its policy of providing such an oil pipeline limited partnership with
an income tax allowance, and remanded the issue to the FERC for further action.
On December 2, 2004 the FERC issued a "Request for Comments" in Docket No.
PL05-5, seeking comments on the scope of the DC Circuit's order and whether it
applied outside the specific facts of that case. On January 25, 2005 the
Partnership and others submitted comments to the FERC demonstrating that the
Court's opinion should not apply to limited partnerships such as Iroquois, and
that the FERC's pre-existing policy should continue to apply. The FERC has not
yet acted on the comments filed in that docket, and it is not known when such
action will occur. Given the status of the proceeding, the Partnership cannot
give any assurances as to its continued ability to recover income taxes as a
component of its rates in the future.

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
pipeline systems were to become constrained or if the price of Western Canada
natural gas were to increase significantly, existing shippers may not extend
their contracts and the Partnership may be unable to find replacement sources of
natural gas for the pipeline system's capacity. The Partnership cannot give any
assurances as to the availability of additional sources of gas that can
interconnect with its pipeline system.

     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 pipeline systems;

        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.

                                       16

<PAGE>




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. For additional information
regarding litigation arising from the Eastchester Extension construction, 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.

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 entity, 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;

                                       17

<PAGE>




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

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

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

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 capital expenditures, earnings or
competitive position 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 29,100 square feet of leased office space under a
lease agreement that expires on April 30, 2011. The Partnership also leases
approximately 10,500 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

                                       18

<PAGE>


pipeline system. The Partnership also leases a right-of-way easement on Long
Island, New York, which expires in 2030. The Partnership believes that it has
satisfactory interests in all of the properties making up its pipeline system.

ITEM 3.  LEGAL PROCEEDINGS

Eastchester Construction Incidents

     On November 16, 2002, certain undersea electric transmission cables owned
by Long Island Lighting Partnership d/b/a The Long Island Power Authority, or
LIPA, and Connecticut Light and Power Partnership, 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., or Cal Dive, a subcontractor of the Partnership's general
contractor, Horizon Offshore Contractors, Inc., or Horizon.

     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, collectively
refered to as the "Cable Interests," filed third-party claims against the
Partnership and its operating subsidiary, IPOC, as well as Horizon and Thales,
seeking recovery for their 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 originally claimed a total of $34.3 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 September 2004, the Cable Interests amended their
claim to $23.5 million, consisting of approximately $12.9 million for repairs
and repair related costs and $10.6 million in consequential damages.

     A mediation was conducted in February 2005, at the conclusion of which all
parties agreed to terms for a global settlement of the litigation. Neither the
Partnership nor IPOC will be contributing to the settlement, but will be given
full releases from all parties. A formal settlement agreement is being
negotiated, with the goal of all funds paid by April 15, 2005.

     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. On
March 28, 2005, the Partnership and the Town of Huntington executed a settlement
agreement resolving this matter and another relating to restoration of Town
property. The Partnership does not admit any liability but will pay $45,100 to
resolve these matters.


                                       19

<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. As required by 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. 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 they are funding the costs for the Partnership's defense. The
Partnership also commenced a declaratory judgment action against Horizon's
primary liability insurer seeking coverage and is currently investigating the
applicability of all other 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. Horizon's suit contends that if it is not
entitled to exoneration, its liability should be limited to $19.3 million,
representing the value of the GULF HORIZON and her pending freight, and
Horizon's insurers have provided an undertaking (subject to policy defenses) to
pay any judgment that may be rendered in the suit up to $19.3 million. NYPA,
LIPA and the insurers of the Y-49 cable, collectively referred to as the "Y-49
Cable Interests," also have filed claims in the limitation action asserting
total damages of approximately $18.2 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

                                       20

<PAGE>




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. (For resolution of these unrelated claims, see Eastchester
Contractor Settlement discussion below.) 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 filed motions to transfer the Texas action to the
United States District Court for the Eastern District of New York. Thales 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 and that Horizon had no right to limit its liability as to the
Partnership's contract claims. The Y-49 Cable Interests filed cross claims
against the Partnership alleging claims under the Crossing Agreement between the
Partnership and NYPA and in common law tort.

     The Y-49 Cable Interests filed a motion for partial summary judgment
against the Partnership on October 13, 2004. The motion asks the court to find
the Partnership liable for indemnity under the Crossing Agreement for all costs
and expenses incurred by the Y-49 Cable Interests directly related to the
emergency response to the incident and for the costs and expenses of the
temporary and permanent repairs. The Partnership believes the motion is
premature and has opposed the motion. The motion is now fully briefed and
pending before the court for decision.

     The parties presently are engaging in document discovery, and 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. 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.

     Pursuant to its agreements with the owners of the electric transmission
cables that the Eastchester facilities cross in the Long Island Sound, the
Partnership performed certain post-construction surveys to verify the condition
of the cable crossings and confirm the location of the pipeline. Specifically,
the Partnership had constructed a "structure" over the Y-50 cable system
consisting of lightweight flexible concrete mattresses under the pipeline,
specially fabricated concrete blocks adjacent to the pipeline and crushed rock.
The surveys and additional follow-up

                                       21

<PAGE>




studies indicate that the "structure" may have settled to a greater extent than
originally anticipated and that its location is believed to be 65 feet north of
the location where the pipeline crosses the Y-50 cable. The Partnership has been
discussing this matter with the owner of the Y-50 cable system as to whether and
how these issues should be modified and notified the FERC by letter dated
September 3, 2004. 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 costs, if any, in the event of an unfavorable outcome.

     No liabilities have been recorded by the Partnership in conjunction with
any of the preceding legal matters.

Eastchester Contractor Litigation Settlement

     On March 11, 2005, the Partnership, IPOC, Horizon and its Subcontractors
reached an agreement resolving the claims and counter claims made in the
Horizon, Weeks, Cal Dive and Tom Allen proceedings described below, collectively
referred to as Eastchester Contract Suits. In addition, the Partnership has
reached an agreement in principle with certain of its insurance carriers
regarding the recovery of a portion of the costs related to a failed directional
pipeline drill that occurred during the construction of the Eastchester lateral.
The Partnership's projected $334 million total Eastchester capital costs
included the costs for the settlement of the Eastchester Contract Suits and the
expected insurance recovery associated with the directional drill.

     On January 20, 2004, Horizon Offshore Contractors, Inc. 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 million. On
April 7, 2004, the Partnership filed in such court proceeding an amended answer
and counterclaims against Horizon totaling in excess of $66 million.

     On March 1, 2004 and in a duplicate filing on March 9, 2004, 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 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, on April 1 and April 5, 2004 in compliance
with Section 6.2(c)(ii) of its Second Supplemental Indenture, dated August 13,
2003, posted bonds to discharge the Mechanic's Liens.

     On September 10, 2004, Cal Dive filed a complaint against the Partnership
in the United States District Court for the Eastern District of New York. The
complaint alleges that Cal Dive has not been paid $3.3 million for work that it
performed on the Eastchester project. The Partnership filed an answer to the Cal
Dive action on October 15, 2004 and commenced a third party action against
Horizon on October 25, 2004.

                                       22

<PAGE>




     On June 14, 2004, Tom Allen Construction Company, or Tom Allen, one of
Horizon's subcontractors for the Eastchester project, filed a complaint against
Horizon and the Partnership in the Supreme Court of the State of New York, New
York County. Tom Allen was responsible for performing the directional drills at
Northport and Hunts Point. Tom Allen is claiming that it has not been paid for
work associated with a failed directional drill at Hunt's Point and is seeking
$5.6 million in damages from Horizon and the Partnership. The Partnership served
an answer to the complaint and various discovery demands on July 30, 2004.

     On July 21, 2004 Weeks Marine Inc., or Weeks, one of Horizon's
subcontractors for the Eastchester project, filed a complaint against Horizon
and the Partnership in the Supreme Court of the State of New York, New York
County. Weeks was responsible for certain marine construction operations
including dredging, rock placement, fabric placement and associated activities
along the Eastchester project. Weeks is claiming that it has not been paid for
work associated with the marine portion of the Eastchester project and is
seeking $18.5 million in damages from Horizon and the Partnership. The
Partnership filed an answer to the complaint on August 16, 2004.

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

     On January 28, 2004, Anthony Capobianco filed a complaint against the
Partnership, IPOC 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., or 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 million. The Partnership has notified its insurance carriers and
an answer has been filed to the complaint. Hallen's insurer has agreed to
indemnify and defend the Partnership in this action up to the $1 million limit
of its general liability insurance policy. Additionally, Hallen has coverage
under an excess liability policy up to $20 million. 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.

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 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 transportation
contracts. In February 2004, the Partnership entered into a ten year contract
for

                                       23

<PAGE>




the 12,000 Dth/d while the remaining unsubscribed capacity of 40,720 Dth/d will
continue to be remarketed on a short term basis until longer term market
opportunities emerge. 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.

     On March 2, 2005, representatives of the Partnership and US Gen NE agreed
in principal to a settlement agreement regarding the Partnership's proof of
claim with the bankruptcy court. Under said settlement, the Partnership expects
to receive $8.4 million, the value of its mitigated claim as well as,
approximately $2.1 million as a result of retained cash collaterals for a total
settlement of approximately $10.5 million plus 4% interest accruing from the
start of the claim. Based on US Gen NE's disclosure statement filed with the
Bankruptcy Court, US GEN NE estimates to pay 100% of each unsecured claim. The
settlement is in the process of being approved by both parties and the
Bankruptcy Court. The Partnership expects to record any funds received as part
of this bankruptcy proceeding as "Other Income."

     On September 15, 2004, NEGT announced that it had entered into an agreement
with GS Power Holdings II LLC (a subsidiary of Goldman Sachs) to purchase NEGT's
indirect equity interest in the Partnership. NEGT's indirect interest is held
through JMC-Iroquois, Inc. and Iroquois Pipeline Investment, LLC, both of which
represent a 5.77% interest in the Partnership. On January 31, 2005, Cogentrix
Energy, Inc. ("Cogentrix") announced that, through its subsidiaries Cogentrix
Power Holdings I LLC and Cogentrix Power Holdings II LLC, it had acquired the
equity interests in both JMC-Iroquois, Inc. and Iroquois Pipeline Investment,
LLC.

Enron Corp. and Affiliated Entities Bankruptcy Filing

     Enron Corp. and Enron North America Corp., collectively Enron, filed
voluntary petitions for relief under Chapter 11 of the United States Bankruptcy
Code in the United States Bankruptcy Court for the Southern District of New
York, or Bankruptcy Court, in 2001. In October 2002, the Partnership filed
Proofs of Claim with the Bankruptcy Court in the amount of $1,593,362.39 for
Claim 1 and in the amount of Unknown dollars for Claim 2 resulting from
termination by Enron of the Partnership's Gas Transportation (Contract No.
R-1250-05). On February 22, 2005, by Letter Agreement, Enron agreed to allow the
Partnership $1,816,762.70 in unsecured claims, subject to the approval of the
Bankruptcy Court. Based on Enron's disclosure statement, Enron estimates to pay
20% of each unsecured claim. The Partnership expects to record any funds
received as part of this bankruptcy proceeding as "Other Income."

     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.

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

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

                                       24

<PAGE>




                                    PART II.

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

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

ITEM 6.  SELECTED FINANCIAL DATA

     The following selected financial data should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and with the Partnership's financial statements, including the notes
thereto, appearing elsewhere in this annual report. The income statement,
balance sheet and cash flow data for the years ended December 31, 2004, 2003,
2002, 2001 and 2000 have been derived from the Partnership's financial
statements, which have been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm. See Note 2 to the Consolidated
Financial Statements for an explanation of the restatement of the Consolidated
Statements of Cash Flows for 2004, 2003 and 2002.

