UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
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Commission File Number 333-42578
Iroquois Gas Transmission System, L.P.
(Exact name of registrant as specified in its charter)
Delaware 06-1285387
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
One Corporate Drive
Suite 600
Shelton, Connecticut 06484-6211
(Address of principal executive office)
(Zip Code)
(203) 925-7200 (Registrant's
telephone number, including area code)
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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 ]
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
Form 10-K Annual Report, for the year ended December 31, 2003
Table of Contents
Page
----
Special Note Regarding Forward-Looking Statements..............................1
PART I.
ITEM 1. BUSINESS..............................................................3
ITEM 2. PROPERTIES...........................................................19
ITEM 3. LEGAL PROCEEDINGS....................................................20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................23
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS..........................................23
ITEM 6. SELECTED FINANCIAL DATA..............................................23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS........................25
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK....................................................36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................36
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE..................................36
ITEM 9A. DISCLOSURE CONTROLS AND PROCEDURES...................................36
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP..................38
ITEM 11. EXECUTIVE COMPENSATION...............................................40
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT...........................................................46
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................46
PART IV.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES...............................46
i
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K..............................................48
INDEX TO FINANCIAL STATEMENTS................................................F-1
ii
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This annual report includes statements that are "forward-looking" (as
defined in the Private Securities Litigation Reform Act of 1995). These
forward-looking statements are based on the Partnership's current expectations
and projections about future events. Words such as "believes," "expects,"
"estimates," "may," "intends," "will," "should" or "anticipates" and similar
expressions or their negatives identify forward-looking statements. Examples of
forward-looking statements that are not historical in nature include those
regarding:
o trends and outlook in the natural gas transportation
industry and market;
o forecast of growth in natural gas demand and supply;
o the Partnership's competitiveness in the natural gas
transportation market;
o the Partnership's business and growth strategies, including
attracting new shippers and expanding its pipeline system to
add new markets not currently served by it;
o the effects of regulations; and
o anticipated future revenues, capital spending and financial
resources.
The forward-looking statements included in this annual report are subject to
risks and uncertainties that may cause the Partnership's actual results or
performance to differ from any future results or performance expressed or
implied by the forward-looking statements. These risks and uncertainties
include, among other things:
o competition and other factors that may affect the
Partnership's ability to maintain its contracts with its
existing shippers or acquire new shippers;
o inability to execute the Partnership's business strategy,
changes in the Partnership's business strategy or expansion
plans or inability to achieve its projections;
o regulatory, legislative and judicial developments,
particularly with respect to regulation by the Federal
Energy Regulatory Commission, or the FERC;
o the outcome of litigation to which the Partnership is a
party;
o dependence on shippers for revenues; and
o dependence on availability of Western Canada natural gas
reserves and the continued availability of gas
transportation from Western Canada to the Partnership's
pipeline through the TransCanada PipeLines Limited System.
2
Certain of these factors are discussed in more detail elsewhere, including,
without limitation, under the captions "Business-Risk Factors," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." Other matters set forth in this annual report may also cause actual
results in the future to differ materially from those described in the
forward-looking statements. The Partnership does not intend to update or revise
any forward-looking statements, whether as a result of new information, future
events or otherwise. In light of these risks, uncertainties and assumptions, the
forward-looking events discussed in this annual report might not occur.
PART I.
ITEM 1. BUSINESS
Introduction
Iroquois Gas Transmission System, L.P., or the Partnership, is a
Delaware limited partnership. It owns and operates a 412-mile interstate natural
gas transmission pipeline from the Canada-United States border near Waddington,
New York to South Commack, Long Island, New York including an approximate
36-mile mainline extension from Northport, New York through the Long Island
Sound to Hunts Point, New York. The Partnership provides service to local gas
distribution companies, electric utilities and electric power generators, as
well as marketers and other end-users, directly or indirectly, by connecting
with pipelines and interconnects throughout the northeastern United States. The
Partnership is exclusively a transporter of natural gas in interstate commerce
and operates under authority granted by the FERC. The Partnership was organized
in 1989 and commenced full operations in 1992, creating a link between markets
in the states of Connecticut, Massachusetts, New Hampshire, New Jersey, New York
and Rhode Island, and western Canada natural gas supplies. The Partnership's
pipeline system connects at four locations with three interstate pipelines and
also connects with the pipeline system of TransCanada PipeLines Limited (the
"TransCanada System") at the Canada-United States border near Waddington, New
York.
The Partnership provides transportation service to its shippers under
transportation service contracts, which provide for either firm reserved service
or interruptible service. Firm reserved transportation service contracts are
either long-term, multi-year contracts or short-term contracts of less than one
year. Under firm reserved transportation contracts, a certain amount of the
Partnership's pipeline system's capacity is reserved for the use of a shipper.
Under interruptible transportation service contracts, a shipper's access to the
Partnership's pipeline system depends upon the availability of pipeline system
capacity on any given day. As of December 31, 2003, the Partnership had 35
shippers with long-term firm reserved transportation service contracts for 1,113
thousands of dekatherms per day. As of December 31, 2003, approximately 82% of
the Partnership's subscribed pipeline capacity was contracted under firm
reserved transportation service contracts that continue through at least
November 1, 2011.
The partners and their respective interests in the Partnership are as
follows:
3
Percentage
Ownership
Ultimate Parent of Partner Name of Partner Interest
-------------------------- --------------- --------
TransCanada PipeLines TransCanada Iroquois Ltd. 29.0%
Limited TCPL Northeast Ltd. 11.96%
KeySpan Corporation NorthEast Transmission 19.4%
Company
KeySpan IGTS Corp. 1.0%
Dominion Resources, Inc. Dominion Iroquois, Inc. 24.72%
National Energy & Gas JMC-Iroquois, Inc. 4.93%
Transmission, Inc. Iroquois Pipeline Investment, LLC 0.84%
Energy East Corporation TEN Transmission Company 4.87%
New Jersey Resources NJNR Pipeline Company 3.28%
Corporation
Iroquois Pipeline Operating Company, or IPOC, a wholly owned
subsidiary of the Partnership, is the operator of the Partnership's pipeline
system and is responsible for the day-to-day management of the pipeline system
pursuant to an operating agreement entered into between the Partnership and IPOC
on January 10, 1989, as amended and restated on February 28, 1997, that expires
on November 11, 2011 and renews on a yearly basis thereafter.
Description of the Pipeline
Pipeline Facilities. The Partnership's pipeline system extends 412
miles from the Canada-United States border near Waddington, New York to South
Commack, Long Island, New York and includes the recently completed
Eastchester/New York City expansion of its pipeline system, consisting of an
approximate 36-mile mainline extension, referred to as the Eastchester
Extension, running from the mainline on Long Island near Northport, New York,
through the Long Island Sound to Hunts Point, New York. The pipeline system
offers access to natural gas supplies in Western Canada to local gas
distribution companies, electric utilities, electric power generators and
natural gas marketers operating in the New York and New England power grids.
Compressor Stations. Compressor stations increase the pressure of
natural gas flowing through the Partnership's pipeline system, increasing its
capacity and the volume of natural gas that can be shipped under contract. In
May 1992, the FERC approved construction of the Partnership's first compressor
station located in Wright, New York. This station went into service in November
1993 and by that year-end, the volumes under contract had increased to 648.6
MDth/d. A second compressor station, in Croghan, New York, was commissioned in
December 1994, expanding firm reserved service to 758.9 MDth/d. The
Partnership's third compressor station, located in Athens, New York, commenced
operation on November 1, 1998. Also as part of the Eastchester Extension, the
Partnership added two new compressor stations at Boonville and Dover, New York,
additional compression at the existing Croghan and Wright
4
compressor station and cooling facilities at the Wright and Athens, New York
compressor stations. As of December 31, 2003, the Partnership had firm
reserved transportation contracts in place to deliver 1,113 MDth/d of natural
gas.
Metering Stations and Interconnects. The Partnership receives natural
gas from the TransCanada System at the Canada-United States border near
Waddington, New York and delivers gas in New York and Connecticut through meters
tied directly to end-user markets. The Partnership's pipeline system operates
and maintains a total of 21 delivery meters with a combined capacity of
approximately 6.3 MMDth/d. Each meter station consists of a separate control
building that contains gas measurement equipment and electrical and
instrumentation devices. The Partnership also delivers gas to the other major
natural gas pipelines in the Northeast through its interconnections at four
locations with three interstate pipelines and also connects with the TransCanada
System. The Partnership also has interconnections with the New York Facilities
System at South Commack, Long Island and Hunts Point, New York. The New York
Facilities System is a pipeline system owned and used by both Consolidated
Edison Company of New York, or Con Ed, and KeySpan Corporation.
Communications. The Partnership maintains 24-hour monitoring of its
pipeline system via a computerized data monitoring and control system known as
SCADA (supervisory control and data acquisition) that links all compressor
stations and maintenance bases with the Partnership's gas control center in
Shelton, Connecticut. Remote facilities along the pipeline route are accessed
with the use of multiple address radio communication links to a satellite
system, which allows the pipeline system to be operated remotely from the gas
control center.
Operations. The gas control center houses the gas management, control
and computer systems required to operate the pipeline system and dispatch gas. A
backup gas control center is located in Oxford, Connecticut. In the event that
neither of these control centers is available, the Partnership's entire pipeline
system can be monitored and operated from the Wright, New York compressor
station. The Partnership has operated the pipeline system with regular and
continuous maintenance since it commenced operations. Inspections and tests have
been performed at prescribed intervals to ensure the integrity of the system.
These include periodic corrosion surveys, testing of relief and over-pressure
devices and periodic aerial inspections of the right-of-way, all conforming to
the United States Department of Transportation regulations. Such actions have
allowed the Partnership to maintain high operational availability of its system,
in particular, its compressors. Availability is a measure of the overall
reliability of a compressor. During the last six years, the average availability
of the Partnership's compressor units has ranged from 95% to 99%. In addition,
because multiple compressor stations are operational, the system is capable of
achieving high levels of throughput even when one or more compressor units are
experiencing an outage.
Transportation Services and Shippers
The design capacity of the Partnership's mainline pipeline system is
subscribed under firm reserved transportation service contracts with 35
shippers. Under the firm reserved transportation service contracts, the pipeline
receives natural gas on behalf of shippers at designated receipt points and
transports the gas on a firm basis up to each shipper's maximum
5
daily quantity. As of December 31, 2003, approximately 82% of the subscribed
capacity of the Partnership's pipeline system was contractually committed
through at least November 1, 2011. The Partnership has also entered into several
short-term (less than one year) firm reserved transportation service contracts
and numerous interruptible transportation service contracts. Reservation and
variable fees are payable under firm reserved transportation service contracts
and depend on the volume of gas shipped and the zone within which the gas is
shipped. The Partnership's pipeline is currently divided into two zones: Zone
One covers the mainline from Waddington to Wright, New York and Zone Two covers
the territory from Wright, New York through Connecticut to South Commack, Long
Island, New York. The Partnership is also authorized by the FERC to enter into
"negotiated rate" contracts with shippers. To date, the Partnership has entered
into a limited number of negotiated rate contracts for short-term firm
transportation service.
