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, 2002
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 and Exchange Act of 1934
during the preceding 12 months (or shorter period that the registrant was
required to file such reports), and (2) has been subject to the filing
requirements for at least the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes [ ] No [ X ]
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
Form 10-K Annual Report, for the year ended December 31, 2002
Table of Contents
Page
Special Note Regarding Forward-Looking Statements..............................1
PART I.
ITEM 1. BUSINESS..............................................................2
ITEM 2. PROPERTIES...........................................................17
ITEM 3. LEGAL PROCEEDINGS....................................................17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................19
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS..................................................19
ITEM 6. SELECTED FINANCIAL DATA..............................................19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS..................................20
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK..........................................................29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................29
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE..................................29
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP..................30
ITEM 11. EXECUTIVE COMPENSATION...............................................32
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT...........................................................37
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................38
ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES...................................38
PART IV.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K..................................................39
i
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 dependence on shippers for revenues; and
o dependence on availability of Western Canada natural gas reserves
and the continued availability of gas transportation from Western
Canada to the Partnership's pipeline through the TransCanada
PipeLines Limited System.
Certain of these factors are discussed in more detail elsewhere, including,
without limitation, under the captions "Business-Risk Factors," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." Other matters set forth in this annual report may also cause actual
results in the future to differ materially from those described in the
forward-looking statements. The Partnership does not intend to update or revise
any forward-looking statements, whether as a result of new information, future
events or otherwise. In light of these risks, uncertainties and assumptions, the
forward-looking events discussed in this annual report might not occur.
1
PART I.
ITEM 1. BUSINESS
Introduction
Iroquois Gas Transmission System, L.P. is a Delaware limited
partnership. It owns and operates a 375-mile interstate natural gas transmission
pipeline from the Canada-United States border near Waddington, New York to South
Commack, Long Island, New York. The Partnership provides service to local gas
distribution companies, electric utilities and electric power generators, as
well as marketers and other end-users, directly or indirectly, by connecting
with pipelines and exchanges throughout the northeastern United States. The
Partnership is exclusively a transporter of natural gas in interstate commerce
and operates under authority granted by the FERC. The Partnership commenced full
operations in 1992, creating a link between markets in the states of
Connecticut, Massachusetts, New Hampshire, New Jersey, New York and Rhode
Island, and western Canada natural gas supplies. The Partnership's pipeline
system connects at four locations with three interstate pipelines and also
connects with the pipeline system of TransCanada PipeLines Limited (the
"TransCanada System") at the Canada-United States border near Waddington, New
York.
The Partnership provides transportation service to its shippers under
transportation service contracts, which provide for either firm reserved service
or interruptible service. Firm reserved transportation service contracts are
either long-term, multi-year contracts or short-term contracts of less than one
year. Under firm reserved transportation contracts, a certain amount of the
Partnership's pipeline system's capacity is reserved for the use of a shipper.
Under interruptible transportation service contracts, a shipper's access to the
Partnership's pipeline system depends upon the availability of pipeline system
capacity on any given day. As of December 31, 2002, the Partnership had 34
shippers under long-term firm reserved transportation service contracts and its
pipeline system's contracted capacity of 1,064 thousands of dekatherms per day,
or MDth/d, was fully subscribed. As of December 31, 2002, approximately 83% of
the Partnership's subscribed pipeline capacity was contracted under firm
reserved transportation service contracts that continue until at least 2011.