<TABLE>
<CAPTION>
                                                                  Year ended December 31,
                                                 --------------------------------------------------------------
<S>                                                <C>          <C>          <C>         <C>         <C>
                                                   2004         2003         2002        2001        2000
                                                   ----         ----         ----        ----        ----

                                                                 (In thousands of dollars)

    Income Statement Data:

    Operating revenues...................         $151,996       $132,009    $126,320    $128,270   $127,234

    Operating expenses:

        Operation and maintenance........           27,609         25,400      23,911      22,108     21,119

        Depreciation and amortization....           31,636         24,090      23,684      23,847     23,609

        Taxes other than income taxes....           14,619         12,333      11,206      10,953     11,156
                                                 ---------      ---------   ---------   ---------  ---------

          Total operating expenses.......           73,864         61,823      58,801      56,908     55,884

    Operating income.....................           78,132         70,186      67,519      71,362     71,350

     Other income/(expenses).............           (1,043)         8,169         507       1,829      1,824
                                                 ---------      ---------   ---------   ---------  ---------


        Net interest expense.............           32,351         24,819      25,148      28,067     31,139
                                                 ---------      ---------   ---------   ---------  ---------

    Income before income taxes and cumulative
    effect of change in accounting principle        44,738         53,536      42,878      45,124     42,035

        Provision for income taxes(1)....           18,013         21,435      16,911      18,275     17,083
                                                 ---------      ---------   ---------   ---------  ---------

    Income before cumulative effect
    of change in accounting principle               26,725         32,101      25,967      26,849     24,952
                                                 ---------      ---------   ---------   ---------  ---------

    Cumulative effect of change in accounting
    principle, net of tax                                -          3,715           -           -          -
                                                 ---------      ---------   ---------   ---------  ---------

    Net Income                                    $ 26,725       $ 35,816    $ 25,967    $ 26,849   $ 24,952
                                                 =========      =========   =========   =========  =========
</TABLE>

                                       25

<PAGE>



<TABLE>
<CAPTION>
<S>                                                <C>          <C>          <C>         <C>         <C>

    Cash Flow Data:   (2004, 2003, 2002 Restated)

    Net cash from operating activities.......      $71,452        $70,390     $59,398    $ 77,265   $ 57,181

    Capital expenditures.....................      $34,181       $148,444    $100,049     $36,340     $8,268


    Balance Sheet Data

    (at End of Period):

    Net property, plant and equipment........     $751,202       $759,343    $621,475    $533,219   $520,172

    Total assets.............................     $843,867       $848,705    $689,385    $591,745   $584,368

    Long-term debt, including

        current maturities...................     $457,778       $480,000    $407,222    $366,666   $388,889

    Partners' equity.........................     $343,821       $312,643    $232,073    $190,764   $169,423

-------------------------------------------
</TABLE>


        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 were 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.


Selected Quarterly Financial Data
(In thousands of dollars)



                          Operating           Operating            Net
2004                       Revenue              Income            Income
----                      ----------         ----------         ---------
First quarter                $39,320            $22,759           $9,836
Second quarter               $36,288            $18,211           $5,923
Third quarter                $36,072            $16,697           $5,232
Fourth quarter               $40,316            $20,465           $5,734


2003
----
First quarter                $37,615            $22,723          $10,589
Second quarter               $30,913            $15,700           $6,893
Third quarter                $29,628            $14,091           $6,436
Fourth quarter               $33,853            $17,672          $11,898 (a)

--------------------------------------------
     (a)  includes the cumulative effect of a change in accounting principle
          related to municipal property taxes, net of tax, of $3,715.


                                       26

<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 receives revenues under long-term firm reserved
transportation service contracts with shippers in accordance with service rates
approved by the FERC. On August 29, 2003, the Partnership 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 January 1, 2008.

     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% (e.g., the 100% load
factor interzone rate will be reduced from the then 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 resulted in reductions in revenues of $3.8
million in 2004 and will result in reductions in revenues of $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 became effective on July 1, 2004. The settlement did
not establish any rates, terms or conditions for the Eastchester Extension.

     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. Following additional discussions and negotiations with the parties, the
Partnership submitted a comprehensive settlement agreement on August 12, 2004.
The settlement agreement provides for recourse rates of $0.66 per dth for the
period July 1, 2004 through December 31, 2007 and $0.635 per dth for the period
January 1, 2008 through December 31, 2011. In addition, the Partnership will not
include in future rates any future legal fees


                                       27

<PAGE>



(incurred after June 30, 2004) incurred in litigation regarding construction
incidents associated with the original Eastchester Project. A moratorium on rate
changes, as spelled out more fully in the settlement agreement, will also be in
effect through December 31, 2011. The settlement agreement was approved by the
FERC on October 13, 2004 and became final on November 13, 2004. (See Note 7 of
the Consolidated Financial Statements.)

     Outlook

     Having completed and placed into service its Eastchester Extension in early
2004, the Partnership believes it is well positioned to capture incremental
market growth in New York City, since companies with an existing infrastructure
will have an advantage over companies proposing new infrastructure, in light of
the risks in obtaining permits. Although the development of additional natural
gas supply remains a challenge for the natural gas industry, the announcement of
several new liquefied natural gas 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.

     The metropolitan New York area also offers the Partnership an opportunity
to serve demand in the form of incremental gas-fired electric generation. Both
on Long Island and in New York City, the electric load serving entities,
including the Long Island Power Authority, Con Ed, and the New York Power
Authority, are entering into power purchase agreements with power plant
developers to encourage the construction of new generating assets.

Results of Operations

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


                                                           Year ended
  Revenues and Volumes Transported                        December 31,
                                                  ------------------------------
                                                    2004       2003       2002
                                                  --------   --------   --------

  Operating Revenues (dollars in millions)

           Long-term firm reserved service          $136.3    $115.6    $114.8

           Short-term firm (1)                        10.3       8.8       4.1

           Interruptible/other (1)                     5.4       7.6       7.4
                                                       ---       ---       ---

                    Total revenues                  $152.0    $132.0    $126.3

  Volumes Transported (millions of dekatherms)

           Long-term firm reserved service           291.4     289.7     300.7

           Short-term firm (1)                        41.6      23.1      11.4

           Interruptible/other (1)                    27.6      32.4      32.3
                                                      ----      ----      ----

                    Total volumes transported        360.6     345.2     344.4

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



                                       28

<PAGE>



     Operating 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. As of December 31, 2004, the Partnership was providing
firm reserved transportation service to 36 shippers of 1,278.8 MDth/d of natural
gas, as shown in the following table:

                Remaining
              Term in Years               Quantity in MDth/d
              -------------               ------------------
                 1-5                              234.2
                 6-10                             855.1
                 11-15                            189.5
                                         ---------------------
                 Total                            1,278.8

     The long-term firm service gas transportation contracts expire between
April 1, 2005 and September 1, 2018.

     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.

     2004 compared to 2003

     Total revenues increased by $20.0 million, or 15.2%, to $152.0 million for
2004 from $132.0 million for the prior year.

     Long-term firm reserved service revenues increased $20.7 million, or 17.9%,
to $136.3million for 2004 from $115.6 million for the prior year. This increase
was primarily due to additional revenues from the Eastchester Extension of
approximately $24.5 million due to the February 5, 2004 in-service date of the
Eastchester Extension. These increases were partially offset by decreased
long-term firm reserved service revenues primarily due to a rate decrease
effective July 1, 2004 of approximately $0.03/Dth as well as the loss of the
firm revenue stream


                                       29

<PAGE>


associated with US Gen NE, which filed for bankruptcy in 2003. Portions of the
US Gen New England volumes were re-contracted under short-term contracts.

     Short-term firm revenues increased $1.5 million, or 17.0%, to $10.3 million
for 2004 from $8.8 million for the prior year, primarily due to increased market
demand for natural gas in the second and third quarters of 2004, partially
offset by lower volumes associated with softer market demand for natural gas as
a result of warmer weather and more competitive oil prices during the first
quarter of 2004 as compared to the same period in 2003.

     Interruptible/other revenues decreased $2.2 million, or 28.9%, to $5.4
million for 2004 from $7.6 million for the prior year primarily due to a shift
in the demand for services to short-term firm.

     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.

     Operation and Maintenance Expense

     Operation and maintenance expense includes operating, maintenance and
administrative expenses for the Partnership's corporate office in Shelton,
Connecticut and field support for the mainline, metering and compression
facilities. The Partnership expects that there will be normal increases in
payroll, benefits and insurance expenses due to expected inflationary trends.

     2004 compared to 2003

     Operation and maintenance expense increased by $2.2 million, or 8.7%, to
$27.6 million for 2004 from $25.4 million for 2003. The increase was due to
increased field operating expenses of $1.3 million related to new compressor
stations in Boonville and Dover, NY and additional inspection runs and marine
surveys due to Eastchester being placed into service. Other factors contributing
to the increase were increases in employee benefit expenses and increased
regulatory expenses.

     2003 compared to 2002

     Operation and maintenance expense increased by $1.5 million, or 6.3% to
$25.4 million for 2003 from $23.9 million for 2002. The increases related to
insurance, regulatory expenses, outside services and rent expense.


                                       30

<PAGE>



     Depreciation and Amortization Expense

     2004 compared to 2003

     Depreciation and amortization expense increased by $7.5 million, or 31.1%,
to $31.6 million for 2004 from $24.1 million for 2003. This increase was due
primarily to the February 5, 2004 in-service date of the Eastchester Extension.

     2003 compared to 2002

     Depreciation and amortization expense increased by $0.4 million, or 1.7%,
to $24.1 million for 2003 from $23.7 million for 2002 due primarily to normal
plant additions.

     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 was 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, the
amount that would have been reported as property tax expense for that year would
not have been materially different than what was actually reported. This
one-time change in accounting principle is not expected to have a significant
effect on future property tax expense.

     2004 compared to 2003

     Taxes other than income taxes increased by $2.3 million, or 18.7%, to $14.6
million for 2004 from $12.3 million for 2003 primarily due to increased
assessments on facilities related to the Eastchester Extension.


                                       31

<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.

     Other Income and Expenses

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

     2004 compared to 2003

     Allowance for equity funds used during construction, or equity AFUDC,
decreased by $7.6 million, or 87.4%, to $1.1 million for 2004 from $8.7 million
for 2003. The decrease related primarily to the February 5, 2004 in-service date
of the Eastchester Extension.

     Other expenses, net increased by $1.9 million, to $2.6 million for 2004
from $0.7 million for 2003. In 2004 other expenses, net included a $2.3 million
write-off of the Athens Compressor Station Project. In 2003 other expenses, net
included a $0.7 million write-off related to the Partnership's investment in its
Western Leg Project.

     2003 compared to 2002

     Equity AFUDC increased $6.4 million, or 278.3%, 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.

     Other expenses, net increased approximately $1.5 million in 2003 compared
to 2002. In 2003 other expenses, net included a $0.7 million write-off related
to the Partnership investment in its Western Leg Project. In 2002 other expenses
net included a $2.2 million write-off related to the Partnership's investment in
its Eastern Long Island project which had been withdrawn from FERC
certification.

     Interest Expense

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

     2004 compared to 2003

     Interest expense was $33.4 million for each of 2004 and 2003. In 2004 the
Partnership's average debt balance decreased due to scheduled debt repayments,
however interest rates in 2004 were higher than in 2003.