The Partnership's shippers under firm transportation service contracts
consist of major electric and gas utility companies, marketers, gas producers
and independent electric generating companies. KeySpan Corporation and National
Energy & Gas Transmission, Inc. (f/k/a PG&E National Energy Group), through
their affiliates, each accounted for more than 10% of the Partnership's revenues
for the year ended December 31, 2003. Approximately 48% of the Partnership's
existing pipeline system firm reserved capacity was contracted to affiliates of
the Partnership's partners as of December 31, 2003.
As of the Eastchester Expansion in-service date of February 5, 2004,
six shippers had contracted for service on the expansion totaling 210 MDth/d.
Approximately 71% of this capacity is contracted through at least February 1,
2013. On January 2, 2004 the Partnership submitted a request to the FERC to
establish incremental rates for the Eastchester Expansion shippers and secondary
access rates for existing shippers to deliver at Hunts Point, New York. The new
rates were requested to take effect on February 2, 2004. The filing requested a
single incremental rate applied to delivery of gas to Eastchester shippers with
the cost borne entirely in the monthly demand charge and thereby eliminating a
commodity charge. Existing shippers could deliver gas to Hunts Point by paying a
charge up to the difference between the Eastchester Rate and their existing
rate. By order issued on January 30, 2004, the FERC accepted the rate filing
making the rates effective July 1, 2004 subject to refund and subject to the
outcome of hearings.
On April 8, 2003, in the Partnership's Docket No. RP03-304, the FERC
approved an incremental fuel charge for Eastchester shippers up to a limit of
4.5% of their receipt quantity. Fuel charged to Eastchester shippers may be up
to 4.5 times the rate charged to the Partnership's existing shippers and will
apply to the Eastchester contracts regardless of the delivery point selected and
to existing shippers who choose to deliver gas to Hunts Point, New York.
The Partnership's FERC-approved tariff provides that, subject to
certain exceptions, the Partnership has the right to require that firm
transportation shippers have an investment grade rating or obtain a written
shipper guarantee from a third party with an investment grade rating. During
2003 and 2002, the energy industry, which includes the Partnership's firm
transportation shippers, experienced significant credit and liquidity issues and
credit rating agency downgrades. As of December 31, 2003, the weighted average
credit rating of the Partnership's shippers which are rated or have parental
guarantees or letters of credit in place, representing 88.8% of the
6
pipeline system's contracted capacity, was A3 (based on Moody's Investor
Services) and A- (based on Standard and Poor's (S&P)). The weighted average
credit rating of all shippers, including those who have made other credit
support arrangements that the Partnership finds satisfactory, was A3 (Moody's)
and BBB+ (S&P). The weighted average credit rating was determined by converting
the S&P and Moody's ratings into internal numerical ratings ranging from 1 to
22, with 1 being equivalent to AAA/Aaa by S&P and Moody's and 22 being D or
Default by S&P and Moody's. For purposes of this analysis, those non-rated
shippers who have made other credit support arrangements were either assigned an
assumed investment grade rating, or the ratings of their parent were used.
Demand for Transportation Capacity
The Partnership's market, the northeastern United States, is comprised
of approximately 12 million natural gas customers, who account for approximately
19% of all natural gas customers in the United States. The northeastern United
States has experienced an overall increase in natural gas demand in the last
decade. The Partnership expects this demand to continue to grow by 2-3% per year
through 2025. The bulk of the growth in the northeastern United States is
expected to occur in the electric generation sector.
The Partnership's long-term financial condition is dependent on the
continued availability of competitively priced western Canadian natural gas for
import into the United States. Natural gas reserves may require significant
capital expenditures by others for exploration and development drilling and the
installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered. The Western
Canada Sedimentary Basin is currently, and is expected to remain, the primary
source of natural gas for the Partnership's pipeline system. Sable Island and
other natural gas discoveries offshore of Nova Scotia may also provide
additional gas supplies in the future. Advances in technology may increase the
ultimate recoverable reserves from the Western Canada Sedimentary Basin and
offshore basins and bring gas supplies on stream that are currently not
economical to produce.
A variety of factors could affect the demand for natural gas in the
markets that the Partnership's pipeline system serves. These factors include:
o economic conditions;
o fuel conservation measures;
o competition from alternative energy sources;
o climatic conditions;
o legislation or governmental regulations; and
o technological advances in fuel economy and energy generation
devices.
The Partnership cannot predict whether these or other factors will have an
adverse effect on demand for use of the pipeline system or how significant that
adverse effect could be.
7
In February 2004, the Partnership concluded construction of the
Eastchester Extension. The new line, located primarily in the Long Island Sound
and progressing down the East River, proceeds on land for approximately 4,000
feet, connecting with the northern section of the gas distribution facilities of
the Consolidated Edison Company of New York, or ConEd. Under precedent
agreements, which contained conditions that had to be satisfied before a
contract for firm transportation service was signed, five project shippers
agreed to subscribe for all of the Eastchester Extension's 230 MDth/d of
transportation capacity. On December 26, 2001, the FERC issued a certificate
authorizing the Partnership to construct and operate the Eastchester Extension.
On January 25, 2002, the Partnership accepted the terms of the certificate. A
condition in the December 26 order required that, prior to commencing
construction, the project shippers execute firm service agreements with 10-year
terms for the entire 230 MDth/d of transportation capacity proposed to be built.
This condition was based on the precedent agreements with the five project
shippers. However, as a result of uncertainty and a slowdown in the energy
market, exacerbated by various bankruptcy proceedings and the resulting
examination, both internal and external, of the financial health of a variety of
other energy market participants, certain Eastchester shippers that were
obligated under the precedent agreements to execute firm transportation service
agreements failed to do so. On February 28, 2002, the Partnership filed a
request with the FERC to commence construction even if service contracts for the
full 230 MDth/d of service had not been executed. On March 13, 2002, the FERC
granted the Partnership's request. As a result, the Partnership did not have
executed contracts for 100% of the total project capacity prior to commencing
construction of the Eastchester Extension. To date, the Partnership has
contracted with shippers for 210 MDth/d of transportation services in connection
with the Eastchester Extension.
Construction of the portion of the Eastchester Extension located in
the Long Island Sound commenced in October 2002. However, as a result of delays
in obtaining certain construction authorizations and permits, and delays related
to construction incidents, the in-service date of the completed Eastchester
Extension was February 5, 2004, and the Partnership's management believes that
the final construction costs will be approximately $334 million, rather than the
$210.0 million estimated during the FERC certification process, and will likely
reduce the Partnership's initial margins that were anticipated when the project
application was filed with the FERC.
Initial Eastchester throughput for the full month of February 2004
averaged 44 MDth/d or 21% of the contracted capacity, although full demand
charges are being paid by the shippers. The Partnership believes this initial
percentage is due to the February 5 in-service date of the project and the
incremental fuel assessed to the Eastchester contracts. Capacity utilization
will likely be somewhat seasonal and will increase when the New York City prices
are high enough to offset the higher cost of fuel. Utilization should increase
over time as market demand grows.
On November 8, 2001, the Partnership filed an application with the
FERC to construct and operate a second compressor unit at the Partnership's
existing Athens, New York compressor station. The Athens Project is designed to
provide up to 70 MDth/d of firm transportation services to Athens Generating
Company, L.P., with whom the Partnership has executed a firm transportation
agreement for this service. On June 3, 2002, the FERC issued a certificate
authorizing the Partnership to construct the Athens Project. However, the
Partnership anticipates that it will have adequate capacity to serve the initial
70 MDth/d transportation needs
8
of Athens Generating. On May 14, 2003, the Partnership applied for and received
from the FERC a deferral of the completion of construction until December 3,
2004. Athens Generating is owned by Gen Holdings I, LLC, a subsidiary of
National Energy & Gas Transmission, Inc. (NEGT). On January 16, 2003, NEGT
announced that it had agreed to cooperate with any reasonable proposal by its
lenders regarding the disposition of certain of its generating assets, including
Athens Generating, in connection with defaults under various debt agreements.
The Partnership is awaiting further developments in connection with the
announcement. (See Note 7 to the Consolidated Financial Statements.)
On November 20, 2001, the Partnership filed an application to
construct and operate a new compressor station to be located in Brookfield,
Connecticut. This facility is designed to provide up to 85 MDth/d of firm
transportation service to southern Long Island and the New York City area. The
Partnership would provide firm transportation service to shippers with whom it
has executed precedent agreements. On October 31, 2002, the FERC issued a
certificate authorizing the construction of the Brookfield Project. On December
2, 2002, the Partnership filed a request for clarification or re-hearing with
respect to the fuel rate that would be paid by shippers using the Brookfield
Project facilities. On February 3, 2003, the FERC issued an order stating that
all shippers using the Eastchester Facilities, including Brookfield Project
shippers utilizing the Eastchester facilities, will be required to pay
incremental fuel costs.
Based on communications with its prospective customers regarding the
timing of their needs for new firm transportation service, the Partnership has
determined that a temporary deferral of the construction of the Brookfield
Project was necessary. On April 22, 2003, the Partnership requested an eighteen
month extension from the FERC to extend the construction completion time of the
Brookfield Project to October 31, 2005. On May 14, 2003, the FERC granted the
Partnership's request and extended the construction completion date to November
1, 2005. Both original Brookfield Project Shippers, PPL Energy Plus, LLC and
Astoria Energy LLC have terminated their precedent agreements with the
Partnership. For additional information, see Note 7 to the Consolidated
Financial Statements included elsewhere in this annual report.
Competition
The Partnership faces varying degrees of competition from other major
pipeline systems in the Northeast and alternative energy sources, including
electricity, coal, propane and fuel oils. Additionally, in recent years, the
FERC has issued orders designed to increase competition in the natural gas
industry. These orders have resulted in pipelines competing with their
customers, who are now allowed to resell their unused firm reserved
transportation capacity to other shippers. Firm reserved transportation
contracts traditionally had terms of 10 to 20 years; however, due to increased
competition, new firm reserved transportation contracts are usually of a shorter
duration.