The partners and their respective interests in the Partnership are as
follows:
2
Percentage
Ownership
Ultimate Parent of Partner Name of Partner Interest
-------------------------- --------------- --------
TransCanada PipeLines TransCanada Iroquois Ltd. 29.0%
Limited TCPL Northeast Ltd. 11.96%
KeySpan Energy Corporation NorthEast Transmission 19.4%
Company
LILCO Energy Systems, Inc. 1.0%
Dominion Resources, Inc. Dominion Iroquois, Inc. 24.72%
PG&E Generating Company JMC-Iroquois, Inc. 4.93%
Iroquois Pipeline Investment, LLC 0.84%
Energy East Corporation TEN Transmission Company 4.87%
New Jersey Resources NJNR Pipeline Company 3.28%
Corporation
Iroquois Pipeline Operating Company ("IPOC"), a wholly owned subsidiary
of the Partnership, is the operator of the Partnership's pipeline system and is
responsible for the day-to-day management of the pipeline system pursuant to an
operating agreement entered into between the Partnership and IPOC on January 14,
1989 that expires on November 11, 2011 and renews on a yearly basis thereafter.
Description of the Pipeline
Pipeline Facilities. The Partnership's pipeline system extends 375
miles from the Canada-United States border near Waddington, New York to South
Commack, Long Island, New York. The pipeline system offers access to natural gas
supplies in Western Canada to local gas distribution companies, electric
utilities, electric power generators and natural gas marketers operating in the
New York and New England power grids.
Compressor Stations. Compressor stations increase the pressure of
natural gas flowing through the Partnership's pipeline system, increasing its
capacity and the volume of natural gas that can be shipped under contract. In
May 1992, the FERC approved construction of the Partnership's first compressor
station located in Wright, New York. This station went into service in November
1993 and by that year-end, the volumes under contract had increased to 648.6
MDth/d. A second compressor station, in Croghan, New York, was commissioned in
December 1994, expanding firm reserved service to 758.9 MDth/d. The
Partnership's third compressor station, located in Athens, New York, commenced
operation on November 1, 1998. As part of an Eastchester/New York City expansion
of its pipeline system consisting of an approximately 36-mile mainline extension
running from the mainline on Long Island near Northport, through the Long Island
Sound to Eastchester, New York (the "Eastchester Extension"), the Partnership
added additional compression and cooling facilities at the Croghan, Wright and
Athens, New York compressor stations in 2002. As of December 31, 2002, the
3
Partnership had firm reserved transportation contracts in place to deliver 1,064
MDth/d of natural gas.
Metering Stations and Interconnects. The Partnership receives natural
gas from the TransCanada System at the Canada-United States border near
Waddington, New York and delivers gas in New York and Connecticut through meters
tied directly to end-user markets. The Partnership's pipeline system operates
and maintains a total of 20 delivery meters with a combined capacity of
approximately 4,230 MDth/d. Each meter station consists of a separate control
building that contains gas measurement equipment and electrical and
instrumentation devices. The Partnership has incorporated a manual chart
recorder system to maintain continuous gas measurement in the event of a total
electronic failure. The Partnership also delivers gas to the other major natural
gas pipelines in the Northeast through its interconnections at four locations
with three interstate pipelines and also connects with the TransCanada System.
The Partnership also has an interconnection with the New York Facilities System
at South Commack, Long Island. The New York Facilities System is a pipeline
system owned and used by both Consolidated Edison Company of New York, or Con
Ed, and KeySpan Energy Corporation.
Communications. The Partnership maintains 24-hour monitoring of its
pipeline system via a computerized data monitoring and control system known as
SCADA (supervisory control and data acquisition) that links all compressor
stations and maintenance bases with the Partnership's gas control center in
Shelton, Connecticut. Remote facilities along the pipeline route are accessed
with the use of multiple address radio communication links to a satellite
system, which allows the pipeline system to be operated remotely from the gas
control center.
Operations. The gas control center houses the gas management, control
and computer systems required to operate the pipeline system and dispatch gas. A
backup gas control center is located in Oxford, Connecticut. In the event that
neither of these control centers is available, the Partnership's entire pipeline
system can be monitored and operated from the Wright, New York compressor
station. The Partnership has operated the pipeline system with regular and
continuous maintenance since it commenced operations. Inspections and tests have
been performed at prescribed intervals to ensure the integrity of the system.