                                       32

<PAGE>



     Allowance for borrowed funds used during construction decreased $7.5
million to $1.1 million for 2004 as compared to $8.6 million in 2003 due to the
February 5, 2004 in-service date of the Eastchester Extension.

     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. See Note 4 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.

     Income Taxes

     Provision for taxes decreased $3.4 million in 2004 compared to 2003 due
primarily to a decrease in taxable income.

     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

     See Note 2 to the Consolidated Financial Statements for an explanation of
the restatement of the Consolidated Statements of Cash Flows for 2004, 2003 and
2002.

     The Partnership's primary source of financing has been cash flow from
operations. 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 $1.1 million to
$71.5 million in 2004 from $70.4 million in 2003 and increased by $11.0 million
to $70.4 million in 2003 from $59.4 million in 2002. The increase in net cash
provided by operating activities from 2003 to 2004 was primarily attributable to
an increase in depreciation expense, due to the Eastchester Extension Project,
partially offset by a decrease in pretax net income and the effect of changes in
working capital due to Eastchester. The increase from 2002 to 2003 was primarily
due to the effects of an increase in debt issuance costs, in 2002, which are
included in other assets and deferred charges, associated with the financing
completed on August 14, 2002 related to Eastchester. Additionally the net income
increase from 2002 to 2003 also contributed to the increase in net cash provided
by operating activities.



                                       33

<PAGE>



     Net cash flow related to financing activities decreased by $130.0 million
to ($37.2) million in 2004 from $92.8 million in 2003 and 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.

     As of December 31, 2004, the Partnership had outstanding $200.0 million
aggregate principal amount of 8.68% senior unsecured notes due 2010 and $170.0
million aggregate principal amount of 6.10% senior unsecured notes due 2027. The
Partnership also had $77.8 million, net of scheduled debt repayments,
outstanding under its amended credit facility as of December 31, 2004. The
Partnership is a party to two interest rate swap agreements designed to hedge a
portion of the interest rate risk on its credit facility. As of December 31,
2004, the aggregate notional principal amount of these two swaps was $25.0
million, and the fair value of the swaps, net of taxes, was ($1.8) million. The
Partnership also is a party to a $10.0 million, 364-day, variable rate revolving
line of credit to support working capital requirements. As of December 31, 2004,
the outstanding principal balance on the revolving credit facility was $10.0
million.

     Capital expenditures for 2004 were $34.2 million, compared to $148.4
million in 2003, reflecting primarily the completion of construction activity
related to the Eastchester Extension during 2004. In addition, there were
expenditures associated with general plant purchases and other miscellaneous
projects during 2004. Capital expenditures in 2003 consisted of expenditures
relating to the Eastchester Extension, expenditures associated with a compressor
station site, general plant purchases and other miscellaneous projects. In 2002,
capital expenditures of $100.0 million were primarily related to the Eastchester
Extension, as well as a meter station and interconnect, a compressor station,
general plant purchases and other minor projects.

     Total capital expenditures for 2005 are estimated to be approximately $7
million, including approximately $2.5 million for installation of a vent valve
on Long Island. The remaining capital expenditures planned for 2005 are
primarily for various general plant purchases. The Partnership expects to fund
its 2005 capital expenditures through cash from operations. 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. Total cash distributions
to partners of $15.0 million were made during 2004. There were no cash
distributions to partners during 2003 or 2002. Partners made equity
contributions to the Partnership during 2003, which, in the aggregate, totaled
$20.0 million. There were no equity contributions made in 2004 or 2002.

Off-Balance Sheet Transactions

     At December 31, 2004, the Partnership had no off-balance sheet
transactions, arrangements or other relationships with unconsolidated entities
or persons that would adversely affect revenues, expenses, liquidity,
availability of capital resources, capital expenditures, financial position or
results of operations.


                                       34

<PAGE>



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, 2004 (in
thousands of dollars).

                             Payments Due by Period

<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         $457,778        $32,222        $44,444        $49,960        $331,152

Interest Payments
on Debt                 201,777         31,087         58,542         54,601          57,547

Transportation by
Others (1)               24,768          3,372          6,744          6,744           7,908

Operating Leases         10,183            912          1,597          1,567           6,107

Pension
Contributions
(2)                         836            836             __             __              __
                       --------       --------      ---------      ---------        --------

Total Contractual
Obligations            $695,342        $68,429       $111,327       $112,872        $402,714
                       ========       ========      =========      =========        ========
</TABLE>

---------------------------------------
     (1) Rates are based on known 2005 levels. Beyond 2005, demand rates are
         subject to change.
     (2) Amounts are known only for 2005. No amounts have been assumed for years
         after that.

New Accounting Standards

     Inventory Costs. In November 2004, the Financial Accounting Standards
Board, or FASB, issued Statement of Financial Accounting Standards, or SFAS, No.
151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4." SFAS No. 151
amends the guidance on inventory pricing to require that abnormal amounts of
idle facility expense, freight, handling costs and wasted material be charged to
current period expense rather than capitalized as inventory costs. SFAS No. 151
also requires that allocation of fixed production overheads to the costs of
conversion be based on the normal capacity of the production facilities. SFAS
No. 151 is effective for inventory costs incurred during fiscal years beginning
after June 15, 2005.

     Non-monetary Transactions. Also in December 2004, the FASB issued SFAS No.
153, "Exchanges of Nonmonetary Assets, an amendment of Accounting Principles
Board (APB) Opinion No. 29, Accounting for Nonmonetary Transactions." SFAS No.
153 redefines the types of nonmonetary exchanges that require fair value
measurement. SFAS No. 153 is effective for nonmonetary transactions entered into
on or after July 1, 2005.


                                       35

<PAGE>



     The Partnership expects that the implementation of these two new standards
will not have a material impact upon the Company's financial condition, results
of operations or cash flows.

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 SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." The application
of SFAS No. 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 No. 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, 2004 and 2003, the Partnership recorded regulatory assets of $20.7
million and $20.6 million, respectively. The Partnership continuously reviews
these assets to assess their ultimate recoverability within the approved
regulatory guidelines. The Partnership expects to fully recover these regulatory
assets in its rates. If future recovery of costs ceases to be probable, the
Partnership would be required to charge these assets to current earnings.
However, impairment risk associated with these assets relates to potentially
adverse legislative, judicial or regulatory actions in the future.

     Derivatives and hedging

     The Partnership utilizes derivative contracts to hedge interest rate risk
associated with the Partnership's existing variable rate debt, and to hedge the
net proceeds of new fixed rate debt. SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended, requires that the Partnership
document its hedging strategies and estimates of hedge effectiveness prior to
initiating a hedge, as well as continuing to assess hedge effectiveness for the
life of the hedging instrument. Currently, the Partnership has two interest rate
swaps outstanding with a total notional amount of $25.0 million, and a fair
value of ($1.8) million, net of taxes. The


                                       36

<PAGE>



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.

     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.


                                       37

<PAGE>



ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

     The financial instruments held or issued by the Partnership are for
purposes other than trading or speculation. The Partnership is exposed to risk
resulting from interest rate changes on its variable-rate debt. The Partnership
uses interest rate swap agreements to manage the risk of increases in certain
variable rate issues. It records amounts paid and received under those
agreements as adjustments to the interest expense of the specific debt issues.
The Partnership believes that there is no material market risk associated with
these agreements. See Note 4 to the Consolidated Financial Statements included
elsewhere in this annual report. As of December 31, 2004, the Partnership had
$87.8 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 $0.6 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-3 through F-29 of this
report.

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

     None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

     During the fourth quarter of 2004, Iroquois' management, including the
principal executive officer and principal financial officer, evaluated Iroquois'
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the Securities Exchange Act of 1934 (Exchange Act). These disclosure
controls and procedures have been designed to ensure that (a) information
required to be disclosed in Iroquois' reports under the Exchange Act, is made
known to Iroquois' management, including these officers, by other employees of
Iroquois, as appropriate, to allow timely decisions regarding required
disclosures and (b) this information is recorded, processed, summarized,
evaluated and reported within the time periods specified in the SEC's rules and
forms.

     In connection with the restatement described in Note 2 to Iroquois'
consolidated financial statements, Iroquois' management determined that there
was a material weakness in Iroquois' internal control over financial reporting
as of December 31, 2004. Based on this evaluation the principal executive
officer and principal financial officer have concluded that Iroquois' disclosure
controls and procedures were not effective as of December 31, 2004.

     A material weakness is a control deficiency, or combination of control
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be prevented
or detected. As of December 31, 2004, Iroquois did not maintain effective
controls over the preparation and review of Iroquois' consolidated statement of
cash flows. Specifically, Iroquois did not maintain effective controls to
appropriately exclude from capital expenditures reported in the consolidated
statement of cash flows capital expenditures that were unpaid and included in
accounts payable at the end of the reporting period. Thus capital expenditures
were reported in the consolidated statement of cash flows on an accrual basis
rather than on a cash basis. This error resulted in a misstatement of cash flows
from investing and operating activities. This control deficiency resulted in the
restatement of the Company's consolidated financial statements for the years
ended December 31, 2002, 2003 and 2004 and for all interim periods in 2004 and
2003. Additionally, this control deficiency could result in a misstatement of
the consolidated statement of cash flows that would result in a material
misstatement to annual or interim financial statements that would not be
prevented or detected. Accordingly, management has determined this control
deficiency constitutes a material weakness. Because of this material weakness,
management has concluded that the Company did not maintain effective internal
control over financial reporting as of December 31, 2004 based on the criteria
established in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organizations.

Changes in Internal Control Over Financial Reporting

  A material weakness is a control deficiency, or combination of
control deficiencies, that results in more than a remote likelihood that a
material misstatement of the annual or interim financial statements will not be
prevented or detected. As of December 31, 2004, Iroquois did not maintain
effective controls over the preparation and review of Iroquois' consolidated
statement of cash flows. Specifically, Iroquois did not maintain effective
controls to appropriately exclude from capital expenditures reported in the
consolidated statement of cash flows, capital expenditures that were unpaid and
included in accounts payable at the end of the reporting period. Thus capital
expenditures were reported in the consolidated statement of cash flows on an
accrual basis rather than on a cash basis. This error resulted in a misstatement
of cash flows from investing and operating activities. This control deficiency
resulted in the restatement of the Company's consolidated financial statements
for the years ended December 31, 2002, 2003 and 2004 and for all interim periods
in 2004 and 2003. Additionally, this control deficiency could result in a
misstatement of the consolidated statement of cash flows that would result in a
material misstatement to annual or interim financial statements that would not
be prevented or detected. Accordingly, management has determined this control
deficiency constitutes a material weakness. Because of this material weakness,
management has concluded that the Company did not maintain effective internal
control over financial reporting as of December 31, 2004 based on the criteria
established in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organizations.

     There was no change in internal control over financial reporting during the
last fiscal quarter that has materially affected, or is reasonably likely to
materially affect, Iroquois' internal control over financial reporting.

     In an effort to remediate the material weakness in Iroquois' internal
control over financial reporting described above, management has implemented a
process to identify the amount of unpaid capital expenditures at the end of the
reporting period to ensure capital expenditures are properly reflected in the
statement of cash flows in accordance with SFAS 95. Accordingly, management
believes this process will remediate the material weakness discussed above.


                                       38

<PAGE>


ITEM 9B. OTHER INFORMATION

     None.

