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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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 ]
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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..................................................18
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........................................24
ITEM 6. SELECTED FINANCIAL DATA............................................24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS................................26
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. DISCLOSURE 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
INDEX TO FINANCIAL STATEMENTS................................................F-1
i
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
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o dependence on availability of Western Canada natural gas reserves
and the continued availability of gas transportation from Western
Canada to the Partnership's pipeline through the TransCanada
PipeLines Limited System.
Certain of these factors are discussed in more detail elsewhere, including,
without limitation, under the captions "Business-Risk Factors," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." Other matters set forth in this annual report may also cause actual
results in the future to differ materially from those described in the
forward-looking statements. The Partnership does not intend to update or revise,
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:
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Percentage
Ownership
Ultimate Parent of Partner Name of Partner Interest
-------------------------- --------------- ----------
TransCanada PipeLines TransCanada Iroquois Ltd. 29.0%
Limited TCPL Northeast Ltd. 11.96%
KeySpan Corporation NorthEast Transmission 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
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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.
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
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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-
(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
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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.
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;
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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 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 6 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
7
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 6 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 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
8
charges, construction of new facilities, extension or abandonment of service and
facilities, accounts and records, depreciation and amortization policies, the
acquisition and disposition of facilities, the initiation and discontinuation of
services, and certain other matters. The Partnership, where required, holds
certificates of public convenience and necessity issued by the FERC covering its
facilities, activities and services.
The Partnership's rates and charges for transportation in interstate
commerce are subject to regulation by the FERC. FERC regulations and the
Partnership's FERC-approved tariff allow the Partnership to establish and
collect rates designed to give it an opportunity to recover all actually and
prudently incurred operations and maintenance costs of its pipeline system,
including taxes, interest, depreciation and amortization and a regulated equity
return. The FERC has granted the Partnership the authority to negotiate rates
with its current and potential shippers. The flexibility of such rates will
allow the Partnership to respond to market conditions, as well as permit the
Partnership to negotiate rates or a rate formula that will meet the specific
needs of individual shippers. This ability to negotiate rates will be an
important tool in attracting the growing electric generation market to the
Partnership's pipeline system.
Except in the limited context of negotiated rates, the rates the
Partnership charges may not exceed the just and reasonable rates approved by the
FERC. In addition, the Partnership is prohibited from granting any undue
preference to any person, or maintaining any unreasonable difference in its
rates or terms and conditions of service.
In general, there are two methods available for changing the rate
charged to shippers, provided that the transportation service contracts do not
bar such changes. Under Section 4 of the Natural Gas Act and applicable FERC
regulations, a pipeline may voluntarily seek a change, generally by providing at
least 30 days' prior notice to the FERC of the proposed changes and filing the
appropriate rate change application. If the FERC determines that a proposed rate
change may not be just and reasonable as required by the Natural Gas Act, then
the FERC may suspend the rate change for up to five months and set the matter
for an investigation. Subsequent to any suspension ordered by the FERC, the
proposed change may be placed in effect by the pipeline pending final FERC
review. If the pipeline chooses to do this, any increase reflected in the
proposed changes will, in the ordinary course of events, be collected subject to
refund. It is also possible that a pipeline seeking to increase the rates it
charges its shippers pursuant to a rate change application under Section 4 of
the Natural Gas Act may, after review by the FERC, have its rates reduced by the
FERC instead. Under Section 5 of the Natural Gas Act, on its own motion or based
on a complaint filed by a customer of a pipeline or other interested person, the
FERC may initiate a proceeding seeking to compel a pipeline to change any rate
or term or condition of service which is on file. If the FERC determines that an
existing rate or condition is unjust, unreasonable, unduly discriminatory or
preferential then any rate reduction or change in service term or condition
which is ordered at the conclusion of such a proceeding is generally effective
prospectively from the date of the order requiring such change.
The nature and degree of regulation of natural gas companies have
changed significantly during the past 10 years, and there is no assurance that
further substantial changes will not occur or that existing policies and rules
will not be applied in a new or different manner, particularly in light of the
FERC's decision to seek comments on its negotiated rate policies from companies
in the natural gas industry.
9
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
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
10
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) 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.
11
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 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
12
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:
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
13
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.
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 6 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
14
"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 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
15
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.
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 6 to the Consolidated Financial Statements.
16
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;
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.
17
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 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
18
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.
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
19
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 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
20
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 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
21
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.
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
22
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 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.
23
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 6 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.
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, independent
public accountants.