These include periodic corrosion surveys, testing of relief and over-pressure
devices and periodic aerial inspections of the right-of-way, all conforming to
the United States Department of Transportation regulations. Such actions have
allowed the Partnership to maintain high operational availability of its system,
in particular, its compressors. Availability is a measure of the overall
reliability of a compressor. During the last five years, the average
availability of the Partnership's compressor units has ranged from 97% to 98%, a
rate that the Partnership believes is higher than the rest of the industry. In
addition, because multiple compressor stations are operational, the system is
capable of achieving high levels of throughput even when one or more compressor
units are experiencing an outage.
Transportation Services and Shippers
The design capacity of the Partnership's pipeline system is fully
subscribed under firm reserved transportation service contracts with 34
shippers. Under the firm reserved transportation service contracts, the pipeline
receives natural gas on behalf of shippers at
4
designated receipt points and transports the gas on a firm basis up to each
shipper's maximum daily quantity. As of December 31, 2002, approximately 83% of
the subscribed capacity of the Partnership's pipeline system was contractually
committed through at least November 1, 2011. The Partnership has also entered
into several short-term (less than one year) firm reserved transportation
service contracts and numerous interruptible transportation service contracts.
Reservation and variable fees are payable under firm reserved transportation
service contracts and depend on the volume of gas shipped and the zone within
which the gas is shipped. The Partnership's pipeline is currently divided into
two zones: Zone One covers the mainline from Waddington to Wright, New York and
Zone Two covers the territory from Wright, New York through Connecticut to South
Commack, Long Island, New York. The Partnership is also authorized by the FERC
to enter into "negotiated rate" contracts with shippers. To date, the
Partnership has entered into a limited number of negotiated rate contracts for
short-term firm transportation service.
The Partnership's shippers under firm transportation service contracts
consist of major electric and gas utility companies, marketers, gas producers
and independent electric generating companies. KeySpan Energy Corporation, PG&E
Corporation and El Paso Energy Corp., through their affiliates, each accounted
for more than 10% of the Partnership's revenues for the year ended December 31,
2002. Approximately 46% of the Partnership's existing pipeline system firm
reserved capacity was contracted to affiliates of the Partnership's partners as
of December 31, 2002.
The Partnership's FERC-approved tariff provides that, subject to
certain exceptions, the Partnership has the right to require that firm
transportation shippers have an investment grade rating or obtain a written
shipper guarantee from a third party with an investment grade rating. During
2002, the energy industry, which includes the Partnership's firm transportation
shippers, experienced significant credit and liquidity issues and credit rating
agency downgrades. As of December 31, 2002, approximately 41% of the pipeline
system's volume was under firm reserved transportation service contract with
shippers who are rated investment grade by a nationally recognized credit rating
agency. Approximately 22% of the pipeline system's volume was under firm
reserved transportation service contract with shippers with a debt rating of "A"
or higher. Certain of the Partnership's shippers are not rated by credit rating
agencies. Non-rated or non-investment grade rated shippers accounted for
approximately 37% of the pipeline system's volume. The Partnership determines,
under internal credit standards, the shippers or their guarantors that are
creditworthy so that they are not required to post credit support in connection
with their transportation service contracts. Approximately 6% of the capacity
was contracted by shippers who have agreed to post letters of credit in an
amount equal to three months of demand charges pursuant to their transportation
service contracts and approximately 15% have made other credit support
arrangements that the Partnership finds satisfactory. The percentage of shippers
that were required to make credit support arrangements increased in 2002 due in
part to credit agencies downgrading some of the shippers and a change in the
Partnership's credit policy so that it will no longer consider the
creditworthiness of a shipper's parent in lieu of the shipper's own rating,
unless a parental guarantee is to be provided. Aside from a default on a minor
transportation contract with a shipper that is a subsidiary of Enron
Corporation, the Partnership has not experienced any payment defaults.