FERC Regulation and Tariff Structure
General. The Partnership is subject to extensive regulation by the
FERC as a "natural gas company" under the Natural Gas Act of 1938 (the "Natural
Gas Act"). Under the Natural Gas Act and the Natural Gas Policy Act of 1978, the
FERC has jurisdiction over the Partnership
9
with respect to virtually all aspects of its business, including transportation
of gas, rates and charges, construction of new facilities, extension or
abandonment of service and facilities, accounts and records, depreciation and
amortization policies, the acquisition and disposition of facilities, the
initiation and discontinuation of services, and certain other matters. The
Partnership, where required, holds certificates of public convenience and
necessity issued by the FERC covering its facilities, activities and services.
The Partnership's rates and charges for transportation in interstate
commerce are subject to regulation by the FERC. FERC regulations and the
Partnership's FERC-approved tariff allow the Partnership to establish and
collect rates designed to give it an opportunity to recover all actually and
prudently incurred operations and maintenance costs of its pipeline system,
including taxes, interest, depreciation and amortization and a regulated equity
return. The FERC has granted the Partnership the authority to negotiate rates
with its current and potential shippers. The flexibility of such rates will
allow the Partnership to respond to market conditions, as well as permit the
Partnership to negotiate rates or a rate formula that will meet the specific
needs of individual shippers. This ability to negotiate rates will be an
important tool in attracting the growing electric generation market to the
Partnership's pipeline system.
Except in the limited context of negotiated rates, the rates the
Partnership charges may not exceed the just and reasonable rates approved by the
FERC. In addition, the Partnership is prohibited from granting any undue
preference to any person, or maintaining any unreasonable difference in its
rates or terms and conditions of service.
In general, there are two methods available for changing the rate
charged to shippers, provided that the transportation service contracts do not
bar such changes. Under Section 4 of the Natural Gas Act and applicable FERC
regulations, a pipeline may voluntarily seek a change, generally by providing at
least 30 days' prior notice to the FERC of the proposed changes and filing the
appropriate rate change application. If the FERC determines that a proposed rate
change may not be just and reasonable as required by the Natural Gas Act, then
the FERC may suspend the rate change for up to five months and set the matter
for an investigation. Subsequent to any suspension ordered by the FERC, the
proposed change may be placed in effect by the pipeline pending final FERC
review. If the pipeline chooses to do this, any increase reflected in the
proposed changes will, in the ordinary course of events, be collected subject to
refund. It is also possible that a pipeline seeking to increase the rates it
charges its shippers pursuant to a rate change application under Section 4 of
the Natural Gas Act may, after review by the FERC, have its rates reduced by the
FERC instead. Under Section 5 of the Natural Gas Act, on its own motion or based
on a complaint filed by a customer of a pipeline or other interested person, the
FERC may initiate a proceeding seeking to compel a pipeline to change any rate
or term or condition of service which is on file. If the FERC determines that an
existing rate or condition is unjust, unreasonable, unduly discriminatory or
preferential then any rate reduction or change in service term or condition
which is ordered at the conclusion of such a proceeding is generally effective
prospectively from the date of the order requiring such change.
The nature and degree of regulation of natural gas companies have
changed significantly during the past 10 years, and there is no assurance that
further substantial changes will not occur or that existing policies and rules
will not be applied in a new or different manner, particularly in
10
light of the FERC's decision to seek comments on its negotiated rate policies
from companies in the natural gas industry.
Regulatory Proceedings. After extensive negotiations between the
Partnership, its customers and other interested parties, on August 29, 2003, the
Partnership filed with the FERC an offer of Stipulation and Settlement Agreement
in Docket No. RP03-589, which implements four scheduled reductions to the
Partnership's rates. The central objective of the negotiations was to extend the
principles underlying the Partnership's December 17, 1999 settlement in Docket
No. RP94-72, et al., which established the rates under which the Partnership
currently provides service. By order dated October 24, 2003, the FERC approved
the settlement. The principal elements of the settlement are:
o a reduction in maximum demand rates phased-in over a
four-year period that began on January 1, 2004;
o neither the settlement rates nor any principles underlying
the settlement apply to the Eastchester Extension, which was
certificated in Docket No. CP00-232-000;
o the ability of the Partnership to file a rate case under
Section 4 of the Natural Gas Act is limited to establishing
rates for the Eastchester Extension, while parties retain
all rights to challenge the Partnership's proposed
Eastchester rates. Additionally, the settlement provides
that the Partnership will establish, in a separate
proceeding, a maximum recourse tariff rate for
non-Eastchester shippers that use the Eastchester Extension.
Eastchester shippers would also pay the applicable
incremental fuel charge approved by the FERC in an
unpublished delegated letter order issued April 8, 2003 in
Docket No. RP03-304-000.
o a rate moratorium under which the Partnership may not file
an application to increase rates pursuant to the Natural Gas
Act prior to July 1, 2007, with any subsequent increase
effective no earlier than January 1, 2008. Further, no party
may file for reductions in rates pursuant to the Natural Gas
Act prior to March 1, 2007 or receive such reductions prior
to January 1, 2008 (the rate settlement contains certain
limited exceptions to the moratorium for tariff changes not
intended to effect changes in the Partnership's firm
reserved service quality or rates); and
o retention by the Partnership of revenues associated with new
volumes, facilities, services or classes of service added
during the term of the settlement.
The settlement establishes the Partnership's base tariff recourse
rates, or settlement rates, for the years 2004, 2005, 2006 and 2007. The
settlement rates reflect annual step-downs, which over the term of the
settlement will reduce the Partnership's transportation rates by approximately
13%, i.e., the 100% load factor interzone rate will be reduce from the existing
level of $0.4234 per Dth, to the January 1, 2007 level of $0.3700 per Dth, for a
total cumulative
11
reduction of $0.0534 per Dth. Based on 2004 long-term firm service contracts,
the settlement will result in reductions in revenues of $3.8 million in 2004,
$1.5 million in 2005, $1.0 million in 2006 and $2.5 million in 2007. Under the
settlement, the first step-down in rates becomes effective on July 1, 2004.
Eastchester Extension Rate Case filed with the FERC. The Partnership
received final approval and was issued a certificate to construct the
Eastchester Extension on December 26, 2001 in Docket No. CP00-232-000.
Construction on the extension was completed in late January 2004 and the project
commenced service on February 5, 2004. In anticipation of the in-service date,
on January 2, 2004, the Partnership submitted its rate filing pursuant to
Section 4 of the Natural Gas Act (NGA), 15 U.S.C. ss. 717c, and Part 154 (18
C.F.R. Part 154) of the regulations of the FERC.
The Partnership's rate filing, Docket No. RP04-136-000, establishes
incremental rates for the Eastchester Extension as well as resulting secondary
access rates for delivery to the Eastchester delivery point by existing
non-Eastchester shippers. The Partnership is proposing an Eastchester rate of
$0.8444 per Dth on a 100% load factor basis, which would increase annual
revenues from Eastchester service by $17.0 million based on a total cost of
service of $70.9 million. The proposed Eastchester rates were developed using a
base period consisting of 12 months of actual experience through September 30,
2003, as adjusted for known and measurable changes projected to occur during the
test period ending June 30, 2004. By order issued on January 30, 2004, the FERC
accepted the rate filing making the rates effective July 1, 2004 subject to
refund and subject to the outcome of hearings.
On February 17, 2004, a pre-hearing conference before the FERC
resulted in a procedural schedule outlining the various phases of the
Partnership's rate filing proceeding with an anticipated final order due by the
end of the second quarter of 2005.
Rulemaking on FERC's Regulation of Transportation Services. On
February 9, 2000, the FERC adopted its Order No. 637. Order No. 637 is intended
to increase efficiency as the market for natural gas continues to become more
open and competitive. As a result of Order No. 637, interstate pipelines have
greater flexibility in tailoring the firm reserved services they offer to
customers and customers have improved opportunities to resell their unused firm
reserved transportation service in the secondary market, thus potentially
enhancing the value of firm pipeline service to customers.
While Order No. 637 required some significant changes in the
functioning of the secondary market for firm capacity, its implementation has
not materially affected the level of revenues the Partnership receives. The
Partnership has incurred and may incur additional costs to modify its tariff and
information systems to allow it to comply with Order No. 637. However, these
expenditures have not been, and are not expected to be, material.
As required by Order No. 637, the Partnership filed pro forma tariff
sheets with the FERC. In response to various interim orders issued by the FERC,
the Partnership submitted numerous additional compliance filings in 2003, which
were ultimately accepted by the FERC.
12
Management believes all Order No. 637 requirements have been met. See Note 7 to
the Consolidated Financial Statements included elsewhere in this annual report.
Rulemaking on FERC's Standard of Conduct for Transportation Providers.
On November 25, 2003, the FERC issued Order No. 2004 in FERC Docket No. RM01-10.
According to the FERC, Order No. 2004 adopts new standards of conduct that apply
uniformly to interstate natural gas pipelines and public utilities and that
replace standards of conduct currently in effect. The standards of conduct are
designed to ensure that transmission providers do not provide preferential
access to service or information to affiliated entities. Under the schedule
adopted by the FERC, on February 9, 2004 the Partnership submitted its plan and
schedule for implementing Order No. 2004. By June 1, 2004 the Partnership will
post its revised standards of conduct on its internet website, identifying the
procedures established for implementing the FERC's requirements. Management does
not believe that the requirements of Order No. 2004 will have a material impact
on the Partnership.
Safety Regulations
The Partnership's operations are also subject to regulation by the
United States Department of Transportation under the Natural Gas Pipeline Safety
Act of 1969, as amended, or the NGPSA, relating to the design, installation,
testing, construction, operation and management of the Partnership's pipeline
system. The NGPSA requires any entity that owns or operates pipeline facilities
to comply with applicable safety standards, to establish and maintain inspection
and maintenance plans and to comply with such plans.
The NGPSA was amended by the Pipeline Safety Act of 1992 to require
the Department of Transportation's Office of Pipeline Safety to consider
protection of the environment when developing minimum pipeline safety
regulations. In addition, the amendments required the Department of
Transportation to issue pipeline regulations concerning, among other things, the
circumstances under which emergency flow restriction devices should be required,
training and qualification standards for personnel involved in maintenance and
operation, and requirements for periodic integrity inspections, including
periodic inspection of facilities in navigable waters which could pose a hazard
to navigation or public safety. The amendments also narrowed the scope of gas
pipeline exemptions pertaining to underground storage tanks under the Resource
Conservation and Recovery Act. The Partnership believes its operations comply in
all material respects with the NGPSA; however, the industry, including the
Partnership, could be required to incur additional capital expenditures and
increased costs depending upon regulations issued by the Department of
Transportation under the NGPSA and/or future pipeline safety legislation.