                                   PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP

Executive Officers

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

<TABLE>
<CAPTION>

Name                                  Age           Position
----                                  ---           ---------
<S>                                   <C>           <C>
E.J. "Jay" Holm                       60            President

Paul Bailey                           58            Vice President and Chief Financial Officer

Jeffrey A. Bruner                     46            Vice President, General Counsel and Secretary

Scott E. Rupff                        40            Vice President, Marketing and Commercial Operations

</TABLE>

     E.J. "Jay" Holm is President of IPOC. Jay Holm 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


                                       39
<PAGE>


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 PipeLine Corporation, an interstate pipeline affiliate of
Transco Energy.

     Scott E. Rupff is Vice President, Marketing and Commercial Operations of
IPOC. Mr. Rupff has 18 years of experience in the natural gas industry. Prior to
becoming Vice President, Mr. Rupff was Director of Marketing. Mr. Rupff, joined
IPOC in 1994. Prior to joining IPOC, Mr. Rupff was employed by The Long Island
Lighting Company, or LILCO from 1986 to 1994,. While at LILCO, Mr. Rupff held
various positions within the gas supply organization.

     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             47         Dominion Resources, Inc.                         Dominion Iroquois, Inc.

Carl A. Taylor                40         Energy East                                      TEN Transmission Company

Richard A. Rapp               46         KeySpan Corporation                              NorthEast Transmission
                                                                                          Company, KeySpan IGTS
                                                                                          Corp.

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

Thomas Hoatson                49         Goldman Sachs Group                              JMC-Iroquois, Inc.
                                                                                          Iroquois Pipeline
                                                                                          Investment, LLC

Dean K. Ferguson              35         TransCanada PipeLines Limited                    TransCanada Iroquois
                                                                                          Ltd./TCPL Northeast Ltd.
</TABLE>


                                       40
<PAGE>


     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 currently President, The Energy Network, Inc., which is a
subsidiary of Energy East Corporation, and is responsible for managing Energy
East's non-utility companies. Mr. Taylor was previously President of NYSEG
Solutions, Inc. Prior to 1998, Mr. Taylor held various management positions at
New York State Electric and Gas Corp.

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

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

     Thomas Hoatson is a Vice President for J. Aron & Co., a wholly-owned
subsidiary of the Goldman Sachs Group. Mr. Hoatson replaced Mr. Roger Aikens of
National & Energy Gas Transmission, Inc., or NEGT, as of February 1, 2005 as a
result of NEGT selling its interests in JMC-Iroquois, Inc. and Iroquois Pipeline
Investment, LLC to a subsidiary of Cogentrix Energy Inc. (itself a wholly-owned
subsidiary of the Goldman Sachs Group). Mr. Hoatson has over 25 years experience
in the power industry including development, operations, and management.

     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 does not have
employees and 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.


                                       41
<PAGE>


ITEM 11. EXECUTIVE COMPENSATION

     Summary Compensation Table. The following summary compensation table sets
forth information regarding compensation for fiscal years 2004, 2003 and 2002
paid to the President and each of the four other most highly compensated
executive officers of IPOC. We refer to these individuals as the "named
executive officers." All compensation to the executive officers is paid by IPOC
and reimbursed by the Partnership.

<TABLE>
<CAPTION>

                                          SUMMARY COMPENSATION TABLE


                                                    Annual Compensation
                                 ----------------------------------------------------------
                                                                            Other Annual       All Other
  Name and                                                                  Compensation      Compensation
  Principal Position              Year     Salary ($) (1)     Bonus ($)        ($) (4)          ($) (5)
  ------------------              ----     --------------     ---------        -------          -------
  <S>                             <C>           <C>            <C>             <C>                <C>
  Edward J. Holm                  2004          294,439.25     114,848.97        ---              $13,000.00
    President(2)

                                  2003          214,748.79      98,658.00      $153,009.10               ---


  Paul Bailey                     2004          204,132.70      51,586.57        ---              124,608.47
    Vice President and Chief
    Financial Officer


                                  2003          197,050.67      43,936.00        ---              113,026.57

                                  2002          193,089.42      57,000.00        ---              106,122.20


  Jeffrey A. Bruner               2004          174,042.32      54,888.54        ---               80,186.58
    Vice President, General
    Counsel and Secretary

                                  2003          167,335.08      44,172.00        ---               67,886.42

                                  2002          157,103.91      39,100.00        ---               59,409.00


  Scott E. Rupff                  2004          129,571.50      43,329.06      364.71               6,563.07
    Vice President, Marketing
    and Commercial Operations

                                  2003          104,606.84      17,344.00        ---                5,314.92

                                  2002          100,583.34      23,000.00        ---                5,113.68


  Herbert A. Rakebrand III        2004          382,987.71            ---        ---                2,556.76
    Vice President, Marketing
    and Transportation (3)

                                  2003          190,479.02      41,974.00        ---               89,766.90

                                  2002          190,895.76      54,400.00        ---               79,268.01

</TABLE>

-----------------------------
(1)      Amounts reported for the 2004, 2003 and 2002 fiscal years,
         respectively, include salary paid in lieu of vacation for the
         following: Mr. Holm -- $0, $10,633.33 and $0; Mr. Bailey -- $5,753.32,
         $3,328.05 and $3,165.40; Mr. Bruner -- $1,420.66, $7,755.92 and
         $653.85; Mr. Rupff -- $0, $160.93 and $0; and Mr. Rakebrand --
         $3,630.20, $5,409.72 and $9,455.28.

(2)      Mr. Holm joined IPOC in April 2003.

(3)      Mr. Rakebrand resigned as Vice President, Marketing and Transportation
         effective as of March 31, 2004. The aggregate amount of $382,987.71
         reflected in this column for Mr. Rakebrand represents the following
         amounts:


                                       42
<PAGE>


         $50,680.51 for salary paid in fiscal year 2004, $3,630.20 for salary
         paid in lieu of vacation (as disclosed above) and $328,677 in
         consideration for the various conditions and promises set forth in his
         separation agreement, dated March 24, 2004, which was to be paid in
         five equal installments during the one-year period commencing from the
         effective date of his resignation.

(4)      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 and a tax gross up of 364.71 for Mr. Rupff in the
         2004 fiscal year.

(5)      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 2004, the named executive officers became entitled to receive the
         following amounts under the long-term incentive plan: Messrs. Bailey
         and Bruner became entitled to receive $114,605 and $71,471,
         respectively; and each of Messrs. Holm, Rupff and Rakebrand became
         entitled to receive $0. For fiscal year 2003, the named executive
         officers became entitled to receive the following amounts under the
         long-term incentive plan: Messrs. Bailey, Bruner and Rakebrand became
         entitled to receive $103,256, $59,823, $80,429, respectively; and each
         of Mr. Holm and Mr. Rupff 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: Messrs. Bailey,
         Bruner and Rakebrand became entitled to receive $95,647, $51,502 and
         $69,896, respectively; and each of Mr. Holm and Mr. Rupff became
         entitled to receive $0. Another portion of the amounts presented in
         this column represent the matching contributions made by IPOC under the
         Iroquois Pipeline Operating Company Savings Plan (the "401(k) Plan")
         and the IPOC Supplemental 401(k) Savings Plan (the "Supplemental
         Plan"). Under the 401(k) Plan, which is generally available to all
         employees, IPOC currently matches a participant's tax-deferred
         contributions by an amount equal to 100% of such contribution for each
         year, up to 5% of the participant's annual compensation. Under the
         Supplemental Plan, IPOC currently matches the tax-deferred
         contributions by a select group of management or highly compensated
         employees in an amount equal to 100% of such contribution for each
         year, up to 5% of the participant's annual compensation, less any
         matching contributions allocated to the participant's account under the
         401(k) Plan. The following contributions were made during the 2004,
         2003 and 2002 fiscal years, respectively, under the 401(k) Plan: Mr.
         Holm received $10,250, $0 and $0; Mr. Bailey received $10,003.47,
         $9,770.57 and $9,580.70; Mr. Bruner received $8,715.58, $8,063.42 and
         $7,907; Mr. Rupff received $6,563.07, $5,314.92 and $5,113.68; and Mr.
         Rakebrand received $2,556.76, $9,337.90 and $9,147.50. The following
         amounts were received during the 2004, 2003 and 2002 fiscal years,
         respectively, under the Supplemental Plan: Mr. Holm received $2,750, $0
         and $0; Mr. Bailey received $0, $0 and $894.50; and Mr. Rakebrand
         received $0, $0 and $224.51.

Long-Term Incentive Plan

     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 or, performance
units ("Performance Units"), which are valued annually based upon our year-end
book value and our average return on rate base equity. The payout value of the
Performance Units is based on the sum of (i) the value of the Performance Units
at the end of a performance period and (ii) the amount of dividends per
Performance Unit during the period. Payment on the Performance Units is made in
cash within 30 days following completion of our audited financial statements.

     The Performance Units generally vest and become payable over five years,
with 50% of each award vesting at the end of the third year and 25% vesting at
the end of each of the fourth and fifth years. Upon a termination of a
participant's employment with IPOC or its subsidiaries, for any reason other
than death, disability, or retirement, all unvested Performance Units will be
forfeited and no payment will be paid with respect to such forfeited Performance
Units. Upon a


                                       43
<PAGE>


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 summary compensation table reflects the amounts that became vested and
payable to the named executive officers under the performance share unit plan
for fiscal year 2004. There were no grants awarded to the named executive
officers pursuant to the performance share unit plan in fiscal year 2004.

Pension Plans

     IPOC sponsors a qualified non-contributory, cash balance retirement plan
("CBRP") covering substantially all of its employees and excess benefit plans
("EBPs") covering certain key employees. Under the CBRP, 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 EBPs are 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 EBPs, the benefits provided to
Mr. Bailey takes into account his years of service with TransCanada Pipelines
Limited. The benefits under the excess pension plan are not subject to the
provisions of the Internal Revenue Code that limit the compensation used to
determine benefits and the amount of annual benefits payable under the qualified
pension plan.

     The following table illustrates, for representative annual covered
compensation and years of benefit service classifications, the annual retirement
benefit that would be payable to employees under both the non-contributory cash
balance retirement plan and the excess benefit plan if they retired in 2005 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.


<TABLE>
<CAPTION>

                                             PENSION PLAN TABLE

                                              Years of Service
--------------------------------------------------------------------------------------------------------------
   Remuneration                 15                  20               25               30                35
--------------------------------------------------------------------------------------------------------------
<S>                           <C>                <C>              <C>               <C>               <C>

     150,000                  41,405             60,992            87,928           117,845           159,224

     200,000                  56,815             83,824           120,908           162,323           219,491

     250,000                  72,224            106,656           153,886           206,801           279,758

     300,000                  87,633            129,488           186,865           251,280           340,023

     350,000                 103,042            152,320           219,845           295,757           400,289

     400,000                 118,451            175,152           252,824           340,236           460,556

     450,000                 133,861            197,984           285,803           384,714           520,822

     500,000                 149,270            220,816           318,782           429,192           581,088

</TABLE>


     The number of years of credited service, as of December 31, 2004, for
Messrs. Holm, Bailey, Bruner, Rupff and Rakebrand are as follows: 1.67, 22.33,
12.58, 10.33 and 12.33,


                                       44
<PAGE>


respectively. These numbers include the credited service with TransCanada
Pipelines Limited pursuant to the excess pension plan.

Supplemental Executive Retirement Agreement

     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
Limited pension plans, the IPOC 401(k) plan and his social security benefits.