5
Demand for Transportation Capacity
The Partnership's market, the northeastern United States, is comprised
of approximately 12 million natural gas customers, who account for approximately
19% of all natural gas customers in the United States. The northeastern United
States has experienced an overall increase in natural gas demand in the last
decade. The Partnership expects this demand to continue to grow by 2-3% per year
through 2025. The bulk of the growth in the northeastern United States is
expected to occur in the electric generation sector.
The Partnership's long-term financial condition is dependent on the
continued availability of competitively priced western Canadian natural gas for
import into the United States. Natural gas reserves may require significant
capital expenditures by others for exploration and development drilling and the
installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered. The Western
Canada Sedimentary Basin is currently, and is expected to remain, the primary
source of natural gas for the Partnership's pipeline system. Sable Island and
other natural gas discoveries offshore of Nova Scotia may also provide
additional gas supplies in the future. Advances in technology may increase the
ultimate recoverable reserves from the Western Canada Sedimentary Basin and
offshore basins and bring gas supplies on stream that are currently not
economical to produce.
A variety of factors could affect the demand for natural gas in the
markets that the Partnership's pipeline system serves. These factors include:
o economic conditions;
o fuel conservation measures;
o competition from alternative energy sources;
o climatic conditions;
o legislation or governmental regulations; and
o technological advances in fuel economy and energy generation
devices.
The Partnership cannot predict whether these or other factors will have an
adverse effect on demand for use of the pipeline system or how significant that
adverse effect could be.
In April 2002, the Partnership commenced construction of the
Eastchester Extension. The new line will proceed on land for approximately 4,000
feet, connecting with the northern section of ConEd's gas distribution
facilities. The Partnership believes that because of the location of its
pipeline and its ability to utilize Long Island Sound, a means of direct access
to the New York City market can be developed with minimal environmental and
landowner or right-of-way issues. In contrast, other competing proposals must
access this market through more congested areas at a greater expense. Under
precedent agreements, which contain conditions that must be satisfied before a
contract for firm transportation service is signed, five project shippers agreed
to subscribe for all of the Eastchester Extension's 230 MDth/d of transportation
capacity. On December 26, 2001, the FERC issued a certificate authorizing the
6
Partnership to construct and operate the Eastchester Extension. On January 25,
2002, the Partnership accepted the terms of the certificate. A condition in the
December 26 order required that, prior to commencing construction, the project
shippers execute firm service agreements with 10-year terms for the entire 230
MDth/d of transportation capacity proposed to be built. This condition was based
on the precedent agreements with the five project shippers. However, as a result
of uncertainty and a slowdown in the energy market, exacerbated by Enron
Corporation's bankruptcy proceedings and the resulting examination, both
internal and external, of the financial health of a variety of other energy
market participants, certain Eastchester shippers that were obligated under the
precedent agreements to execute firm transportation service agreements failed to
do so. On February 28, 2002, the Partnership filed a request with the FERC to
commence construction even if service contracts for the full 230 MDth/d of
service had not been executed. On March 13, 2002, the FERC granted the
Partnership's request. As a result, the Partnership did not have executed
contracts for 100% of the total project capacity prior to commencing
construction of the Eastchester Extension. To date, the Partnership has
contracted with shippers for 210 MDth/d of transportation services in connection
with the Eastchester Extension.
A portion of the upstream Eastchester Extension facilities have been
placed into service. Construction of the portion of the Eastchester Extension
located in the Long Island Sound commenced in October 2002. However, as a result
of delays in obtaining certain construction authorizations and permits, and
delays related to construction incidents, the projected in-service date of the
completed Eastchester Extension is now the late summer or early fall of 2003,
and the Partnership's management believes that the final construction costs will
be at least $250.0 million, rather than the $210.0 million estimated during the
FERC certification process, and will likely reduce the Partnership's initial
margins that that were anticipated when the project application was filed with
the FERC.