Year ended December 31,
-----------------------------------------------------------
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
24
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
======== ======== ======== ======== ========
Cash Flow Data:
Net cash from operating
activities....................... $59,359 $75,046 $ 68,782 $ 77,265 $ 57,181
Capital expenditures................. $22,088 $153,100 $109,433 $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
- ---------------------------------
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.
25
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.
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
26
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 (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 6 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:
27
Year ended
December 31,
----------------------------
Revenues and Volumes Transported
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.
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 Quantity in
Term in Years 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
28
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 $136.3 million 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 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
29
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.
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.
30
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.
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.
31
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.
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 3 to the Consolidated Financial
Statements.
Allowance for borrowed funds used during construction increased $5.8
million to $8.5 million for 2003 as compared to 2002 primarily due to the
Partnership's expenditures for the Eastchester Extension.
Income Taxes
Provision for taxes decreased $3.4 million in 2004 compared to 2003 due
primarily to a decrease in taxable income.
32
Provision for taxes increased $4.5 million in 2003 compared to 2002 due
primarily to an increase in taxable income. Provision for taxes decreased $1.4
million in 2002 compared to 2001 due primarily to a decrease in taxable income.
Liquidity and Capital Resources
The Partnership's primary source of financing has been cash flow from
operations. The Partnership's ongoing operations will require the availability
of funds to service debt, fund working capital, and make capital expenditures on
the Partnership's existing facilities and expansion projects.
Net cash provided by operating activities decreased by $15.7 million to
$59.4 million in 2004 from $75.0 million in 2003 and increased by $6.2 million
to $75.0 million in 2003 from $68.8 million in 2002. The decrease in net cash
provided by operating activities from 2003 to 2004 was primarily attributable to
a decrease in pretax net income and the effect of changes in working capital due
to the Eastchester Extension project, partially offset by an increase in
depreciation expense, also 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.
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 $22.1 million, compared to $153.1
million in 2002, 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
33
$109.4 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.
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).
34
Payments Due by Period
Less than More than
Total 1 Year 1 to 3 Years 3 to 5 Years 5 Years
----- ------ ------------ ------------ -------
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
======== ======== ======== ======== ========
(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.
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.
35
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 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.
36
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 6 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
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of changes in value of a financial
instrument, derivative or non-derivative, caused by fluctuations in interest
rates and prices. The following discussion of the Partnership's risk management
activities includes forward-looking statements that involve risks and
uncertainties. Actual results could differ materially from those contemplated in
the forward-looking statements. The Partnership handles market risks in
accordance with established policies, which may include various derivative
transactions.
The financial instruments held or issued by the Partnership are for
purposes other than trading or speculation. The Partnership is exposed to risk
resulting from interest rate changes on its variable-rate debt. The Partnership
uses interest rate swap agreements to manage the risk of increases in certain
variable rate issues. It records amounts paid and received under those
agreements as adjustments to the interest expense of the specific debt issues.
The Partnership believes that there is no material market risk associated with
these agreements. See Note 3 to the Consolidated Financial Statements included
elsewhere in this annual report. As of December 31, 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-34 of this
report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. DISCLOSURE CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, the Partnership
carried out an evaluation, under the supervision and with the participation of
the Partnership's management, including the President and the Chief Financial
Officer, of the effectiveness of the Partnership's disclosure controls and
procedures. Based on this evaluation, the President and Chief Financial Officer
have concluded that the Partnership's disclosure controls and procedures (as
defined in Rule 15d-15 under the Securities Exchange Act of 1934) are designed
to ensure that information required to be disclosed by the Partnership in
reports that it files or submits under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported, within the time periods specified
in the SEC's rules and forms and that such information is accumulated and
38
communicated to the Partnership's management, including the President and the
Chief Financial Officer, as appropriate to allow timely decisions regarding
required disclosures.
Changes in Internal Controls
There have been no significant changes in the Partnership's internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of the evaluation referred to above.
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.
Name Age Position
---- --- --------
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
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
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.
Name Age Affiliate at Which Employed Partner Represented
---- --- --------------------------- -------------------
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.
40
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
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.
SUMMARY COMPENSATION TABLE
Annual Compensation
-------------------------------------------------
Other Annual All Other
Name and Compensation Compensation
Principal Position Year Salary ($) (1) Bonus ($) ($) (4) ($) (5)
------------------ ---- -------------- --------- ------- -------
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
- -----------------------------
(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: $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
42
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 40Plan, 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 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.
43
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.