Environmental Matters
Environmental laws and regulations have changed substantially and
rapidly over the last 20 years, and the Partnership anticipates that there will
be continuing changes. Increasingly strict federal, state or local environmental
restrictions, limitations and regulations have resulted in increased operating
costs for the Partnership, and it is possible that the costs of compliance with
environmental laws and regulations will continue to increase. To the extent that
environmental costs are normal costs of doing business, these costs would be
recoverable under the Partnership's rates through future rate proceedings.
13
Current Operations. At each of the Partnership's five natural gas
compressor stations, IPOC routinely monitors environmental standards and
controls and, to date, IPOC has found that environmental permits and regulations
are being complied with in all material respects. Additionally, IPOC intends to
monitor environmental standards and controls at all new facilities.
Settlement of Federal and State Investigations. On May 23, 1996, as
part of a resolution of federal criminal and civil investigations of the
construction of certain of the Partnership's pipeline facilities, IPOC pled
guilty to four felony violations of the Clean Water Act and entered into consent
decrees under the Clean Water Act in four federal judicial districts. Although
not a named defendant, the Partnership signed the plea agreement and consent
decrees and is bound by their terms. The Partnership also entered into related
settlements with the State of New York, the FERC and the Department of
Transportation. Under these various agreements, the Partnership and IPOC agreed
to pay $22.0 million in fines and penalties and to take remedial measures. The
Partnership and IPOC are taking certain actions and adopting a number of
procedures to reduce their risk of noncompliance with environmental regulations
in the future. In August 1996, as a result of settlement of the federal
proceedings, IPOC was placed by the Environmental Protection Agency on a list
that excludes IPOC from federal financial and other assistance under federal
programs and limits IPOC's ability to do business with U.S. government agencies.
In the future, it is IPOC's intention to seek removal from this list. This has
not had, and the Partnership does not expect it to have, a material adverse
impact on the Partnership's business.
Employees
The Partnership does not directly employ its personnel. The
Partnership's personnel and services are provided by IPOC, its wholly owned
subsidiary, pursuant to the Partnership's operating agreement with IPOC. The
Partnership reimburses IPOC for all reasonable expenses incurred in operating
the Partnership's pipeline system including salaries and wages and related taxes
and benefits. As of December 31, 2003, IPOC had 123 employees.
Risk Factors
The Partnership's business involves significant risks and
uncertainties including those described below.
The Partnership may not be able to maintain its contracts with existing shippers
or enter into contracts with new shippers
As of December 31, 2003, approximately 82% of the subscribed capacity
of the Partnership's pipeline system was contracted through at least November 1,
2011. The Partnership cannot give any assurances that it will be able to extend
or replace these contracts at the end of their initial terms or that, if the
Partnership does extend or replace its existing firm reserved transportation
service contracts, it will be able to do so at the maximum rates that the FERC
will authorize it to charge. The extension or replacement of the existing
long-term contracts with the Partnership's shippers and its ability to enter
into similar contracts for the total increased capacity of its pipeline system
to be generated by its expansions depends on a number of factors beyond the
Partnership's control, including:
14
o the supply and price of natural gas in Canada and the United
States;
o competition to deliver gas to the Northeast from alternative
sources of supply;
o the demand for gas in the Northeast;
o whether transportation of gas pursuant to long-term
contracts continues to be market practice; and
o whether the Partnership's business strategy, including its
expansion strategy, is successful.
If the Partnership materially breaches its obligations under any
transportation service contract, the affected shipper may have various remedies,
including termination of its transportation service contract. The Partnership
cannot assure that it will be able to replace a contract terminated for breach
with a comparable contract. If these contracts are terminated or are not
extended or replaced with comparable contracts, or if the Partnership is unable
to secure contracts for all the capacity to be generated by its expansions, the
Partnership's cash flows and ability to service its outstanding senior notes may
be adversely affected.
The Partnership is dependent on the performance of its shippers
The Partnership is dependent upon shippers for revenues from
contracted transportation capacity on its pipeline system. The firm reserved
transportation service contracts obligate the shippers to pay reservation
charges regardless of whether or not they use their reserved capacity to
transport natural gas on the pipeline system, subject to limited rights in favor
of the shippers in certain circumstances to receive reservation charge credits.
As a result, the Partnership's profitability generally depends upon the
continued creditworthiness of the shippers rather than upon the amount of
natural gas transported. During 2002 and continuing in 2003, the energy
industry, which includes the Partnership's firm transportation shippers,
experienced significant credit and liquidity issues and credit rating agency
downgrades.
On July 8, 2003, PG&E Corporation reported that NEGT (f/k/a PG&E
National Energy Group) and a number of its subsidiaries filed voluntary
petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. These
subsidiaries include, PG&E Energy Trading Holdings Corporation, PG&E Energy
Trading-Gas Corporation, PG&E Energy Trading-Power Corporation, PG&E ET
Investments Corporation, and US Gen New England, Inc. (US Gen NE).
US Gen NE had two firm transportation service agreements with the
Partnership, one for 40,702 Dth/d which expires on November 1, 2013 and one for
12,000 Dth/d which expires on April 1, 2018. The total monthly demand charges
for both contracts was $0.5 million. On September 5, 2003, the bankruptcy court
authorized the rejection of US Gen NE's two firm transportation contracts. The
Partnership has remarketed a portion of the capacity on a short-term basis and
plans to continue to remarket and resell this capacity in the future. There can
be no assurance, however, that shippers will not default on their payment
obligations for transportation services provided in the future.
15
The Partnership's rates are calculated on the basis of an assumed
contracted capacity and its revenue projections assume that shippers will pay
these rates as required by their contracts. A prolonged economic downturn in the
energy industry or a broader economic downturn affecting the northeastern Unites
States could negatively affect the ability of some or all of the shippers to
fulfill their obligations under the transportation service contracts. A failure
to pay by any of its shippers, for any length of time during which the
Partnership does not succeed in obtaining a creditworthy replacement shipper
would decrease the Partnership's revenues and cash flows and could have an
adverse impact on the Partnership's ability to make payments on its outstanding
senior notes.
Changes in regulation and rates may adversely affect the Partnership's results
of operations
Because its pipeline system is an interstate natural gas pipeline, the
Partnership is subject to regulation as a "natural gas company" under the
Natural Gas Act of 1938, as amended, or the Natural Gas Act. The Natural Gas Act
makes the rates the Partnership can charge its shippers and other terms and
conditions of service subject to FERC review and the possibility of modification
in rate proceedings. Under the Natural Gas Act, the Partnership's rates must be
"just and reasonable," as determined by the FERC. In rate review proceedings,
the FERC has the responsibility to ensure that the rates that interstate
pipelines, such as the Partnership's, charge are not greater than those
necessary to enable the pipeline to recover the costs incurred to construct,
own, operate and maintain its pipeline system and to afford the pipeline an
opportunity to earn a reasonable rate of return. Under FERC regulations,
shippers have the opportunity to contest the Partnership's rates and tariff
structure. The Partnership cannot assure that the FERC will not alter or refine
its preferred methodology for establishing pipeline rates and tariff structure.
It is possible that changes in the FERC's ratemaking policies could result in
lower rates than those the Partnership could charge under the existing
methodology, or could make a large proportion of the Partnership's rate subject
to recovery on the basis of actual quantities of natural gas that the
Partnership transports, rather than on the basis of firm capacity reservations.
Such changes could therefore adversely affect the Partnership's revenues and
ability to service its senior notes.
Under the terms of the transportation service contracts and in
accordance with the FERC's rate making principles, the Partnership is only
permitted to recover costs associated with the construction and operation of its
pipeline system which are actually, reasonably and prudently incurred and are
included in its pipeline system's regulatory rate base. There can be no
assurance that all costs the Partnership incurs, including costs incurred in
constructing its expansions, will be recoverable through its rates.
A decline in the availability of Western Canadian natural gas may reduce
shippers' willingness to contract for capacity on the Partnership's pipeline
The Partnership's long-term financial condition is dependent on the
continued availability of Western Canadian natural gas for import into the
United States. If the availability of Western Canadian natural gas were to
decline over the initial term of the Partnership's current transportation
service contracts, if upstream transportation service on the TransCanada System
were to become constrained or if the price of Western Canada natural gas were to
increase significantly, existing shippers may not extend their contracts and the
Partnership may be unable
16
to find replacement sources of natural gas for the pipeline system's capacity.
The Partnership cannot give any assurances as to the availability of additional
sources of gas that can interconnect with its pipeline system.
Continued sales of Western Canadian natural gas to the United States
will also depend on:
o the level of exploration, drilling, reserves and production
of Western Canada Sedimentary Basin natural gas and the
price of such natural gas;
o the accessibility of Western Canada Sedimentary Basin
natural gas which may be affected by weather, natural
disaster or other impediments to access, including capacity
constraints on the TransCanada System;
o the price and quality of natural gas available from
alternative United States and Canadian sources and the rates
to transport Canadian natural gas to the United States
border; and
o the regulatory environments in the United States and Canada,
including the continued willingness of the governments of
both countries to permit the import to the United States of
natural gas from Canada on a basis that is commercially
acceptable to the Partnership's shippers and their
customers.
Failure of the pipeline system's operations may result in liabilities for the
Partnership and reduce its revenues or impair its ability to meet its
obligations under its senior notes
There are risks associated with the operation of a complex pipeline
system, such as operational hazards and unforeseen interruptions caused by
events beyond the Partnership's control. These include adverse weather
conditions, accidents, breakdown or failure of equipment or processes,
performance of the facilities below expected levels of capacity and efficiency
and catastrophic events such as explosions, fires, earthquakes, floods,
landslides or other similar events beyond the Partnership's control. Liabilities
incurred and interruptions to the operation of the pipeline caused by such
events could reduce revenues generated by the Partnership and increase the
Partnership's expenses and impair the Partnership's ability to meet its
obligations under the terms of its senior notes. Insurance proceeds may not be
adequate to cover all liabilities incurred, lost revenues or increased expenses.
Lawsuits against the Partnership could adversely affect its operating results
In the course of expanding its natural gas pipeline and related
facilities, the Partnership faces typical construction risks, including, but not
limited to, risks relating to the existence of sensitive property owned by third
parties and environmental and geological problems. In constructing the
Eastchester Extension, the Partnership faced particular risks associated with
the construction of a large, mainly underwater, pipeline. During construction,
certain undersea electric transmission cables owned by the Long Island Power
Authority and Connecticut Light and Power Company were allegedly damaged and/or
severed as a result of an allision with an
17
anchor deployed by the DSV Mr. Sonny, a work vessel owned and operated by a
subcontractor taking part in the construction of the Eastchester Extension.