On November 8, 2001, the Partnership filed an application with the FERC
to construct and operate a second compressor unit at the Partnership's existing
Athens, New York compressor station. The Athens Project is designed to provide
up to 70 MDth/d of firm transportation services to Athens Generating Company,
L.P., with whom the Partnership has executed a firm transportation agreement for
this service. On June 3, 2002, the FERC issued a certificate authorizing the
Partnership to construct the Athens Project. However, the Partnership
anticipates that it will have adequate capacity to serve the initial 70 MDth/d
transportation needs of Athens Generating, and so the Partnership intends to
defer the commencement of construction of the second compressor unit at Athens,
subject to a re-evaluation at a later date. Athens Generating is owned by Gen
Holdings I, LLC, a subsidiary of PG&E National Energy Group, Inc. On January 16,
2003, PG&E National Energy Group announced that it had agreed to cooperate with
any reasonable proposal by its lenders regarding the disposition of certain of
its generating assets, including Athens Generating, in connection with defaults
under various debt agreements. The Partnership is awaiting further developments
in connection with the announcement.
On November 20, 2001, the Partnership filed an application to construct
and operate a new compressor station to be located in Brookfield, Connecticut.
This facility is designed to provide up to 85 MDth/d of firm transportation
service to southern Long Island and the New York City area. The Partnership
would provide firm transportation service to shippers with
7
whom it has executed precedent agreements. On October 31, 2002, the FERC issued
a certificate authorizing the construction of the Brookfield Project. On
December 2, 2002, the Partnership filed a request for clarification or
re-hearing with respect to the rate that would be paid by shippers using the
Brookfield Project facilities. On February 3, 2003, the FERC issued an order
stating that all shippers using the Eastchester Facilities, to which the
Brookfield Project facilities will connect, will be required to pay incremental
fuel costs. The rate to be paid by shippers using the Brookfield Project
facilities to connect to the Eastchester delivery point will ultimately be
determined in future rate proceedings. The Partnership is currently assessing
the market for the Brookfield Project to determine if the projected November
2004 in-service date should be delayed.
On December 14, 2001, the Partnership filed an application to construct
approximately 29 miles of 20-inch pipeline from a point offshore of Milford,
Connecticut to a point in Brookhaven, Suffolk County, New York and additional
compression and cooling facilities to provide approximately 175 MDth/d of firm
transportation service to the eastern end of Long Island, New York. On April 8,
2002, the Partnership filed a motion to consolidate its Eastern Long Island
Project with a similar project proposed by Islander East Pipeline Company, LLC
that was pending at the FERC, and to convene a comparative hearing on the two
projects. The motion was denied by the FERC on September 19, 2002 and a
certificate of public convenience and necessity was issued to Islander East. On
October 10, 2002, the FERC granted the Partnership's motion to defer the Eastern
Long Island Project and directed the Partnership to provide the FERC with an
update on the status of the Eastern Long Island Project at a later date. On
February 7, 2003, the Partnership notified the FERC that, after extensive
discussions with the Eastern Long Island Project's prospective shippers, the
Partnership had determined that insufficient market demand exists to continue to
pursue the Project and the Partnership moved to withdraw its application. As of
December 31, 2002, the Partnership expensed approximately $2.2 million in costs
related to engineering and environmental assessments performed in connection
with the Eastern Long Island Project.
Competition
The Partnership faces varying degrees of competition from other major
pipeline systems in the Northeast and alternative energy sources, including
electricity, coal, propane and fuel oils. Additionally, in recent years, the
FERC has issued orders designed to increase competition in the natural gas
industry. These orders have resulted in pipelines competing with their
customers, who are now allowed to resell their unused firm reserved
transportation capacity to other shippers. Firm reserved transportation
contracts traditionally had terms of 10 to 20 years; however, due to increased
competition, new firm reserved transportation contracts are usually of a shorter
duration.