PENSION PLAN TABLE
Years of Service
- --------------------------------------------------------------------------------
Remuneration 15 20 25 30 35
- --------------------------------------------------------------------------------
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
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
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:
General Limited
Partner Partner Total Partnership
Ultimate Parent Name of Partner Interest Interest Interest
- --------------- --------------- -------- -------- --------
TransCanada PipeLines TransCanada Iroquois Ltd. 29.0% -- 29.0%
Limited
TCPL Northeast Ltd. 11.96% -- 11.96%
KeySpan Corporation NorthEast Transmission Company 18.07% 1.33% 19.4%
Keyspan IGTS Corp. 1.0% -- 1.0%
45
General Limited
Partner Partner Total Partnership
Ultimate Parent Name of Partner Interest Interest Interest
- --------------- --------------- -------- -------- --------
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
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
46
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.
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.
47
3.2* First Amendment to Amended and Restated Limited Partnership Agreement
of the Partnership dated as of January 27, 1999 among the partners of
the Partnership.
4.1* Indenture dated as of May 30, 2000 between the Partnership and the
Chase Manhattan Bank, as trustee (the "Trustee") for $200,000,000
aggregate principal amount of 8.68% senior notes due 2010.
4.2** Second Supplemental Indenture dated as of August 13, 2002 between the
Partnership and JPMorgan Chase Bank (formerly known as the Chase
Manhattan Bank), as trustee, paying agent, securities registrar and
transfer agent for $170,000,000 aggregate principal amount of 6.10%
senior notes due 2027.
4.3* First Supplemental Indenture, dated as of May 30, 2000 between the
Partnership and the Trustee for $200,000,000 aggregate principal
amount of 8.68% senior notes due 2010.
4.4* Form of Exchange Note.
4.5* Exchange and Registration Rights Agreement dated as of May 30, 2000
among the Partnership and the Initial Purchasers for $200,000,000
aggregate principal amount of 8.68% senior notes due 2010.
10.1* Credit Agreement among the Partnership, The Chase Manhattan Bank, as
administrative agent, Bank of Montreal, as syndication agent and
Fleet National Bank, as documentation agent, and other financial
institutions, dated May 30, 2000.
10.2** Amendment No. 1 to Credit Agreement, dated as of July 30, 2002,
among the Partnership, the several banks and other financial
institutions from time to time party thereto, and JPMorgan Chase Bank
(formerly known as the Chase Manhattan Bank), as administrative
agent.
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.
48
10.9* Performance Share Unit Plan of Iroquois Pipeline Operating Company
effective as of January 1, 1999.
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
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
IROQUOIS GAS TRANSMISSION SYSTEM, L.P., as Registrant
By: Iroquois Pipeline Operating Company, its Agent
Date: March 31, 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 March 31, 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
/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
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-5
Consolidated Statements of Cash Flows for the years ended December 31,
2004, 2003 and 2002.................................................F-8
Statements of Changes in Partners' Equity for the years ended December 31,
2004, 2003 and 2002 ...............................................F-10
Notes to Financial Statements............................................F-11
F-1
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.
PricewaterhouseCoopers LLP
Boston, Massachusetts
February 1, 2005
F-2
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(thousands of dollars)
FOR YEAR ENDED DECEMBER 31 2004 2003 2002
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
--------- --------- ---------
F-3
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
========= ========= =========
The accompanying notes are an integral part of these financial statements.
F-4
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED BALANCE SHEETS
ASSETS (thousands of dollars)
AT DECEMBER 31 2004 2003
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
----------- -----------
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
=========== ===========
The accompanying notes are an integral part of these financial statements.
F-5
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND PARTNERS' EQUITY (thousands of dollars)
AT DECEMBER 31 2004 2003
CURRENT LIABILITIES:
Accounts payable $ 9,454 $ 21,424
Accrued interest 4,674 4,626
Current portion of long-term debt (Note 3) 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 3) 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
--------- ---------
F-6
COMMITMENTS AND CONTINGENCIES (NOTE 6)
TOTAL LIABILITIES 500,046 536,062
--------- ---------
PARTNERS' EQUITY 343,821 312,643
--------- ---------
TOTAL LIABILITIES AND
PARTNERS' EQUITY $ 843,867 $ 848,705
========= =========
The accompanying notes are an integral part of these financial statements.
F-7
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
FOR THE YEARS ENDED DECEMBER 31 2004 2003 2002
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)
Other current assets (1,749) (272) (476)
Accounts payable (11,970) 4,721 9,048
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: 59,359 75,046 68,782
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (22,088) (153,100) (109,433)
--------- --------- ---------
NET CASH USED FOR INVESTING ACTIVITIES (22,088) (153,100) (109,433)
--------- --------- ---------
F-8
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
========= ========= =========
The accompanying notes are an integral part of these financial statements.