Additionally, the Y-49 facility, which is a 600 megawatt undersea electrical
power interconnection between Westchester County and LIPA's transmission system
at Sands Point, New York, allegedly sustained damage causing a disruption of
power transmission over the line and leakage of dielectric fluid. NYPA alleges
that the damage was caused by an anchor of Horizon's pipeline lay barge, the
GULF HORIZON, which was in the vicinity of NYPA's cable and was involved in work
in the Eastchester Extension at the time of the casualty. As a result of these
incidents, litigation is currently pending against the Partnership. It is
unknown at this time whether there will be material adverse effects on the
Partnership's financial condition as a result of this litigation. For additional
information about this litigation, see "Item 3. Legal Proceedings" below. For a
description of additional legal proceedings in which the Partnership is
currently involved, see Note 7 to the Consolidated Financial Statements
appearing elsewhere in this annual report.
The Partnership may not succeed in its planned expansions
The Partnership's ability to engage in any expansion project will be
subject to, among other things, approval of its management committee,
restrictions under the indenture relating to the Partnership's senior notes and
numerous business, economic, regulatory, competitive and political uncertainties
beyond the Partnership's control. Therefore, the Partnership cannot guarantee
that any proposed expansion or extension project will be undertaken or, if
undertaken, will be successful.
The success of any planned expansions, once undertaken, may depend on
several factors, including, among others, the following:
o other existing pipelines may provide transportation services
to the area to which the Partnership is expanding;
o any entities, upon obtaining the proper regulatory
approvals, may construct new competing pipelines or increase
the capacity of existing competing pipelines;
o a competitor's new or upgraded pipeline could offer
transportation services that are more desirable to shippers
because of location, facilities or other factors;
o shippers may not be willing to sign long-term contracts for
service which would make use of a planned expansion; and
o laws and regulations, including permit requirements, may
become more stringent so as to affect materially the
viability of the expansions.
The Partnership would also require additional capital to fund any
planned expansions of its pipeline system. If the Partnership fails to generate
sufficient funds in the future, it may have to delay or abandon its expansion
plans, in which case it will lose the ability to capitalize
18
expenditures on such abandoned expansions. Also, a proposed expansion may cost
more than planned to complete and such excess costs may not be recoverable.
The Partnership is subject to laws relating to the protection of the environment
that could involve substantial compliance costs and liabilities
The Partnership's operations are subject to federal, state and local
laws and regulations relating to the protection of the environment and public
safety. Risks of substantial costs and liabilities are inherent in pipeline
operations and the Partnership cannot guarantee that significant costs and
liabilities will not be incurred under applicable environmental and safety laws
and regulations, including those relating to claims for damages to property and
persons resulting from the Partnership's pipeline system operations.
Moreover, it is possible that the development or discovery of other
facts or conditions, such as increasingly stringent changes to federal, state or
local environmental laws and regulations, and enforcement policies thereunder,
could result in increased costs and liabilities to the Partnership. The
Partnership is unable to predict the effect that any future changes in
environmental laws and regulations will have on its future earnings and it
cannot guarantee that environmental costs incurred by it will be recoverable
under its FERC-approved tariff.
ITEM 2. PROPERTIES
The Partnership's principal executive office is located in Shelton,
Connecticut in approximately 33,422 square feet of leased office space under a
lease agreement that expires on April 30, 2011. On December 19, 2003, the
Partnership exercised an option to cancel approximately 4,300 square feet of
that space through written notification to the landlord of the Shelton office
and by making a one-time payment to the landlord of approximately $50,000. The
cancellation of that portion of the lease will become effective on January 1,
2005. The Partnership also leases approximately 14,000 square feet of warehouse
and office space in Oxford, Connecticut under a lease agreement that expires on
March 31, 2006. The Partnership believes that its facilities are adequate for
its current operations and that additional leased space can be obtained if
needed.
The Partnership holds the right, title and interest to and in its
pipeline system. With respect to real property, the pipeline system falls into
two categories: (i) parcels which the Partnership owns, such as compressor
station and meter station sites; and (ii) parcels in which the Partnership has a
leasehold interest, easement or right-of-way from landowners permitting the use
of land for the construction and operation of the pipeline system. The
Partnership obtained the right to construct and operate its pipeline system
across certain property through negotiations and through the exercise of the
power of eminent domain, where necessary. The Partnership continues to have the
power of eminent domain in each of the states in which it operates its pipeline
system. The Partnership also leases a right-of-way easement on Long Island, New
York, which expires in 2030. The Partnership believes that it has satisfactory
interests in all of the properties making up its pipeline system.
19
ITEM 3. LEGAL PROCEEDINGS
On November 16, 2002, certain undersea electric transmission cables
owned by Long Island Lighting Company d/b/a The Long Island Power Authority, or
LIPA, and Connecticut Light and Power Company, or CL&P, were allegedly damaged
and/or severed when an anchor deployed by the DSV MR. SONNY, a work vessel
taking part in the construction of the Eastchester Extension, allegedly allided
with the cables. The MR. SONNY allegedly is owned by Cal Dive International,
Inc., a subcontractor of the Partnership's general contractor, Horizon Offshore
Contractors, Inc.
On December 6, 2002, Cal Dive commenced a maritime limitation of
liability action in the United States District Court for the Eastern District of
New York, seeking exoneration from or limitation of liability in respect of this
incident. LIPA, CL&P, the Partnership, Horizon, and Thales GeoSolutions Group,
Ltd. (another of Horizon's subcontractors), have all filed claims in the
limitation action. In addition, LIPA, CL&P and their subrogated underwriters
(the "Cable Interests") filed third-party claims against the Partnership and its
operating subsidiary, IPOC, as well as Horizon and Thales, seeking recovery for
its alleged losses. The Partnership filed cross claims against Horizon and
Thales for indemnification in respect of the Cable Interests' claims, and
Horizon filed a third-party claim against Thales. The Cable Interests
subsequently agreed to dismiss their claim against IPOC, but without prejudice
to their right to re-file that claim if they deem necessary.
The Cable Interests are claiming a total of $34.2 million in damages,
consisting of $14.4 million for repairs and repair related costs, including LIPA
and CL&P internal costs and overheads of $4.7 million, as well as $19.9 million
in consequential damages.
In addition to the foregoing, the Partnership has been advised that
the Town of Huntington, New York may assert a claim against the Partnership
alleging violations of certain municipal ordinances on the basis of a claim that
dielectric fluid was released from the cable as a result of the incident.
Under the terms of the construction contract between Horizon and the
Partnership, Horizon is obligated to indemnify the Partnership for Horizon's
negligence associated with the construction of the Eastchester Extension.
Horizon is also contractually responsible for its subcontractors' negligence. As
required by the contract, Horizon named the Partnership as an additional named
insured under Horizon's policies of insurance. The Partnership understands that
it is covered under Horizon's policies to the extent that Horizon has assumed
liability to the Partnership under the contract. Based on Horizon's subcontracts
with Thales and Cal Dive, the Partnership may also be entitled to coverage as an
additional insured party under those parties' policies of insurance. In
addition, Thales's underwriters have sent a letter to Thales, which was
forwarded to the Partnership's counsel on March 12, 2004, agreeing to indemnify
the Partnership in accordance with the indemnity provision in the Horizon/Thales
contract. This indemnity is subject to the policies' terms and limit of
$10,000,000.00. The details of this arrangement are being negotiated. In any
event, the Partnership believes it is adequately insured by its own insurers.
Therefore, based on its initial investigation, the Partnership's management
believes that this matter will not have a material adverse effect on the
Partnership's financial condition or results of operations.
20
On February 27, 2003, the New York Power Authority, or NYPA, informed
the Partnership that one of four cables that comprised its Y-49 facility, which
is a 600 megawatt undersea electrical power interconnection between Westchester
County and LIPA's transmission system at Sands Point, New York, allegedly
sustained damage causing a disruption of power transmission over the line and
leakage of dielectric fluid. NYPA alleges that the damage was caused by an
anchor of Horizon's pipeline lay barge, the GULF HORIZON, which was in the
vicinity of NYPA's cable and was involved in work in the Eastchester Extension
at the time of the casualty.
By letter dated March 25, 2003, counsel representing NYPA and LIPA
informed the Partnership that they intend to hold the Partnership, Horizon and
Horizon's subcontractor, Thales, jointly and severally liable for the full
extent of their damages, which they allege includes emergency response costs,
repair of the damaged electrical cable, loss of use and disruption of service,
and certain other as yet unspecified damages arising out of or relating to the
incident.
The Partnership is a party to an agreement with NYPA, which provides,
among other things, that the Partnership will indemnify NYPA for damage to the
Y-49 cables, which results from the Partnership's or its contractors'
negligence, acts, omissions or willful misconduct. Under the terms of the
construction contract between Horizon and the Partnership, Horizon is obligated
to indemnify the Partnership for Horizon's negligence associated with the
construction of the Eastchester Extension. Horizon is also contractually
responsible for its sub-contractor's negligence. Pursuant to the contract,
Horizon named the Partnership as an additional named insured under Horizon's
policies of insurance. The Partnership is still investigating whether Horizon's
insurance is adequate to cover the Partnership for its potential losses in this
matter. The Partnership may also be entitled to indemnity as an additional
insured under Thales' policies of insurance, although this matter is also still
subject to further investigation. The Partnership has placed Horizon and its
underwriters on notice that it intends to hold Horizon responsible. The
Partnership has further requested that Horizon assume its defense and hold it
harmless in respect of this claim; however, to date, Horizon has rejected this
request. The Partnership has also placed its own insurance underwriters on
notice and is currently investigating the applicability of all available
insurance coverages.
On August 15, 2003, Horizon commenced a maritime limitation of
liability action in the United States District Court for the Southern District
of Texas, Houston Division, captioned In the Matter of Horizon Vessels Inc., as
owner of the GULF HORIZON, seeking exoneration from or limitation of liability
in connection with this incident. NYPA and LIPA (collectively, the "Y-49 Cable
Interests") also have filed claims in the limitation action asserting total
damages of approximately $21 million. On November 12, 2003, the Partnership
filed an Answer in Horizon's action, requesting that the limitation of liability
action be dismissed and/or that the limitation injunction be lifted to permit
the Partnership to pursue its claims against Horizon in the forum of its choice,
or, in the alternative, that Horizon be denied limitation rights under the
Limitation Act. The Partnership also filed a claim in Horizon's limitation
action seeking indemnity for any liability it may be found to have to the Y-49
Cable Interests as a result of the NYPA cable incident as well as all losses
suffered by the Partnership as a result thereof, and, on a protective basis,
seeking full damages for Horizon's breaches and deficient performance under the
Partnership/Horizon construction contract, which claims are unrelated to the
NYPA cable
21
incident. Thales also has filed a claim in the Horizon limitation action seeking
indemnity for any liability it may be found to have to the Y-49 Cable Interests
or the Partnership. The Y-49 Cable Interests and the Partnership both have filed
motions to transfer the Texas action to the United States District Court for the
Eastern District of New York. Thales has joined in those motions. By order
entered February 27, 2004, the court denied the motions to transfer. However, in
doing so, the court confirmed that the Partnership could pursue its contract
claims against Horizon outside of the limitation action.