FERC Regulation and Tariff Structure
General. The Partnership is subject to extensive regulation by the FERC
as a "natural gas company" under the Natural Gas Act of 1938 (the "Natural Gas
Act"). Under the Natural Gas Act and the Natural Gas Policy Act of 1978, the
FERC has jurisdiction over the Partnership with respect to virtually all aspects
of its business, including transportation of gas, rates and charges,
construction of new facilities, extension or abandonment of service and
facilities,
8
accounts and records, depreciation and amortization policies, the acquisition
and disposition of facilities, the initiation and discontinuation of services,
and certain other matters. The Partnership, where required, holds certificates
of public convenience and necessity issued by the FERC covering its facilities,
activities and services.
The Partnership's rates and charges for transportation in interstate
commerce are subject to regulation by the FERC. FERC regulations and the
Partnership's FERC-approved tariff allow the Partnership to establish and
collect rates designed to give it an opportunity to recover all actually and
prudently incurred operations and maintenance costs of its pipeline system,
including taxes, interest, depreciation and amortization and a regulated equity
return. The FERC has granted the Partnership the authority to negotiate rates
with its current and potential shippers. The flexibility of such rates will
allow the Partnership to respond to market conditions, as well as permit the
Partnership to negotiate rates or a rate formula that will meet the specific
needs of individual shippers. This ability to negotiate rates will be an
important tool in attracting the growing electric generation market to the
Partnership's pipeline system.
Except in the limited context of negotiated rates, the rates the
Partnership charges may not exceed the just and reasonable rates approved by the
FERC. In addition, the Partnership is prohibited from granting any undue
preference to any person, or maintaining any unreasonable difference in its
rates or terms and conditions of service.
In general, there are two methods available for changing the rate
charged to shippers, provided that the transportation service contracts do not
bar such changes. Under Section 4 of the Natural Gas Act and applicable FERC
regulations, a pipeline may voluntarily seek a change, generally by providing at
least 30 days' prior notice to the FERC of the proposed changes and filing the
appropriate rate change application. If the FERC determines that a proposed rate
change may not be just and reasonable as required by the Natural Gas Act, then
the FERC may suspend the rate change for up to five months and set the matter
for an investigation. Subsequent to any suspension ordered by the FERC, the
proposed change may be placed in effect by the pipeline pending final FERC
review. If the pipeline chooses to do this, any increase reflected in the
proposed changes will, in the ordinary course of events, be collected subject to
refund. It is also possible that a pipeline seeking to increase the rates it
charges its shippers pursuant to a rate change application under Section 4 of
the Natural Gas Act may, after review by the FERC, have its rates reduced by the
FERC instead. Under Section 5 of the Natural Gas Act, on its own motion or based
on a complaint filed by a customer of a pipeline or other interested person, the
FERC may initiate a proceeding seeking to compel a pipeline to change any rate
or term or condition of service which is on file. If the FERC determines that an
existing rate or condition is unjust, unreasonable, unduly discriminatory or
preferential then any rate reduction or change in service term or condition
which is ordered at the conclusion of such a proceeding is generally effective
prospectively from the date of the order requiring such change.
The nature and degree of regulation of natural gas companies have
changed significantly during the past 10 years, and there is no assurance that
further substantial changes will not occur or that existing policies and rules
will not be applied in a new or different manner, particularly in light of the
FERC's decision to seek comments on its negotiated rate policies from companies
in the natural gas industry.
9
Regulatory Proceedings. After extensive negotiations with various
parties to a series of previous rate-related hearings and orders between 1996
and 1999, on December 17, 1999, the Partnership filed with the FERC an offer of
settlement. By order dated February 10, 2000, the FERC approved the rate
settlement, effectively resolving all remaining issues in the Partnership's
previous rate proceedings. The principal elements of the rate settlement are:
o a reduction in maximum demand rates phased-in over a
three-year period that began on January 1, 2001;
o withdrawal of certain pending petitions for review regarding
FERC actions on the Partnership's general rate change
application;
o a rate moratorium under which the Partnership may not file
an application to increase rates pursuant to the Natural Gas
Act prior to January 1, 2004 and no party may file for
reductions in rates pursuant to the Natural Gas Act prior to
April 1, 2003 or receive such reductions prior to January 1,
2004 (the rate settlement contains certain limited
exceptions to the moratorium for tariff changes not intended
to effect changes in the Partnership's firm reserved service
quality or rates); and
o retention by the Partnership of revenues associated with new
volumes, facilities, services or classes of service added
after November 1, 1999.