Compensation of the Management Committee

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

Compensation Committee Interlocks and Insider Participation

     The human resources committee, a sub-committee composed of members of the
management committee, determines the policies applicable to the manner in which
the Partnership's executives are compensated. The members of the human resources
committee are representatives from Keyspan, Dominion and TransCanada. None of
the members of the human resources committee has ever been an officer of the
Partnership, or any subsidiary thereof, had any direct or indirect personal or
professional economic dealings with the Partnership, or any subsidiary thereof,
or engaged in any other activity that is required to be disclosed as an
interlock or insider participation matter.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The Partners

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


<TABLE>
<CAPTION>
                                                                     General       Limited            Total
                                                                     Partner       Partner          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%

</TABLE>



                                       45
<PAGE>


<TABLE>
<CAPTION>

                                                                     General       Limited            Total
                                                                     Partner       Partner          Partnership
Ultimate Parent                  Name of Partner                     Interest      Interest           Interest
---------------                  ---------------                     ---------     --------         -----------
<S>                              <C>                                 <C>            <C>              <C>
  Dominion Resources, Inc.       Dominion Iroquois, Inc.             24.72%           --             24.72%


  Cogentrix Energy, Inc.         JMC-Iroquois, Inc.                  4.57%           .36%             4.93%
                                 Iroquois Pipeline Investment,       0.84%            --              0.84%
                                 LLC


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


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


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Affiliates of each partner of the Partnership transport natural gas on the
Partnership's pipeline system, at rates, terms and conditions contained in its
FERC approved tariff. Approximately 49% of natural gas under long-term firm
contract was transported by affiliates of partners for the year ended December
31, 2004.

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 2004 and 2003 and for other
services rendered during 2004 and 2003 on behalf of the Partnership:


           Fee Category                        2004                2003
           ------------                        ----                ----

           Audit Fees                        $141,500            $141,500

           Audit-Related Fees                  44,500              21,000

           Tax Fees                            39,090              39,500

           All Other Fees                          __                  __
                                         --------------      --------------
           Total Fees:                       $225,090            $202,000


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.


                                       46
<PAGE>


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:


                                                     2004              2003
                                                     ----              ----

                   Tax Compliance                   $21,300           $19,500

                   Tax Advice                        17,790            20,000
                                               --------------    --------------
                   Total                            $39,090           $39,500
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 2004 or 2003.

                                    PART IV.

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

    (a)   1.   Financial Statements

               The Index to Financial Statements on 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.


                                       47
<PAGE>


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

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

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

  4.4*    Form of Exchange Note.

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

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

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

 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 Paul Bailey.

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

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


                                       48
<PAGE>


 12.1*    Statements regarding computation of ratios.

 14.1***  Code of Business Ethics.

 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.

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

     *    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.

     ***  Previously filed as an exhibit to the Partnership's Annual Report on
          Form 10-K for the year ended December 31, 2003.


                                       49
<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: June 22, 2005              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 June 22, 2005.


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


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



/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



                                       50
<PAGE>




/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
---------------------------
Joseph P. Shields



/s/ Thomas Hoatson               Representative on the Management Committee
---------------------------
Thomas Hoatson




                                       51
<PAGE>


                          INDEX TO FINANCIAL STATEMENTS

                                                                            Page
                                                                            ----

Report of Independent Registered Public Accounting Firm......................F-2

Financial Statements


     Consolidated Statements of Income for the years ended December 31,
            2004, 2003 and 2002..............................................F-3

     Consolidated Balance Sheets as of December 31, 2004 and 2003............F-4

     Consolidated Statements of Cash Flows for the years ended December 31,
            2004, 2003 and 2002..............................................F-6

     Statements of Changes in Partners' Equity for the years ended
            December 31, 2004, 2003 and 2002 ................................F-7

     Notes to Financial Statements...........................................F-8




                                      F-1
<PAGE>




             Report of Independent Registered Public Accounting Firm

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 "Partnership") at
December 31, 2004 and 2003, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2004 in
conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Partnership'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 the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, 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.

As discussed in Note 2, the accompanying consolidated financial statements have
been restated.

PricewaterhouseCoopers LLP
Boston, Massachusetts
February 1, 2005, except for Note 2
"2004 Restatement", as to
which the date is June 21, 2005


                                      F-2
<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

                        CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>

                                                                          (thousands of dollars)

FOR YEAR ENDED DECEMBER 31                                         2004              2003            2002

<S>                                                             <C>                 <C>             <C>
OPERATING REVENUES                                              $151,996            $132,009        $126,320

OPERATING EXPENSES:

  Operation and maintenance                                       27,609              25,400          23,911

  Depreciation and amortization                                   31,636              24,090          23,684

  Taxes other than income taxes                                   14,619              12,333          11,206
                                                            ------------------- --------------- ----------------
  Total Operating Expenses                                        73,864              61,823          58,801
                                                            ------------------- --------------- ----------------


OPERATING INCOME                                                  78,132              70,186          67,519
                                                            ------------------- --------------- ----------------

OTHER INCOME/(EXPENSES):

  Interest income                                                    453                 226             416

  Allowance for equity funds used
    during construction                                            1,123               8,670           2,319

  Other, net                                                      (2,619)               (727)         (2,228)
                                                            ------------------- --------------- ----------------
                                                                  (1,043)              8,169             507
                                                            ------------------- --------------- ----------------



INTEREST EXPENSE:

  Interest expense                                                33,421              33,384          27,892

  Allowance for borrowed funds
    used during construction                                      (1,070)             (8,565)         (2,744)
                                                            ------------------- --------------- ----------------

    Net Interest Expense                                          32,351              24,819          25,148
                                                            ------------------- --------------- ----------------

INCOME BEFORE INCOME TAXES
AND CUMULATIVE EFFECT OF
CHANGE
IN ACCOUNTING PRINCIPLE                                           44,738              53,536          42,878


PROVISION FOR INCOME TAXES                                        18,013              21,435          16,911


INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE                                              26,725              32,101          25,967


CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE,
NET OF TAX                                                            __               3,715              __
                                                            ------------------- --------------- ----------------

NET INCOME                                                       $26,725             $35,816         $25,967
                                                            ====================================================
</TABLE>



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



                                      F-3
<PAGE>



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


<TABLE>
<CAPTION>


ASSETS                                                                              (thousands of dollars)

AT DECEMBER 31                                                                    2004                  2003

<S>                                                                             <C>                     <C>
CURRENT ASSETS:

  Cash and temporary cash investments                                             $36,393               $36,344

  Accounts receivable - trade, net                                                  6,752                 7,080

  Accounts receivable - affiliates                                                  6,584                 5,495

  Prepaid property taxes                                                            5,602                 3,248

  Other current assets                                                              4,914                 3,165
                                                                              -------------          ------------
    Total Current Assets                                                           60,245                55,332
                                                                              -------------          ------------

</TABLE>


<TABLE>
<CAPTION>

<S>                                                                             <C>                     <C>

NATURAL GAS TRANSMISSION PLANT:

  Natural gas plant in service                                                  1,094,821               802,220

  Construction work in progress                                                     6,472               280,528
                                                                              -------------          ------------
                                                                                1,101,293             1,082,748

  Accumulated depreciation and amortization                                      (350,091)             (323,405)
                                                                              -------------          ------------
    Net Natural Gas Transmission Plant                                            751,202               759,343
                                                                              -------------          ------------


OTHER ASSETS AND DEFERRED CHARGES:

  Regulatory assets - income tax related                                           19,449                19,174

  Regulatory assets - other                                                         1,285                 1,473

  Other assets and deferred charges                                                11,686                13,383
                                                                              -------------          ------------


    Total Other Assets and Deferred Charges                                        32,420                34,030
                                                                              -------------          ------------


    TOTAL ASSETS                                                                 $843,867              $848,705
                                                                              =============          ============

</TABLE>


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



                                      F-4
<PAGE>



                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>

LIABILITIES AND PARTNERS' EQUITY                                         (thousands of dollars)

AT DECEMBER 31                                                          2004                     2003

<S>                                                                    <C>                     <C>
CURRENT LIABILITIES:

  Accounts payable                                                       $9,454                 $21,424

  Accrued interest                                                        4,674                   4,626

  Current portion of long-term debt (Note 4)                             32,222                  32,222

  Customer deposits                                                       3,899                   5,132

  Other current liabilities                                               2,250                   2,293
                                                                      -------------           -------------
   Total Current Liabilities                                             52,499                  65,697
                                                                      -------------           -------------

LONG-TERM DEBT (NOTE 4)                                                 425,556                 447,778
                                                                      -------------           -------------


OTHER NON-CURRENT LIABILITIES:

  Unrealized loss-interest rate hedge                                     1,771                   3,263

  Other non-current liabilities                                           1,486                   1,821
                                                                      -------------           -------------
    Total Other Non-Current Liabilities                                   3,257                   5,084
                                                                      -------------           -------------


AMOUNTS EQUIVALENT TO

 DEFERRED INCOME TAXES:

  Generated by Partnership                                              158,669                 122,220

  Payable by Partners                                                  (139,220)               (103,046)

  Related to Other Comprehensive Income                                    (715)                 (1,671)
                                                                      -------------           -------------
    Total Amounts Equivalent to Deferred

    Income Taxes                                                         18,734                  17,503
                                                                      -------------           -------------
COMMITMENTS AND
CONTINGENCIES (NOTE 7)

   TOTAL LIABILITIES                                                    500,046                 536,062
                                                                      -------------           -------------

PARTNERS' EQUITY                                                        343,821                 312,643
                                                                      -------------           -------------

  TOTAL LIABILITIES AND
  PARTNERS' EQUITY                                                     $843,867                $848,705
                                                                      =============           =============
</TABLE>



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



                                      F-5
<PAGE>



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


<TABLE>
<CAPTION>
                                                                                    (thousands of dollars)

FOR THE YEARS ENDED DECEMBER 31                                               2004             2003             2002
                                                                            Restated         Restated          Restated

<S>                                                                          <C>             <C>               <C>
CASH FLOWS FROM OPERATING ACTIVITIES:

  Net Income                                                                 $26,725          $35,816           $25,967

  Adjusted for the following:

    Depreciation and amortization                                             31,636           24,090            23,684

    Allowance for equity funds used
      during construction                                                     (1,123)          (8,670)           (2,319)

    Deferred regulatory assets-income tax related                               (275)          (5,094)             (782)

    Amounts equivalent to deferred income taxes                                  275            5,094               782

    Income and other taxes payable by Partners                                18,013           23,916            16,911

    Other assets and deferred charges                                          1,680            1,551            (8,446)

    Other non-current liabilities                                                490             (515)              257

    Changes in Working Capital:

        Accounts receivable                                                     (761)            (721)             (107)

        Prepaid property taxes                                                (2,354)          (2,303)              (68)

</TABLE>


<TABLE>
<CAPTION>

<S>                                                                          <C>             <C>               <C>
       Other current assets                                                   (1,749)            (272)             (476)

       Accounts payable                                                          123               65              (336)

       Accrued interest                                                           48           (2,213)            3,930

       Customer deposits                                                      (1,233)           4,773               356

       Other current liabilities                                                 (43)          (5,127)               45
                                                                           ------------    ------------      ------------

NET CASH PROVIDED BY
OPERATING ACTIVITIES:                                                         71,452           70,390            59,398
                                                                           ------------    ------------      ------------


CASH FLOWS FROM INVESTING ACTIVITIES:

  Capital expenditures                                                       (34,181)        (148,444))        (100,049)
                                                                           ------------    ------------      ------------
   NET CASH USED FOR INVESTING ACTIVITIES                                    (34,181)        (148,444)         (100,049)
                                                                           ------------    ------------      ------------


CASH FLOWS FROM FINANCING ACTIVITIES:

  Partner distributions                                                      (15,000)              --                --

  Long-term debt borrowings                                                       --           95,000           205,000

  Repayments of long-term debt                                               (22,222)         (22,222)         (164,444)