The Partnership is still in the process of investigating this incident
and evaluating its rights, obligations and responsibilities. Given the
preliminary stage of this matter, the Partnership is unable to assess the
likelihood of an unfavorable outcome and/or the amount or range of loss, if any,
in the event of an unfavorable outcome.
The Partnership has also learned that as part of the Eastchester
construction there may have been one or more violations by the contractor of the
exclusionary zones established around certain specified areas of possible
cultural resources, namely underwater archeological sites such as shipwrecks,
along the pipeline's marine route and the contractor may have placed anchors
outside the authorized construction corridor. At this time, the Partnership has
no information that any sites were in fact damaged and the Partnership's
investigation in this matter is ongoing. The Partnership has informed the FERC
and the New York State Office of Parks, Recreation and Historic Preservation of
this matter. At this time, the Partnership is unable to determine if there will
be any material adverse effect on the Partnership's financial condition and
results of operations due to this matter.
Eastchester-Horizon Suit
On January 20, 2004, Horizon filed a complaint against the Partnership
and IPOC in the Supreme Court of the State Of New York, New York County (Index
No. 04/600140). The complaint alleges that the Partnership wrongfully terminated
its agreement with Horizon to perform the Eastchester construction work in Long
Island Sound and that the Partnership committed other breaches of such agreement
in conjunction with the Eastchester construction work. The complaint seeks
damages in excess of $40.0 million. The Partnership is in the process of
preparing a rigorous defense to Horizon's claims; it has served an answer and
will file substantial claims in state and/or federal court against Horizon for
Horizon's actions during the Eastchester construction work. Given the
preliminary stage of this matter, the Partnership is unable at this time to
assess the likelihood of a favorable or unfavorable outcome and/or the amount or
range of recovery or loss, if any, resulting from Horizon's claims and the
Partnership's counterclaims.
Cal Dive International, Inc.
On March 1, 2004 and in a duplicate filing on March 9, 2004, Cal Dive
International, Inc. ("Cal Dive") filed a Mechanic's Lien totaling $3.3 million
in the offices of the Clerk of Bronx and Suffolk Counties, respectively. Cal
Dive was in privity with Horizon Offshore Contractors,
22
Inc. ("Horizon") and provided services to Horizon during the Eastchester
construction work. The Partnership instructed Horizon to address the lien notice
pursuant to its contractual obligations. The Partnership also demanded further
information from Cal Dive on the particulars of its lien. The Partnership does
not believe it owes Cal Dive any monies and plans to vigorously contest the
validity of the liens. Furthermore, the Partnership, in compliance with Section
6.2(c)(ii) of its Second Supplemental Indenture, dated August 13, 2003, intends
to post a bond to discharge the Mechanic's Lien.
Capobianco, A. vs. Iroquois Gas & Consolidated Edison Company of New York
On January 28, 2004, Anthony Capobianco filed a complaint against
Iroquois Gas Transmission System, L.P., Iroquois Pipeline Operating Company and
Consolidated Edison Company of New York in the Supreme Court of the State of New
York, New York County (Index No. 101366/04). The complaint alleges that Mr.
Capobianco, an employee of Hallen Construction Company, Inc. ("Hallen"),
sustained personal injuries resulting from an electrical current causing severe
electrical shock while performing his duties as part of the construction of the
Hunts Point segment of the Partnership's Eastchester project. Hallen was the
Partnership's contractor employed to construct that segment of the project. The
claim is asserted for damages in the amount of $10.0 million. The Partnership
has notified its insurance carriers and an answer has been filed to the
complaint. Given the preliminary nature of this matter, at this time, the
Partnership is unable to determine the likelihood of an unfavorable outcome
and/or the amount or range of loss, if any, in the event of an unfavorable
outcome.
The Partnership is a party to various other legal matters incidental
to its business. However, the Partnership believes that the outcome of these
proceedings will not have a material adverse effect on the Partnership's
financial condition or results of operations. See Note 7 to the Consolidated
Financial Statements appearing elsewhere in this annual report.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Partnership has not submitted any matters to the vote of its
security holders.
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Partnership does not have any publicly-traded common equity.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and with the Partnership's financial statements, including the notes
thereto, appearing elsewhere in this annual report. The income statement,
balance sheet and cash flow data for the years ended
23
December 31, 2003, 2002, 2001, 2000 and 1999 have been derived from the
Partnership's financial statements, which have been audited by
PricewaterhouseCoopers LLP, independent public accountants.
Year ended December 31,
------------------------------------------------------
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
(In thousands of dollars, except ratios)
Income Statement Data:
Operating revenues................... $132,009 $126,320 $128,270 $127,234 $123,919
Operating expenses:
Operation and maintenance........ 26,081 26,112 22,108 21,119 21,534
Depreciation and amortization.... 24,090 23,684 23,847 23,609 21,976
Taxes other than income taxes.... 12,333 11,206 10,953 11,156 11,449
---------- --------- --------- --------- ---------
Total operating expenses....... 62,504 61,002 56,908 55,884 54,959
Operating income..................... 69,505 65,318 71,362 71,350 68,960
Other income and (expenses).......... 8,850 2,708 1,829 1,824 1,419
---------- --------- --------- --------- ---------
Income before interest charges, taxes and
cumulative effect of change in accounting
principle 78,355 68,026 73,191 73,174 70,379
Net interest expense............. 24,819 25,148 28,067 31,139 30,621
---------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of change in accounting principle.... 53,536 42,878 45,124 42,035 39,758
Provisions for taxes(1).......... 21,435 16,911 18,275 17,083 15,580
---------- --------- --------- --------- ---------
Income before cumulative effect
of change in accounting principle 32,101 25,967 26,849 24,952 24,178
---------- --------- --------- --------- ---------
Cumulative effect of change in accounting
principle, net of tax 3,715 - - - -
---------- --------- --------- --------- ---------
Net Income $ 35,816 $ 25,967 $ 26,849 $ 24,952 $ 24,178
========== ========= ========= ========= =========
Cash Flow Data:
Net cash from operating
activities....................... $75,046 $ 68,782 $ 77,265 $ 57,181 $ 57,961
Capital expenditures................. $153,100 $109,433 $36,340 $8,268 $7,718
Balance Sheet Data
(at End of Period):
Net property, plant and equipment $759,343 $621,475 $533,219 $520,172 $534,806
Total assets......................... $848,705 $689,385 $591,745 $584,368 $594,851
Long-term debt, including
current maturities............... $470,000 $407,222 $366,666 $388,889 $336,664
Partners' capital.................... $312,643 $232,073 $190,764 $169,423 $227,388
_________________________________
(1) The payment of income taxes is the responsibility of partners of the
Partnership. The Partnership's approved rates, however, include an
allowance for taxes (calculated as if it was a corporation) and the FERC
requires the Partnership to record such taxes in its partnership records
to reflect the taxes payable by its partners as a result of the
Partnership's operations. These taxes are recorded without regard to
whether each partner can utilize its share of the Partnership's tax
deductions. The Partnership's rate base, for rate-making purposes, is
reduced by the amount equivalent to accumulated deferred income taxes in
calculating the required return.
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Overview
The Partnership owns and operates a 412-mile interstate natural gas
transmission pipeline that extends from the Canada-United States border near
Waddington, New York to South Commack, Long Island, New York and includes the
Eastchester Extension. The Partnership provides service to local gas
distribution companies, electric utilities and electric power generators, as
well as marketers and other end-users, directly or indirectly, by connecting
with pipelines and exchanges throughout the northeastern United States. The
Partnership is exclusively a transporter of natural gas in interstate commerce
and operates under authority granted by the FERC. The Partnership commenced full
operations in 1992, creating a link between markets in the states of
Connecticut, Massachusetts, New Hampshire, New Jersey, New York and Rhode
Island, and western Canada natural gas supplies. The Partnership's pipeline
system connects at four locations with three interstate pipelines and also
connects with the pipeline system of TransCanada PipeLines Limited at the
Canada-United States border near Waddington, New York.
The Partnership began constructing the Eastchester Extension on April
19, 2002. As part of the Eastchester Extension, the Partnership made
modifications to its three existing compressor stations and constructed two new
compressor stations in Dover, New York and Boonville, New York. Construction of
the Long Island Sound portion of the Eastchester Extension commenced in October
2002. As a result of delays in obtaining certain construction authorizations and
permits and delays related to construction incidents, Eastchester Extension was
placed into service on February 5, 2004. Management believes that final project
construction costs will be approximately $334 million, rather than the $210.0
million in project costs estimated during the FERC's certification process, and
will likely reduce the Partnership's initial margins that were anticipated when
the project application was filed with the FERC. See Note 7 to the Consolidated
Financial Statements included elsewhere in this annual report.
The Partnership receives revenues under long-term firm reserved
transportation service contracts with shippers in accordance with service rates
approved by the FERC. On December 17, 1999, the Partnership filed with the FERC
a settlement of various outstanding rate matters (Docket Nos. RP97-126 and
RP94-72). Pursuant to the settlement the parties agreed to a rate moratorium
whereby, with limited exceptions, no new rates could be placed in effect on the
Partnership's system until January 1, 2004. In light of the expiration of the
1999 rate moratorium, the Partnership renegotiated its effective transportation
rates with its customers and on August 29, 2003 filed a new four-year rate
settlement with the FERC in Docket No. RP03-589. On October 24, 2003, the FERC
approved the settlement which, as noted below, approved new settlement rates for
the Partnership's existing mainline customers and, with limited exception,
provided that no change to the mainline settlement rates may be placed in effect
on the Partnership's mainline system until December 31, 2007.