As provided in the rate settlement, the Partnership's 100% load factor
interzone rate decreased by $0.01/Dth effective January 1, 2001, by $0.024/Dth
effective January 1, 2002; and by $0.014/Dth effective January 1, 2003, for a
total cumulative reduction of $0.048/Dth. The rate settlement also provides for
similar reductions in other rates charged by the Partnership. The total revenue
impact of these rate reductions was $2.4 million in 2001, $6.1 million in 2002
and is expected to be approximately $3.6 million in 2003, based on long-term
firm reserved transportation service contracts in place as of December 31, 2002.
Rulemaking on FERC's Regulation of Transportation Services. On February
9, 2000, the FERC adopted its Order No. 637. Order No. 637 is intended to
increase efficiency as the market for natural gas continues to become more open
and competitive. As a result of Order No. 637, interstate pipelines should have
greater flexibility in tailoring the firm reserved services they offer to
customers and customers should have improved opportunities to resell their
unused firm reserved transportation service in the secondary market, thus
potentially enhancing the value of firm pipeline service to customers. Order No.
637:
o instituted a two-year waiver of price ceilings on short-term
released capacity, which expired in September 2002;
o allows pipelines to make pro forma tariff filings proposing
peak and off-peak rates for short-term services;
10
o allows pipelines to propose term-differentiated rates for
short-term and long-term services, with any "excess"
revenues shared equally with long-term customers;
o changes regulations regarding scheduling procedures,
capacity segmentation, and pipeline penalties to allow
shippers to utilize pipeline capacity more efficiently;
o narrows the right of first refusal for future long-term
contracts while protecting the right of captive customers to
renew long-term contracts; and
o improves reporting requirements to increase price
transparency and provide additional information on
individual transactions to assist the FERC in its effort to
monitor the functioning of natural gas markets.
While Order No. 637 required some significant changes in the
functioning of the secondary market for firm capacity, its implementation has
not materially affected the level of revenues the Partnership receives. The
Partnership has incurred and may incur additional costs to modify its tariff and
information systems to allow it to comply with Order No. 637. However, these
expenditures have not been, and are not expected to be, material.
As required by Order No. 637, the Partnership filed pro forma tariff
sheets with the FERC. Portions of this filing remain pending at the FERC. See
Note 7 to the Consolidated Financial Statements included elsewhere in this
annual report.
Safety Regulations
The Partnership's operations are also subject to regulation by the
United States Department of Transportation under the Natural Gas Pipeline Safety
Act of 1969, as amended, or the NGPSA, relating to the design, installation,
testing, construction, operation and management of the Partnership's pipeline
system. The NGPSA requires any entity that owns or operates pipeline facilities
to comply with applicable safety standards, to establish and maintain inspection
and maintenance plans and to comply with such plans.
The NGPSA was amended by the Pipeline Safety Act of 1992 to require the
Department of Transportation's Office of Pipeline Safety to consider protection
of the environment when developing minimum pipeline safety regulations. In
addition, the amendments required the Department of Transportation to issue
pipeline regulations concerning, among other things, the circumstances under
which emergency flow restriction devices should be required, training and
qualification standards for personnel involved in maintenance and operation, and
requirements for periodic integrity inspections, including periodic inspection
of facilities in navigable waters which could pose a hazard to navigation or
public safety. The amendments also narrowed the scope of gas pipeline exemptions
pertaining to underground storage tanks under the Resource Conservation and
Recovery Act. The Partnership believes its operations comply in all material
respects with the NGPSA; however, the industry, including the Partnership, could
be required to incur additional capital expenditures and increased costs
depending upon regulations issued by the Department of Transportation under the
NGPSA and/or future pipeline safety legislation.