  Partner contributions                                                           --           20,000                --
                                                                           ------------    ------------      ------------
    NET CASH PROVIDED BY / (USED FOR)
    FINANCING ACTIVITIES                                                     (37,222)          92,778            40,556
                                                                           ------------    ------------      ------------


NET INCREASE/(DECREASE) IN CASH AND
  TEMPORARY CASH INVESTMENTS                                                      49           14,724               (95)


CASH AND TEMPORARY CASH INVESTMENTS
   AT BEGINNING OF YEAR                                                       36,344           21,620            21,715
                                                                           ------------    ------------      ------------

CASH AND TEMPORARY CASH
  INVESTMENTS AT END OF YEAR                                                 $36,393          $36,344           $21,620
                                                                           ------------    ------------      ------------

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

  CASH PAID FOR INTEREST                                                     $31,744          $33,969           $23,060
                                                                           ------------    ------------      ------------

ACCOUNTS PAYABLE ACCRUALS FOR
   CAPITAL EXPENDITURES                                                      $ 8,504          $20,597           $15,941
                                                                           ============    ============      ============
</TABLE>




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



                                      F-6
<PAGE>


                     IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
                    STATEMENT OF CHANGES IN PARTNERS' EQUITY
                             (thousands of dollars)

<TABLE>
<CAPTION>
                                                                                                     Accumulated
                                                      Taxes          Equity          Equity             Other           Total
                                          Net        Payable     Distributions    Contributions     Comprehensive     Partners'
                                        Income      by Partners    to Partners     by Partners      Income/(Loss)       Equity
<S>                                      <C>          <C>           <C>                <C>               <C>            <C>
Balance at December 31, 2001             $256,769     $ 166,940     $ (490,544)        $ 259,381         $   (1,782)    $190,764
                                      ===========================================================================================


Net income                                 25,967                                                                         25,967

Taxes payable by partners                                16,911                                                           16,911

Other comprehensive loss,                                                                                    (1,569)     (1,569)
net of tax
Balance at December 31, 2002             $282,736     $ 183,851     $ (490,544)        $ 259,381         $   (3,351)    $232,073
                                      ===========================================================================================


Net income                                 35,816                                                                         35,816

Taxes payable by partners                                23,916                                                           23,916

Equity contributions                                                                      20,000                          20,000

Other comprehensive income,                                                                                     838          838
net of tax
Balance at December 31, 2003             $318,552     $ 207,767     $ (490,544)        $ 279,381         $   (2,513)    $312,643
                                      ===========================================================================================


Net income                                 26,725                                                                         26,725

Taxes payable by partners                                18,013                                                           18,013

Equity distributions                                                   (15,000)                                         (15,000)

Other comprehensive income,                                                                                   1,440        1,440
net of tax

Balance at December 31, 2004             $345,277     $ 225,780     $ (505,544)        $ 279,381         $   (1,073)    $343,821
                                      ===========================================================================================
</TABLE>


                                      F-7
<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, 2004, 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. Total cash distributions of $15.0 million were made to Partners
during 2004. There were no cash distributions to Partners during 2003 or 2002.


     NOTE 2

     2004 RESTATEMENT

     The consolidated statements of cash flows for the years ended December 31,
2004, 2003 and 2002 have been restated. The Partnership previously did not
exclude from capital expenditures reported in the consolidated statements of
cash flows, capital expenditures that were unpaid and included in accounts
payable at the end of the reporting period. Thus capital expenditures were
reported in the consolidated statements of cash flows on an accrual basis rather
than on a cash basis which is inconsistent with the requirements of SFAS No. 95,
"Statement of Cash Flows". This error resulted in an over/understatement of cash
flows from investing activities with an equal over/understatement of cash flows
from operating activities. This restatement did not impact the Partnership's
previously reported balance sheets or statements of income.

     The following table sets forth the effects of the restatement on certain
line items within the Partnership's previously reported consolidated statement
of cash flows for the twelve months ended December 31, 2004:


                                                     (in thousands)
                                              As
                                           Originally                 As
                                            Reported   Adjustment   Restated

Changes in working capital -
  accounts payable                         $(11,970)    $ 12,093    $   123

Net cash provided by operating
  activities                               $ 59,359     $ 12,093    $ 71,452

Cash flows from investing activities -
  capital expenditures                     $(22,088)    $(12,093)   $(34,181)

Net cash used in investing activities      $(22,088)    $(12,093)   $(34,181)

Accounts payable accruals for capital
  expenditures                             $     --     $  8,504    $  8,504



     The following table sets forth the effects of the restatement on certain
line items within the Partnership's previously reported consolidated statement
of cash flows for the twelve months ended December 31, 2003:

                                                     (in thousands)
                                              As
                                           Originally                 As
                                            Reported   Adjustment   Restated

Changes in working capital -
  accounts payable                         $   4,721   $  (4,656)    $     265

Net cash provided by operating
  activities                               $  75,046   $  (4,656)    $  70,390

Cash flows from investing activities -
  capital expenditures                     $(153,100)  $   4,656     $(148,444)

Net cash used in investing activities      $(153,100)  $   4,656     $(148,444)

Supplemental Disclosures of Cash Flow
  Information:
Accounts Payable Accrual for
  Capital Expenditures                     $     -     $  20,597     $  20,597

     The following table sets forth the effects of the restatement on certain
line items within the Partnership's previously reported consolidated statement
of cash flows for the twelve months ended December 31, 2002:

                                                     (in thousands)
                                              As
                                           Originally                 As
                                            Reported   Adjustment   Restated

Changes in working capital -
  accounts payable                         $   9,048   $  (9,384)    $   (336)

Net cash provided by operating
  activities                               $  68,782   $  (9,384)    $  59,398

Cash flows from investing activities -
  capital expenditures                     $(109,433)  $   9,384     $(100,049)

Net cash used in investing activities      $(109,433)  $   9,384     $(100,049)

Supplemental Disclosures of Cash Flow
  Information:
Accounts Payable Accrual for
  Capital Expenditures                     $     -     $  15,941     $  15,941

     NOTE 3

     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

     Basis of Presentation

     The consolidated financial statements of the Partnership 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 Partnership 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 Partnership
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
Partnership and Iroquois Pipeline Operating Company. Intercompany transactions
have been eliminated in consolidation.


                                      F-8
<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 $36.4 million at December
31, 2004 and $36.3 million at December 31, 2003 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, 2004, construction work in progress included construction
costs relating mainly to the Brookfield Project, ancillary projects related to
Eastchester 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 Partnership 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-9
<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 $25.0 million, and a fair
value of ($1.8) million, net of taxes. The Partnership records the market value
of these interest rate swaps on its financial statements as a component of Other
Comprehensive Income (Partners' Equity) and Other Non-current Liabilities.

     Change in Method of Accounting for Municipal Property Taxes

     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 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 materially
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.


                                      F-10
<PAGE>

     New Accounting Standards

     Inventory Costs. In November 2004, the FASB issued SFAS No. 151, "Inventory
Costs, an amendment of ARB No. 43, Chapter 4." SFAS No. 151 amends the guidance
on inventory pricing to require that abnormal amounts of idle facility expense,
freight, handling costs and wasted material be charged to current period expense
rather than capitalized as inventory costs. SFAS No. 151 also requires that
allocation of fixed production overheads to the costs of conversion be based on
the normal capacity of the production facilities. SFAS No. 151 is effective for
inventory costs incurred during fiscal years beginning after June 15, 2005.

     Non-monetary Transactions. Also in December 2004, the FASB issued SFAS No.
153, "Exchanges of Nonmonetary Assets, an amendment of Accounting Principles
Board (APB) Opinion No. 29, Accounting for Nonmonetary Transactions." SFAS No.
153 redefines the types of nonmonetary exchanges that require fair value
measurement. SFAS No. 153 is effective for nonmonetary transactions entered into
on or after July 1, 2005.

     The Partnership expects that the implementation of these two new standards
will not have a material impact upon the Partnership's financial condition,
results of operations or cash flows.

     Other Comprehensive Income

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

<TABLE>
<CAPTION>

        Year end December 31,                                                   2004                   2003
                                                                                ----                   ----
<S>                                                                           <C>                      <C>
        NET INCOME:                                                           $26,725                  $35,816
                                                                            -----------              -----------
        OTHER COMPREHENSIVE INCOME (LOSS):

        Unrealized loss on interest rate hedge,
        net of tax of (32) and (229), respectively                                (48)                    (345)

        Reclassification to net income,
        net of tax of 629 and 779, respectively                                   944                    1,171
                                                                            -----------              -----------
        Unrealized gain (loss) on interest rate hedge, net of
        reclassification adjustment                                               896                      826
                                                                            -----------              -----------
        Additional minimum liability on pension plan, net of tax
        of 329 and (22), respectively                                             495                      (34)

        Unrealized gain on supplemental pension plan, net of tax
        of 32 and 31, respectively                                                 49                       46
                                                                            -----------              -----------
        Comprehensive Income                                                  $28,165                  $36,654
                                                                            ===========              ===========
</TABLE>


                                      F-11
<PAGE>


     NOTE 4

     LONG TERM DEBT:

     Detailed information on long-term debt is as follows:

<TABLE>
<CAPTION>

                                                                                            December 31,
                                                                                      2004                2003
                                                                                      ----                ----
<S>                                                                                <C>                 <C>
Senior Notes - 8.68% due 2010                                                      $200,000            $200,000
Senior Notes - 6.10% due 2027                                                       170,000             170,000
Term Loan Facility due 2008(LIBOR)                                                   77,778             100,000
Revolving Credit Facility due 2005 (LIBOR)                                           10,000              10,000
                                                                                 ------------        ------------
                                            Total                                  $457,778            $480,000

Less Current Maturities of Long-Term Debt                                            32,222              32,222

     Long-Term Debt                                                                $425,556            $447,778

</TABLE>

     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, 2004 and December 31,
2003, the aggregate notional principal amount of these two swaps was $25.0
million and $30.6 million, respectively. The fair value of these interest rate
swaps, net of taxes at December 31, 2004 and December 31, 2003, was ($1.8)
million and ($2.0) million, respectively.


                                      F-12
<PAGE>



     The combined schedule of repayments at December 31, 2004 is as follows
(millions of dollars):

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

                     2005                                       $ 32.2
                     2006                                       $ 22.2
                     2007                                       $ 22.2
                     2008                                       $ 22.3
                     2009                                       $ 27.6
                     Thereafter                                 $331.2

     NOTE 5

     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 6

     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 Partnership could realize in a current market exchange.

     As of December 31, 2004 and December 31, 2003, 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, 2004 and December
31, 2003, the carrying amounts and estimated fair values of the Partnership's
long-term debt including current maturities were as follows (in thousands of
dollars):


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

                 2004                  $457,778             $504,334
                 2003                  $480,000             $541,568



                                      F-13
<PAGE>



     NOTE 7

     COMMITMENTS AND CONTINGENCIES:

     Regulatory Proceedings

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

     On October 24, 2003, the FERC approved a 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
January 1, 2008. 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 reduced from the then
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 2003
long-term firm service contracts as of December 31, 2004, the settlement
resulted in reductions in revenues of approximately $3.8 million in 2004 and
will result in reductions in revenues of $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
became 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 proposed 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 served as the initial rate per the certificate
order). The increased rate reflected, among other things, an increase in plant
costs from the certificate estimate of $210 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 customers 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.