F-9
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
STATEMENT OF CHANGES IN PARTNERS' EQUITY
(thousands of dollars)
Accumulated
Taxes Equity Equity Other Total
Net Payable Distributions Contributions Comprehensive Partners'
Income by Partners to Partners by Partners Income/(Loss) Equity
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, net of tax (1,569) (1,569)
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, net of tax 838 838
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, net of tax 1,440 1,440
Balance at December 31, 2004 $ 345,277 $ 225,780 $ (505,544) $ 279,381 $ (1,073) $ 343,821
======================================================================================
F-10
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
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.
F-11
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.
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.
F-12
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.
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.
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
F-13
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):
Year end December 31, 2004 2003
--------------------- ---- ----
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
------- -------
F-14
NOTE 3
LONG TERM DEBT:
Detailed information on long-term debt is as follows:
December 31,
2004 2003
---- ----
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
-------- --------
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.
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
F-15
NOTE 4
CONCENTRATIONS OF CREDIT RISK:
The Partnership's cash and temporary cash investments and trade
accounts receivable represent concentrations of credit risk. Management believes
that the credit risk associated with cash and temporary cash investments is
mitigated by its practice of limiting its investments primarily to commercial
paper rated P-1 or higher by Moody's Investors Services and A-1 or higher by
Standard and Poor's, and its cash deposits to large, highly-rated financial
institutions. Management also believes that the credit risk associated with
trade accounts receivable is mitigated by the restrictive terms of the FERC gas
tariff that require customers to pay for service within 20 days after the end of
the month of service delivery.
NOTE 5
FAIR VALUE OF FINANCIAL INSTRUMENTS:
The fair value amounts disclosed below have been reported to meet the
disclosure requirements of SFAS No. 107, "Disclosures About Fair Values of
Financial Instruments" and are not necessarily indicative of the amounts that
the 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-16
NOTE 6
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-17
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.
F-18
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 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.
F-19
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 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.
F-20
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 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
F-21
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 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
F-22
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 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
F-23
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.
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.
F-24
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 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
F-25
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 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 7
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.
F-26
Total income tax expense includes the following components (thousands
of dollars):
U.S.
2004 Federal State Total
====================================================================
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
======== ====== ========
U.S.
2002 Federal State Total
====================================================================
Current $ 4,007 $1,954 $ 5,961
Deferred 10,070 880 10,950
-------- ------ --------
Total $14,077 $2,834 $16,911
======== ====== ========
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):
F-27
2004 2003 2002
================================================================================
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 51 47 (51)
expenses
Alternative minimum tax credit 262 1,025 (585)
Other 81 4,089 (314)
------- ------- -------
Total deferred taxes $36,174 $16,771 $10,950
======= ======= =======
The components of the net deferred tax liability are as follows
(thousands of dollars):
At December 31, 2004 2003
================================================================================
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)
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)
========= =========
F-28
NOTE 8
RELATED PARTY TRANSACTIONS:
Operating revenues and amounts due from related parties were primarily
for gas transportation services. Amounts due from related parties are shown
below net of payables, if any.
The following table summarizes the Partnership's related party
transactions (millions of dollars):
Payments Due (to)/from Revenue
to Related Related from Related
2004 Parties Parties Parties
---------------------------------------------------------------------------------
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
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
===== ====== =====
F-29
NOTE 9
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):
2004 2003 2002
--------------------------------------------------------------------
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) $ --
==== ==== ====
F-30
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):
Change in Benefit Obligation 2004 2003
---------------------
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)
====== ======
F-31
Information for pension plans with an accumulated benefit obligation in
excess of plan assets (thousands of dollars):
2004 2003
---------------------
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 in other comprehensive income $(825) $56
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):
2004 2003
---------------------
Discount rate 5.75% 6.00%
Rate of compensation increase 4.00% 4.00%
The following table summarizes the weighted average assumptions used to
determine the net periodic benefit cost for years ended December 31 (rates shown
are rates at beginning of measurement period):
2004 2003 2002
------------------------
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%
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-32
The following table summarizes the expected future benefit payments
over the next five years and aggregate five years thereafter (thousands of
dollars):
Year Benefit 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.
F-33
Contributions:
The Partnership expects to contribute $0.8 million to its pension plan in 2005
and contributed $1.4 million in 2004.
F-34
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.
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.