The settlement establishes the Partnership's base tariff recourse
rates, or settlement rates, for the years 2004, 2005, 2006, and 2007. The
settlement rates reflect annual step-downs, which over the term of the
settlement will reduce the Partnership's transportation rates by
25
approximately 13% (e.g., the 100% load factor interzone rate will be reduced
from the existing level of $0.4234 per Dth, to the January 1, 2007 level of
$0.3700 per Dth, for a total cumulative reduction of $0.0534 per Dth). Based on
long-term firm service contracts as of December 31, 2003, the settlement will
result in reductions in revenues of $3.8 million in 2004, $1.5 million in 2005,
$1 million in 2006 and $2.5 million in 2007. Under the settlement the first
step-down in rates becomes effective on July 1, 2004. The settlement does not
establish any rates, terms or conditions for the Eastchester Extension.
Outlook
While the gas-fired electric generation building cycle has slowed in
New England, there is a significant effort by the state of New York to encourage
additional gas-fired generation within the state, as demonstrated by the recent
solicitation for generating capacity by Consolidated Edison, the Long Island
Power Authority and the New York Power Authority. The development of additional
gas supply remains a challenge for the natural gas industry. However, the
announcement of several new liquefied natural gas (LNG) terminals in the
Northeast increases the potential for new gas supply to the region and enhances
the opportunity for further penetration of natural gas into energy markets.
Obtaining permits for projects in the Northeast remains a significant
challenge. This however, may benefit the Partnership given its recent completion
of a new meter delivery point into New York City through its Eastchester
Extension, since companies with an existing infrastructure will have an
advantage over companies proposing new infrastructure, in light of the risks in
obtaining permits.
Results of Operations
The components of Operating Revenues and Volumes Transported for the
past three years are provided in the following table:
Year ended
December 31,
-------------------------------
Revenues and Volumes Transported
2003 2002 2001
---- ---- ----
Revenues (dollars in millions)
Long-term firm reserved service $115.6 $114.8 $119.1
Short-term firm (1) 8.8 4.1 5.5
Interruptible/other (1) 7.6 7.4 3.7
--- --- ---
Total revenues $132.0 $126.3 $128.3
Volumes Transported (millions of dekatherms)
Long-term firm reserved service 289.7 300.7 281.8
Short-term firm (1) 23.1 11.4 15.7
Interruptible/other (1) 32.4 32.3 20.6
---- ---- ----
Total volumes transported 345.2 344.4 318.1
26
(1) Short-term represents firm service contracts of less than one year. Other
revenue includes deferred asset surcharges, park and loan service revenue
and marketing fees.
Revenues
As discussed above, the Partnership receives revenues under long-term
firm reserved transportation service contracts with shippers in accordance with
service rates approved by the FERC. The Partnership's firm revenues are
primarily derived from long-term contracts and are not directly affected by
fluctuations in volumes. The Partnership also has interruptible transportation
service revenues which, although small relative to overall revenues, are at the
margin and thus can have a significant impact on its net income. Interruptible
transportation service revenues include short-term firm reserved transportation
service contracts of less than one-year terms as well as standard interruptible
transportation service contracts. While it is common for pipelines to have some
form of required revenue sharing of their interruptible transportation service
revenues with long-term firm reserved service shippers, the Partnership does
not. However, the Partnership cannot assure that this will be the case in the
future.
2003 compared to 2002
Total revenues increased by $5.7 million, or 4.5%, to $132.0 million
for 2003 from $126.3 million for the prior year. This increase was largely due
to an increase in short-term firm revenues of approximately $4.7 million,
attributable primarily to increased volumes for short-term firm service
resulting from stronger market demand for natural gas due to colder weather
during the first quarter of 2003 as compared to the same period in 2002.
Long-term firm revenues increased by $0.8 million primarily due to additional
capacity provided by the mainline compression portion of the Eastchester
facilities and a new negotiated rate long-term firm contract in the first
quarter of 2003, partially offset by the rate decrease effective January 1, 2003
of approximately $0.01 per Dth. The Partnership's firm revenues are primarily
derived from long-term contracts and are not directly impacted by fluctuations
in volumes.
2002 compared to 2001
Total revenues decreased by $2.0 million, or 1.6%, to $126.3 million
for 2002 from $128.3 million for the prior year. Long-term firm revenues for
2002 decreased $4.3 million from the prior year primarily due to a rate decrease
of $.024 cents per Dth in 2002. The rate decrease resulted in a $6.1 million
decrease in long-term firm revenues for 2002 which was partially offset by new
long-term firm contracts in place in 2002. Short-term firm revenues for 2002
decreased $1.4 million from the prior year while interruptible/other revenues
increased $3.7 million over 2001 levels due primarily to a shift in demand for
services from short-term firm to interruptible.
Operation and Maintenance Expense
Operation and maintenance expense includes operating, maintenance and
administrative expenses for the Partnership's corporate office in Shelton,
Connecticut and field support for the
27
mainline, metering and compression facilities. The Partnership expects that
there will be normal increases in payroll, benefits and insurance expenses due
to expected inflationary trends.
2003 compared to 2002
Operation and maintenance expense was $26.1 million for each of 2003
and 2002. Operation and maintenance expense for 2003 included a $0.7 million
write-off related to the Partnership's investment in its Western Leg project as
well as increases related to insurance, regulatory expenses, outside services
expense and rent expense. Operation and maintenance expense for 2002 included a
$2.2 million write-off related to the Partnership's investment in its Eastern
Long Island, or ELI, project which had been withdrawn from FERC certification.
2002 compared to 2001
Operation and maintenance expense increased by $4.0 million, or 18.1%,
to $26.1 million for 2002 from $22.1 million for 2001. The increase was due to
the write-off of the ELI project in 2002, increased payroll and benefits expense
as well as higher outside service and insurance costs in 2002.
Taxes Other Than Income Taxes
Taxes other than income taxes consist primarily of municipal property
taxes and payroll taxes. With the Eastchester Extension being placed into
service in 2004, the Partnership expects that municipal property taxes will
continue to increase as municipalities begin to place that property on their tax
rolls.
As of December 31, 2003, the Partnership changed its method of
accounting for municipal property taxes to provide a better matching of property
tax expense with the receipt of services provided by the municipalities. Most
municipalities in Connecticut assess property values as of October 1 of each
year (lien date) with payments due the following July 1, for the year beginning
that July 1. Most New York municipalities assess property values as of July 1
(lien date) with payments due the following January 1 for the year beginning
that January 1. New York school districts also follow a similar process.
Through the calendar year ended December 31, 2002, the Partnership
accrued property taxes based on estimated assessments beginning on the lien
date. For the calendar year ended December 31, 2003, the Partnership began to
recognize the actual property tax expense over the same period that the towns
recognize the income from those taxes. The cumulative effect of this change in
accounting for municipal property taxes, all of which is recognized in the
quarter ended December 31, 2003 is a reduction to expense of approximately $6.2
million before income taxes and $3.7 million after income taxes, and is
reflected on the income statement as a cumulative effect of change in accounting
principle. If the Partnership had accounted for property taxes in this manner
for 2002 and 2001, the amounts that would have been reported as property tax
expense for these years would not have been significantly different than what is
actually reported. This one-time change in accounting principle is not expected
to have a significant effect on future property tax expense.
28
2003 compared to 2002
Taxes other than income taxes increased by $1.1 million, or 9.8%, to
$12.3 million for 2003 from $11.2 million for 2002 primarily due to increased
assessments, partially reflecting the in-service of modifications to existing
compressor stations added as part of the Eastchester Extension in 2002.
2002 compared to 2001
Taxes other than income taxes increased by $0.2 million, or 1.8%, to
$11.2 million for 2003 from $11.0 million for 2002, partially due to increases
in property assessments.
Other Income and Expenses
Other income includes certain investment income and the net of income
and expense adjustments not recognized elsewhere.
2003 compared to 2002
Other income and expenses increased by $6.2 million, or 229.6%, to
$8.9 million for 2003 from $2.7 million for 2002, primarily as a result of an
increase in allowance for equity funds used during construction, or Equity
AFUDC, of $6.4 million to $8.7 million for 2003 from $2.3 million for 2002. This
increase was due primarily to the Partnership's expenditures for the Eastchester
Extension. The increase was partially offset by a decrease in interest income of
approximately $0.2 million in 2003 compared to 2002 primarily due to a decrease
in the interest rate realized from investments as well as lower average cash
balances during 2003.
2002 compared to 2001
Other income and expenses increased by $0.9 million, or 50.0%, to $2.7
million for 2002 from $1.8 million for 2001, primarily as a result of an
increase in Equity AFUDC of $1.9 million to $2.3 million for 2002 from $0.4
million for 2001. This increase was due primarily to the Partnership's
expenditures for the Eastchester Extension. The increase was partially offset by
a decrease in interest income of approximately $1.0 million in 2002 compared to
2001 primarily due to a decrease in the interest rate realized from investments
as well as lower average cash balances during 2002.
Interest Expense
Interest expense relates primarily to borrowings associated with the
Partnership's construction projects, most recently the Eastchester Extension.
29
2003 compared to 2002
Interest expense increased $5.5 million, or 19.7%, to $33.4 million
for 2003 from $27.9 million for 2002. The increase in interest expense reflects
an increase in the Partnership's average debt balance due to borrowings
associated with construction of the Eastchester Extension. A $170.0 million bond
offering was completed in August 2002 at which time $144.2 million was used to
pay down the Partnership's existing bank facility, which included a $22.2
million prepayment. The Partnership's credit agreement was amended to permit the
Partnership to draw on that facility, up to an aggregate of $120.0 million, to
match construction expenditures. As of December 31, 2003, this amount had been
fully drawn by the Partnership. The details of the bond offering are discussed
in Note 3 to the Consolidated Financial Statements.
Allowance for borrowed funds used during construction increased $5.8
million to $8.5 million for 2003 as compared to 2002 primarily due to the
Partnership's expenditures for the Eastchester Extension.
2002 compared to 2001
Interest expense decreased $0.8 million to $27.9 million for 2002 from
$28.7 million in 2001 primarily due to a lower average long-term debt balance
due to scheduled debt repayments and lower interest rates on floating rate debt
during the first half of 2002. This decrease was partially offset by an increase
in interest expense in the second half of 2002, reflecting an increase in the
Partnership's average debt balance due primarily to the $170.0 million bond
offering which was completed in August 2002.
Allowance for borrowed funds used during construction increased $2.1
million to $2.7 million for 2002 as compared to 2001 primarily due to the
Partnership's expenditures for the Eastchester Extension.
Income Taxes
Provision for taxes increased $4.5 million in 2003 compared to 2002
due primarily to an increase in taxable income. Provision for taxes decreased
$1.4 million in 2002 compared to 2001 due primarily to a decrease in taxable
income.