                                      F-14
<PAGE>

     On June 15 and July 8, 2004, settlement conferences were convened at the
FERC's offices to attempt to negotiate a settlement of the issues in the rate
case. As a result of those conferences, the parties reached a settlement in
principle of all issues that was supported or not opposed by all participants to
the proceeding. On July 15, 2004 the Partnership submitted a motion to the
Presiding Administrative Law Judge to suspend the procedural schedule to allow
the parties to formalize the settlement agreement; such motion was granted by
the judge on July 16. Following additional discussions and negotiations with the
parties, the Partnership submitted a comprehensive settlement agreement on
August 12, 2004. The settlement agreement provides for recourse rates of $0.66
per Dth for the period July 1, 2004 through December 31, 2007 and $0.635 per Dth
for the period January 1, 2008 through December 31, 2011. In addition, the
Partnership will not include in future rates any future legal fees (incurred
after June 30, 2004) incurred in litigation regarding construction incidents
associated with the original Eastchester Project. A moratorium on rate changes,
as spelled out more fully in the settlement agreement, will also be in effect
through December 31, 2011. The settlement agreement was approved by the FERC on
October 13, 2004 and became final on November 13, 2004.

     In addition to settling the Eastchester recourse rates as set forth above,
the Partnership has also entered into negotiated rate agreements with all of the
initial shippers on the Eastchester Extension Project. The negotiated rates on a
100% load-factor equivalent basis range between $0.47 and $0.63 per Dth
depending on whether the agreement was signed pre or post construction and the
length of the negotiated contract.

     The recourse rates and negotiated individual Eastchester shipper rates,
coupled with cost overruns experienced on the Eastchester Project, will reduce
the Partnership's initial margins that were anticipated when the project
application was filed with FERC.

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

     On November 25, 2003 the FERC issued Order No. 2004 in FERC Docket No.
RM01-10. 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. As required by said schedule, on June
1, 2004 the Partnership posted its revised standards of conduct on its internet
website, identifying the procedures established for implementing the FERC's
requirements. Additionally, as required by the order, on September 22, 2004, the
Partnership developed and posted on its website, a written procedure
implementing its standards of conduct and trained all its employees subject to
the standard. Management does not believe that the requirements of Order No.
2004 will have a material impact on the Partnership.

     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 have constructed a second compressor unit at its existing Athens, New York
compressor station. The facilities were


                                      F-15
<PAGE>


designed to provide up to 70 MDth/d of firm transportation to Athens Generating
Company, L. P. ("Athens Generating") with whom the Partnership had 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.

     The Partnership continued to market this project to potential customers and
continued to evaluate its feasibility, however, because the Partnership was
unable to secure customers prior to the December 3, 2004 construction extension
deadline, the project was cancelled and the $2.3 million in capital expenditures
was written off and charged to expense in the fourth quarter of 2004.

     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 had
determined that a temporary deferral of the construction of the Brookfield
Project was 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 other original Brookfield Project shipper,
PPL Energy Plus, LLC, or PPL, also elected to terminate its precedent agreement,
and the Partnership is currently remarketing the Brookfield Project capacity.
Additionally, the Partnership is exploring other services and products that may
also utilize Brookfield Project capacity. As of December 31, 2004, 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 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 in 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. On November 3, 2004,
the Connecticut Department of Environmental Protection approved the project's
site remediation plan and scope of work schedule. Work began in late November
2004 and is anticipated to be completed in early Spring 2005. Site remediation
is not


                                      F-16
<PAGE>


expected to have a material adverse impact on the Partnership's operating
results or financial condition.

     Legal Proceedings-Other

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

     On November 16, 2002, certain undersea electric transmission cables owned
by Long Island Lighting Partnership d/b/a The Long Island Power Authority, or
LIPA, and Connecticut Light and Power Partnership, 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, collectively
referred to as the "Cable Interests," filed third-party claims against the
Partnership and its operating subsidiary, IPOC, as well as Horizon and Thales,
seeking recovery for their 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 originally claimed 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 September 2004, the Cable Interests amended their
claim to $23.5 million, consisting of approximately $12.9 million for repairs
and repair related costs and $10.6 million in consequential damages.

     A mediation was conducted in February 2005, at the conclusion of which all
parties agreed to terms for a global settlement of the litigation. The
Partnership will be contributing nothing to the settlement, but will be given
full releases from all parties. A formal settlement agreement is being
negotiated, with a goal of all funds paid by April 15, 2005.

     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. On
March 28, 2005, the Partnership and the Town of Huntington executed a settlement
agreement resolving this matter and another relating to restoration of Town
property. The Partnership does not admit any liability but will pay $45,100 to
resolve these matters.

     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


                                      F-17
<PAGE>


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. As required by 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 they
are funding the costs for the Partnership's defense. The Partnership also
commenced a declaratory judgment action against Horizon's primary liability
insurer seeking coverage and is currently investigating the applicability of all
other 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. Horizon's suit contends that if it is not
entitled to exoneration, its liability should be limited to $19.3 million,
representing the value of the GULF HORIZON and her pending freight, and
Horizon's insurers have provided an undertaking (subject to policy defenses) to
pay any judgment that may be rendered in the suit up to $19.3 million. NYPA,
LIPA and the insurers of the Y-49 cable, collectively referred to as, the Y-49
Cable Interests, also have filed claims in the limitation action asserting total
damages of approximately $18.2 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


                                      F-18
<PAGE>


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. (For resolution of these unrelated claims, see Easchester
Contractor Litigation Settlement discussion below.) 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 filed motions to transfer the Texas
action to the United States District Court for the Eastern District of New York.
Thales 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 and that Horizon had no right to limit its liability as to the
Partnership's contract claims. The Y-49 Cable Interests filed cross claims
against the Partnership alleging claims under the Crossing Agreement between the
Partnership and NYPA in common law tort.

     The Y-49 Cable Interests filed a motion for partial summary judgment
against the Partnership on October 13, 2004. The motion asks the court to find
the Partnership liable for indemnity under the Crossing Agreement for all costs
and expenses incurred by the Y-49 Cable Interests directly related to the
emergency response to the incident and for the costs and expenses of the
temporary and permanent repairs. The Partnership believes the motion is
premature and has opposed the motion. The motion is now fully briefed and
pending before the court for decision.

     The parties presently are engaging in document discovery, and 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. 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.

     Pursuant to its agreements with the owners of the electric transmission
cables that the Eastchester facilities cross in the Long Island Sound, the
Partnership performed certain post- construction surveys to verify the condition
of the cable crossings and confirm the location of the pipeline. Specifically,
the Partnership had constructed a "structure" over the Y-50 cable system
consisting of lightweight flexible concrete mattresses under the pipeline,
specially fabricated concrete blocks adjacent to the pipeline and crushed rock.
The surveys and additional follow-up studies indicate that the "structure" may
have settled to a greater extent than originally


                                      F-19
<PAGE>


anticipated and that its location is believed to be 65 feet north of the
location where the pipeline crosses the Y-50 cable. The Partnership has been
discussing this matter with the owner of the Y-50 cable system as to whether and
how these issues should be modified and has notified the FERC by letter dated
September 3, 2004. 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 costs, if any, in the event of an unfavorable outcome.

     No liabilities have been recorded by the Partnership in conjunction with
any of the preceding legal matters.

     Eastchester Contractor Litigation Settlement
     --------------------------------------------

     On March 11, 2005, Iroquois, Horizon and its Subcontractors reached an
agreement resolving the claims and counter claims made in the Horizon, Weeks,
Cal Dive and Tom Allen proceedings described below, collectively referred to as
Eastchester Contract Suits. In addition, Iroquois has reached an agreement in
principle with certain of its insurance carriers regarding the recovery of a
portion of the costs related to a failed directional pipeline drill that
occurred during the construction of the Eastchester lateral. The Partnership's
projected $334 million total Eastchester capital costs included the costs for
the settlement of the Eastchester Contract Suits and the expected insurance
recovery associated with the directional drill.

     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 million. On April 7, 2004, the Partnership filed in
such court proceeding an amended answer and counterclaims against Horizon
totaling in excess of $66 million.

     On March 1, 2004 and in a duplicate filing on March 9, 2004, 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 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, on April 1 and April 5, 2004 in compliance
with Section 6.2(c)(ii) of its Second Supplemental Indenture, dated August 13,
2003, posted bonds to discharge the Mechanic's Liens.

     On September 10, 2004, Cal Dive filed a complaint against the Partnership
in the United States District Court for the Eastern District of New York. The
complaint alleges that Cal Dive has not been paid $3.3 million for work that it
performed on the Eastchester project. The Partnership filed an answer to the Cal
Dive action on October 15, 2004 and commenced a third party action against
Horizon on October 25, 2004.


                                      F-20
<PAGE>


     On June 14, 2004, Tom Allen Construction Company, or Tom Allen, one of
Horizon's subcontractors for the Eastchester project, filed a complaint against
Horizon and the Partnership in the Supreme Court of the State of New York, New
York County. Tom Allen was responsible for performing the directional drills at
Northport and Hunts Point. Tom Allen is claiming that it has not been paid for
work associated with a failed directional drill at Hunt's Point and is seeking
$5.6 million in damages from Horizon and the Partnership. The Partnership served
an answer to the complaint and various discovery demands on July 30, 2004.

     On July 21, 2004 Weeks Marine Inc., or Weeks, one of Horizon's
subcontractors for the Eastchester project, filed a complaint against Horizon
and the Partnership in the Supreme Court of the State of New York, New York
County. Weeks was responsible for certain marine construction operations
including dredging, rock placement, fabric placement and associated activities
along the Eastchester project. Weeks is claiming that it has not been paid for
work associated with the marine portion of the Eastchester project and is
seeking $18.5 million in damages from Horizon and the Partnership. The
Partnership filed an answer to the complaint on August 16, 2004.

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

     On January 28, 2004, Anthony Capobianco filed a complaint against the
Partnership, IPOC 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
Partnership, Inc., or 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 million. The Partnership has notified its insurance carriers and
an answer has been filed to the complaint. Hallen's insurer has agreed to
indemnify and defend the Partnership in this action up to the $1 million limit
of its general liability insurance policy. Additionally, Hallen has coverage
under an excess liability policy up to $20 million. 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.

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 transportation
contracts. In February 2004, the Partnership entered into a ten year contract
for


                                      F-21
<PAGE>


the 12,000 Dth/d while the remaining unsubscribed capacity of 40,720 Dth/d will
continue to be remarketed on a short term basis until longer term market
opportunities emerge. 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.

     On March 2, 2005, representatives of the Partnership and US Gen NE agreed
in principal to a settlement agreement regarding the Partnership's proof of
claim with the bankruptcy court. Under said settlement, the Partnership expects
to receive $8.4 million, the value of its mitigated claim as well as,
approximately $2.1 million as a result of retained cash collaterals for a total
settlement of approximately $10.5 million plus 4% interest accruing from the
start of the claim. Based on US Gen NE's disclosure statement filed with the
Bankruptcy Court, US Gen NE estimates to pay 100% of each unsecured claim. The
settlement is in the process of being approved by both parties and the
Bankruptcy Court. The Partnership expects to record any funds received as part
of this bankruptcy proceeding as "Other Income."

     On September 15, 2004, NEGT announced that it had entered into an agreement
with GS Power Holdings II LLC (a subsidiary of Goldman Sachs) to purchase NEGT's
indirect equity interest in the Partnership. NEGT's indirect interest is held
through JMC-Iroquois, Inc. and Iroquois Pipeline Investment, LLC, both of which
represent a 5.77% interest in the Partnership. On January 31, 2005, Cogentrix
Energy, Inc. ("Cogentrix") announced that, through its subsidiaries Cogentrix
Power Holdings I LLC and Cogentrix Power Holdings II LLC, it had acquired the
equity interests in both JMC-Iroquois, Inc. and Iroquois Pipeline Investment,
LLC.

Enron Corp. and Affiliated Entities Bankruptcy Filing
-----------------------------------------------------

     Enron Corp. and Enron North America Corp., collectively Enron, filed
voluntary petitions for relief under Chapter 11 of the United States Bankruptcy
Code in the United States Bankruptcy Court for the Southern District of New
York, or Bankruptcy Court, in 2001. In October 2002, the Partnership filed
Proofs of Claim with the Bankruptcy Court in the amount of $1,593,362.39 for
Claim 1 and in the amount of Unknown dollars for Claim 2 resulting from
termination by Enron of the Partnership's Gas Transportation (Contract No.
R-1250-05). On February 22, 2005, by Letter Agreement, Enron agreed to allow the
Partnership $1,816,762.70 in unsecured claims, subject to the approval of the
Bankruptcy Court. Based on Enron's disclosure statement filed with the
Bankruptcy Court, Enron estimates to pay 20% of each unsecured claim. The
Partnership expects to record any funds received as part of this bankruptcy
proceeding as "Other Income."

     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.

     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


                                      F-22
<PAGE>


addition, the Partnership leases various equipment under non-cancelable
operating leases. During the years ended December 31, 2004, 2003 and 2002, the
Partnership made payments of $1.1, $1.2 and $0.9 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
                       ----                     ------
                       2005                       $0.9
                       2006                        0.8
                       2007                        0.8
                       2008                        0.8
                       2009                        0.8
                       Thereafter                 $5.4

     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 Partnership recognizes a decrease in the Amounts Equivalent to
Deferred Income Taxes account for these amounts and records a corresponding
increase to Partners' equity. Deferred income taxes with respect to the equity
component of AFUDC remain on the accounts of the Partnership until the related
deferred regulatory asset is recognized.

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

<TABLE>
<CAPTION>

                                 U.S.
         2004                   Federal                 State                   Total
----------------------------------------------------------------------------------------------
<S>                            <C>                      <C>                   <C>
Current                        $(20,126)                $1,965                $(18,161)
Deferred                         34,999                  1,175                  36,174
                         ---------------------- ----------------------- ----------------------
Total                           $14,874                 $3,139                 $18,013
                         ====================== ======================= ======================

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

</TABLE>



                                      F-23
<PAGE>


<TABLE>
<CAPTION>

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

</TABLE>


     Not included in the above table for 2003 are the deferred taxes associated
with the cumulative change in accounting principle related to municipal property
taxes, which amounted to approximately $2.5 million.

     The variance between 2004 and 2003 U.S. Federal, current and deferred taxes
is primarily due to the effects of bonus depreciation, primarily due to the
Eastchester Extension project which went into service in February 2004.

     For the years ended December 31, 2004, 2003 and 2002, 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):

<TABLE>
<CAPTION>

                                                          2004                2003                2002
        ----------------------------------------------------------------------------------------------------
<S>                                                   <C>                  <C>                  <C>
        Depreciation                                  $  35,128            $  9,142             $11,121
        Gain/loss on disposal of asset                      445                 (67)                934
        Deferred regulatory asset                           (76)                (75)                (75)
        Property taxes                                      283               2,610                 (80)
        Accrued expenses                                     51                  47                 (51)
        Alternative minimum tax credit                      262               1,025                (585)
        Other                                                81               4,089                (314)
                                                    --------------        ------------        --------------
        Total deferred taxes                            $36,174             $16,771             $10,950
                                                    ==============        ============        ==============

</TABLE>


<TABLE>
<CAPTION>

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

        At December 31,                                                       2004                 2003
        -------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                  <C>
        DEFERRED TAX ASSETS:
        Alternative minimum tax credit                                        $ 652                $ 914
        Accrued expenses                                                      1,006                1,056
                                                                          ------------        --------------
        Total deferred tax assets                                             1,657                1,970

        DEFERRED TAX LIABILITIES:
        Depreciation and related items                                     (132,219)             (96,671)

</TABLE>


                                      F-24
<PAGE>


<TABLE>
<CAPTION>

<S>                                                                        <C>                  <C>
        Deferred regulatory asset                                              (505)                (580)
        Property taxes                                                       (3,687)              (3,404)
        Other                                                                (5,028)              (4,947)
                                                                          ------------        --------------
        Total deferred tax liabilities                                     (141,439)            (105,602)
                                                                          ------------        --------------
        Net deferred tax liabilities                                       (139,781)            (103,632)
                                                                          ------------        --------------
        Less deferral of tax rate change                                        561                  586
                                                                          ------------        --------------
        Deferred taxes-operations                                          (139,220)            (103,046)
        Deferred tax related to equity AFUDC                                (18,888)             (18,588)
        Deferred tax related to change in tax rate                             (561)                (586)
                                                                          ------------        --------------
        Total deferred taxes                                              $(158,669)           $(122,220)
                                                                          ------------        --------------
        Deferred tax related to other
        comprehensive income                                              $    (715)           $  (1,671)
                                                                          ============        ==============

</TABLE>


         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):

<TABLE>
<CAPTION>

                                                 Payments             Due (to)/from   Revenue
                                                 to Related           Related         from Related
                             2004                Parties              Parties         Parties
        -------------------------------------------------------------------------------------------------
<S>                                                       <C>               <C>                 <C>
        TransCanada Iroquois Ltd.                         $ 0.1             $(0.1)              $ --
        Dominion Iroquois, Inc.                             --                 0.2                 0.8
        NorthEast Transmission Company                      1.0                3.7                35.2
        JMC-Iroquois, Inc.                                  --                 1.1                14.2
        TEN Transmission Company                            --                 1.0                11.8
        NJNR Pipeline Company                               --                 0.6                 8.2
                                                 --------------------------------------------------------
                          Totals                          $ 1.1              $ 6.5               $70.2
                                                 ==================== =============== ===================



                                                 Payments            Due 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

</TABLE>


                                      F-25
<PAGE>


<TABLE>
<CAPTION>

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


         NOTE 10

         RETIREMENT BENEFIT PLANS:

         During 1997, the Partnership established a noncontributory cash balance
retirement plan ("CBRP") covering substantially all employees. Pension benefits
are based on years of credited service and employees' career earnings, as
defined in the CBRP. The Partnership'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 Partnership may determine to be
appropriate from time to time.

         During 1997 and 1998 the Partnership 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 Partnership'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 the CBRP and the EBP's (collectively the
"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):

<TABLE>
<CAPTION>

                                                              2004              2003             2002
         -------------------------------------------------------------------------------------------------
<S>                                                            <C>               <C>              <C>
         Service cost                                          $839              $811             $687
         Interest cost                                          307               246              194
         Expected return on plan assets                        (353)             (245)            (211)
         Amortization of prior service cost                      12                12               22
         Recognition of net actuarial loss                       59                57               22
                                                             ----------       ----------        ----------
         Net periodic pension cost before FAS 88               $864              $881             $714
                                                             ----------       ----------        ----------
         Recognized FAS 88 settlement/curtailment
         amount                                                $  --             $(87)            $ --
                                                             ==========       ==========        ==========
</TABLE>


                                      F-26
<PAGE>


         The following tables represent the Plans' combined funded status
reconciled to amounts included in the consolidated balance sheets as of December
31, 2004 and 2003 (thousands of dollars):


<TABLE>
<CAPTION>

Change in Benefit Obligation                                            2004             2003
                                                                  ----------------- ----------------
<S>                                                                    <C>              <C>
Benefit obligation at beginning of year                                $5,110            $3,861
Service cost                                                              839               811
Interest cost                                                             307               246
Actuarial gain                                                            122               346
Curtailments and settlements                                                -              (108)
Benefits paid                                                            (368)              (46)
                                                                  ---------------- -----------------
Benefit obligation at end of year                                      $6,010            $5,110
                                                                  ================ =================



Change in Plan Assets                                                   2004             2003
                                                                  ----------------- ----------------
Fair value of plan assets at beginning of year                         $4,101            $2,483
Actual return on plan assets                                              541               632
Employer contribution                                                   1,441             1,032
Benefits paid                                                            (368)              (46)
                                                                  ---------------- -----------------
Fair value of plan assets at end of year                               $5,715            $4,101
                                                                  ================ =================



Reconciliation of Funded Status                                         2004             2003
                                                                  ----------------- ----------------
Funded status                                                          $ (295)          $(1,009)
Unrecognized net actuarial loss                                           841               966
Unrecognized prior service cost                                            25                37
                                                                  ---------------- -----------------
Prepaid / (Accrued) benefit cost                                         $571               $(6)
                                                                  ================ =================


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

                                                                       2004              2003
                                                                  ---------------- -----------------

              Prepaid benefit cost                                     $1,083           $    --
              Accrued benefit cost                                       (686)           (1,005)
              Intangible assets                                             --                --
              Accumulated other comprehensive income                      174               999
                                                                  ---------------- -----------------
              Net amount recognized                                    $  571           $   (6)
                                                                  ================ =================
</TABLE>



                                      F-27
<PAGE>


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

<TABLE>
<CAPTION>

                                                                              2004              2003
                                                                         ----------------------------------

<S>                                                                          <C>              <C>
              Projected benefit obligation                                   $6,010           $5,110

              Accumulated benefit obligation                                 $6,010           $5,099

              Fair value of plan assets                                      $5,715           $4,101

         Additional Information (thousands of dollars):

                                                                              2004              2003
                                                                         ----------------------------------
         (Decrease) / Increase in minimum liability included                 $ (825)             $56
         in other comprehensive income

</TABLE>



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

<TABLE>
<CAPTION>

                                                                              2004         2003
                                                                         ------------ ------------
<S>                                                                           <C>          <C>
              Discount rate                                                   5.75%        6.00%

              Rate of compensation increase                                   4.00%        4.00%

</TABLE>


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

<TABLE>
<CAPTION>

                                                                              2004              2003         2002
                                                                         ------------------------------------------

<S>                                                                            <C>              <C>          <C>
              Discount rate                                                    6.00%            6.50%        7.00%

              Expected long-term return on plan assets                         8.00%            8.00%        9.00%

              Rate of compensation increase                                    4.00%            4.00%        4.50%
</TABLE>


         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.


                                      F-28
<PAGE>


         The following table summarizes the expected future benefit payments
over the next five years and aggregate five years thereafter (thousands of
dollars):

                                               Benefit
                            Year               payments
                     ----------------------------------------
                            2005                 $271
                            2006                 $488
                            2007                 $343
                            2008                 $602
                            2009                 $723
                          2010-2014             $4,851

         Plan Assets

         The following table sets forth the Partnership's pension plans weighted
average asset allocations at December 31, 2004 and December 31, 2003.


              Asset Category                           2004         2003
              ---------------------------------------------------------------

              U.S. Equities                              45%          45%

              International Equities                     10%          11%

              Real Estate                                 5%           5%

              U.S. Fixed Income                          37%          37%

              Other                                       3%           2%

         The Partnership'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                           2004         2003
              ---------------------------------------------------------------

              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 Partnership expects to contribute $0.8 million to its pension plan
in 2005 and contributed $1.4 million in 2004.


                                      F-29
<PAGE>




                                    EXHIBITS

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


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

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

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

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

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

 4.4*     Form of Exchange Note.

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

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

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

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.




<PAGE>


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

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

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

14.1***   Code of Ethics.

12.2*     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.

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

    *     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.

    ***   Previously filed as an exhibit to the Partnership's Annual Report on
          Form 10-K for the year ended December 31, 2003.