Liquidity and Capital Resources
The Partnership's primary source of financing has been cash flow from
operations, its offerings of senior notes, bank borrowings and partner equity
contributions. The Partnership's ongoing operations will require the
availability of funds to service debt, fund working capital, and make capital
expenditures on the Partnership's existing facilities and expansion projects.
Net cash provided by operating activities increased by $6.2 million to
$75.0 million in 2003 from $68.8 million in 2002 and decreased by $8.5 million
to $68.8 million in 2002 from $77.3 million in 2001, primarily due to the
effects of an increase in debt issuance costs, in 2002, associated with the
financing completed on August 14, 2002 related to the Eastchester Extension,
30
as more fully described below. Additionally, the revenue increase from 2002 to
2003 also contributed to the increase in net cash provided by operating
activities.
Net cash flow related to financing activities increased by $52.2
million to $92.8 million in 2003 from $40.6 million in 2002 due to the net
effects of the 2002 Eastchester Extension financing more fully described below.
Net cash flow related to financing activities increased by $84.8 million to
$40.6 million in 2002 from ($44.2) million in 2001, due to the Eastchester
Extension financing. No new borrowings were made in 2001.
On August 14, 2002, the Partnership issued $170.0 million of senior
unsecured notes that mature on October 31, 2027. The proceeds from the sale of
the notes were used to repay a portion of the first tranche of term loans under
the Partnership's amended credit agreement. This agreement provided for
borrowings from time to time against a second tranche of term loans in an
aggregate amount not to exceed $120.0 million, which, with cash from operations
and additional partner equity contributions, were used to finance the remaining
construction of the Eastchester Extension and for general corporate purposes. As
of December 31, 2003, the full amount of the second tranche of term loans of
$120.0 million was drawn. As of December 31, 2003, the debt outstanding under
the Partnership's amended credit agreement net of scheduled debt repayments was
$100.0 million.
On August 9, 2000, the Partnership entered into an interest rate swap
agreement to hedge a portion of the interest rate risk on its credit facilities.
The interest rate swap agreement terminates on the last business day in May
2009. Under its terms, the Partnership agreed to pay a fixed rate of 6.82% on an
initial notional amount of $25.0 million, which is being amortized during the
term of the interest rate swap agreement, in return for payment of a floating
rate of 3-month LIBOR on the amortizing notional amount. The Partnership also
agreed to grant an option to the swap counter-party to enter into an additional
interest rate swap agreement. The option was exercised on December 26, 2000 with
a termination date on the last business day in May 2009. This additional
interest swap agreement has the same fixed and floating rate terms as the
initial interest rate swap agreement and is for an initial notional amount of
$24.3 million, which is being amortized during the term of the additional
interest rate swap agreement. The two interest swap agreements were amended on
August 14, 2002 to match the term of the Partnership's amended credit agreement,
which was also completed on that date. As of December 31, 2003 and December 31,
2002, the aggregate notional principal amount of these two swaps was $30.6
million and $36.1 million, respectively. The fair value of these interest rate
swaps, net of taxes at December 31, 2003 and December 31, 2002, was ($2.0)
million and ($2.8) million, respectively.
On June 19, 2002, the Partnership entered into forward interest rate
agreements with two major financial institutions in the aggregate notional
amount of $120.0 million. On July 31, 2002, the Partnership entered into
additional forward interest rate agreements with the same institutions in the
aggregate notional amount of $50.0 million. The forward interest rate agreements
were entered into to hedge the underlying interest rate for the unsecured senior
notes which the Partnership issued on August 14, 2002. Upon the closing of the
financing transaction, the forward interest rate agreements were terminated and
the Partnership paid $5.8 million to settle those contracts. The Partnership has
deferred and is amortizing this amount over the life of the senior notes.
31
The Partnership also is party to a $10.0 million, 364-day, variable
rate revolving line of credit to support working capital requirements. As of
December 31, 2003, the outstanding principal balance on the revolving credit
facility was $10.0 million. As of December 31, 2002, there were no amounts
outstanding under this facility.
Capital expenditures for 2003 were $153.1 million, compared to $109.4
million in 2002, reflecting primarily the increased construction activity
related to the Eastchester Extension during the year. In addition, there were
expenditures associated with a compressor station site, general plant purchases
and other miscellaneous projects. Capital expenditures in 2002 also consisted of
expenditures relating to the Eastchester Extension, expenditures associated with
a meter station and interconnect, a compressor station, general plant purchases
and other miscellaneous projects. In 2001, capital expenditures of $36.4 million
were related to the Eastchester Extension, as well as general plant purchases
and other minor projects.
Total capital expenditures for 2004 are estimated to be approximately
$30.9 million, including approximately $27.7 million for the completion of the
Eastchester Extension. The remaining capital expenditures planned for 2004 are
primarily for various general plant purchases. The Partnership expects to fund
its 2004 capital expenditures through internal sources, including cash from
operations and increased equity (by limiting distribution to partners) in
accordance with the partnership agreement. The Partnership's management makes
recommendations to the partnership management committee regarding the amount and
timing of distributions to partners. The amount and timing of distributions is
subject to internal cash requirements for construction, financing and
operational requirements. Distributions and cash calls require the approval of
the management committee. There were no cash distributions to partners during
2003 or 2002. Total cash distributions to partners of $22.0 million were made
during 2001. Partners made equity contributions to the Partnership during 2003,
which, in the aggregate, totaled $20.0 million. There were no equity
contributions made in 2002 or 2001.
Off-Balance Sheet Transactions
At December 31, 2003, the Partnership had no off-balance sheet
transactions, arrangements, or other relationships with unconsolidated entities
or persons that would adversely affect liquidity, availability of capital
resources, financial position, or results of operations.
Contractual Obligations
The Partnership is committed to making payments in the future on two
types of contracts: long-term debt and leases. The Partnership has no
off-balance sheet debt or other such unrecorded obligations and has not
guaranteed the debt of any other party. Below is a schedule of the future
payments the Partnership was obligated to make based on agreements in place as
of December 31, 2003 (in thousands of dollars).
32
Less than More than
Total 1 Year 1 to 3 Years 3 to 5 Years 5 Years
----- ------ ------------ ------------ -------
Long-Term Debt $480,000 $32,222 $44,444 $44,564 $358,770
Transportation by
Others (1) 25,920 3,240 6,480 6,480 9,720
Operating Leases 10,028 920 1,513 1,488 6,107
Pension
Contributions 1,251 1,251 __ __ __
-------- ------- ------- ------- --------
Total Contractual
Obligations $517,199 $37,633 $52,437 $52,532 $374,597
======== ======= ======= ======= ========
(1) Rates are based on known 2004 levels. Beyond 2004, demand rates are subject
to change.
New Accounting Standards
In April 2003, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149
primarily amends SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," to clarify the definition of a derivative and to require
derivative instruments that include up-front cash payments to be classified as
financing activity in the statement of cash flows. SFAS No. 149 is effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The adoption of SFAS No. 149 did
not have a material impact on the Partnership's financial condition or results
of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards for how an issuer classifies and measures in its
financial statements certain financial instruments with characteristics of both
liabilities and equity. SFAS No. 150 requires an issuer to classify a financial
instrument as a liability if that financial instrument embodies an obligation of
the issuer. The adoption of SFAS No. 150 did not have a material impact on the
Partnership's financial condition or results of operations.
In December 2003, the FASB issued SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits, an amendment of
FASB Statements No. 87, 88, and 106." SFAS No. 132 requires that expanded
disclosures on pension and other post retirement benefit plans be included in
financial statements for fiscal years ending on or after Dec. 15, 2003. The
Partnership has adopted SFAS No. 132. See Note 10.
In January 2003, the FASB issued FIN 46R, "Consolidation of Variable
Interest Entities." FIN 46R provides guidance on the identification of, and the
financial reporting for,
33
entities over which control is achieved through means other than
voting rights, known as "variable interest entities." FIN 46R provides guidance
for determining whether consolidation is required. Certain variable interest
entities must be consolidated by the primary beneficiary if the equity investors
in the entity do not have the characteristics of a controlling financial
interest or do not have sufficient equity at risk for the entity to finance its
activities without additional subordinated financial support from other parties.
FIN 46R was effective immediately for all new variable interest entities created
or acquired after Jan. 31, 2003. The Partnership did not have any interests in
any variable interest entities during any of the current reporting periods. The
application of FIN 46R had no material impact on the Partnership's financial
condition or results of operations.
Critical Accounting Policies and Estimates
The Partnership's discussion and analysis of its financial condition,
results of operations and cash flows are based upon the Partnership's
consolidated financial statements, which have been prepared in accordance with
accounting principles generally accepted in the United States of America, or
GAAP. The preparation of these consolidated financial statements required
management to make estimates and judgments that affect the reported amount of
assets and liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities at the date of the consolidated financial
statements. Actual results may differ from these estimates under different
assumptions or conditions.
Critical accounting policies and estimates are defined as those that
are reflective of significant judgment and uncertainties, and potentially may
result in materially different outcomes under different assumptions and
conditions. The Partnership believes that its accounting policies and estimates
that are most critical to the reported results of operations, cash flows and
financial position are described below.
Regulatory accounting
The Partnership follows accounting policies prescribed by GAAP and the
FERC. As a rate-regulated Partnership, the Partnership is subject to the
Financial Accounting Standards Board ("FASB") Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation". The application of SFAS 71 results in differences in the timing of
recognition of certain revenues and expenses from that of other businesses and
industries. The Partnership's gas transmission business remains subject to
rate-regulation and continues to meet the criteria for application of SFAS 71.
This ratemaking process results in the recording of regulatory assets based on
current and future cash inflows. Regulatory assets represent incurred costs that
have been deferred because they are probable of future recovery in customer
rates. As of December 31, 2003 and 2002, the Partnership recorded regulatory
assets of $20.6 million and $15.7 million, respectively. The Partnership
continuously reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. The Partnership expects to fully recover
these regulatory assets in its rates. If future recovery of costs ceases to be
probable, the Partnership would be required to charge these assets to current
earnings. However, impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
34
Derivatives and hedging
The Partnership utilizes derivative contracts to hedge interest rate
risk associated with the Partnership's existing variable rate debt, and to hedge
the net proceeds of new fixed rate debt. SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities", as amended, requires that the Partnership
document its hedging strategies and estimates of hedge effectiveness prior to
initiating a hedge, as well as continuing to assess hedge effectiveness for the
life of the hedging instrument. Currently, the Partnership has two interest rate
swaps outstanding with a total notional amount of $30.6 million, and a fair
value of ($2.0) million, net of taxes. The Partnership records the market value
of these interest rate swaps on its