11
Environmental Matters
Environmental laws and regulations have changed substantially and
rapidly over the last 20 years, and the Partnership anticipates that there will
be continuing changes. Increasingly strict federal, state or local environmental
restrictions, limitations and regulations have resulted in increased operating
costs for the Partnership, and it is possible that the costs of compliance with
environmental laws and regulations will continue to increase. To the extent that
environmental costs are normal costs of doing business, these costs would be
recoverable under the Partnership's rates through future rate proceedings.
Current Operations. At each of the Partnership's three natural gas
compressor stations, IPOC routinely monitors environmental standards and
controls and, to date, IPOC has found that environmental permits and regulations
are being complied with in all material respects.
Settlement of Federal and State Investigations. On May 23, 1996, as
part of a resolution of federal criminal and civil investigations of the
construction of certain of the Partnership's pipeline facilities, IPOC pled
guilty to four felony violations of the Clean Water Act and entered into consent
decrees under the Clean Water Act in four federal judicial districts. Although
not a named defendant, the Partnership signed the plea agreement and consent
decrees and is bound by their terms. The Partnership also entered into related
settlements with the State of New York, the FERC and the Department of
Transportation. Under these various agreements, the Partnership and IPOC agreed
to pay $22.0 million in fines and penalties and to take remedial measures. The
Partnership and IPOC are taking certain actions and adopting a number of
procedures to reduce their risk of noncompliance with environmental regulations
in the future. In August 1996, as a result of settlement of the federal
proceedings, IPOC was placed by the Environmental Protection Agency on a list
that excludes IPOC from federal financial and other assistance under federal
programs and limits IPOC's ability to do business with U.S. government agencies.
This has not had, and the Partnership does not expect it to have, a material
adverse impact on the Partnership's business.
Employees
The Partnership does not directly employ its personnel. The
Partnership's personnel and services are provided by IPOC, its wholly owned
subsidiary, pursuant to the Partnership's operating agreement with IPOC. The
Partnership reimburses IPOC for all reasonable expenses incurred in operating
the Partnership's pipeline system including salaries and wages and related taxes
and benefits. As of December 31, 2002, IPOC had 129 employees.
Risk Factors
The Partnership's business involves significant risks and uncertainties
including those described below.
The Partnership may not be able to maintain its contracts with existing shippers
or enter into contracts with new shippers
As of December 31, 2002, approximately 83% of the subscribed capacity
of the Partnership's pipeline system was contracted through at least November 1,
2011. The
12
Partnership cannot give any assurances that it will be able to extend or replace
these contracts at the end of their initial terms or that, if the Partnership
does extend or replace its existing firm reserved transportation service
contracts, it will be able to do so at the maximum rates that the FERC will
authorize it to charge. The extension or replacement of the existing long-term
contracts with the Partnership's shippers and its ability to enter into similar
contracts for the total increased capacity of its pipeline system to be
generated by its expansions depends on a number of factors beyond the
Partnership's control, including:
o the supply and price of natural gas in Canada and the United
States;
o competition to deliver gas to the Northeast from alternative
sources of supply;
o the demand for gas in the Northeast;
o whether transportation of gas pursuant to long-term
contracts continues to be market practice; and
o whether the Partnership's business strategy, including its
expansion strategy, is successful.
If the Partnership materially breaches its obligations under any
transportation service contract, the affected shipper may have various remedies
including termination of its transportation service contract. The Partnership
cannot assure you that it will be able to replace a contract terminated for
breach with a comparable contract. If these contracts are terminated or are not
extended or replaced with comparable contracts, or if the Partnership is unable
to secure contracts for all the capacity to be generated by its expansions, the
Partnership's cash flows and ability to service its outstanding senior notes may
be adversely affected.
The Partnership is dependent on the performance of its shippers
The Partnership is dependent upon shippers for revenues from contracted
transportation capacity on its pipeline system. The firm reserved transportation
service contracts obligate the shippers to pay reservation charges regardless of
whether or not they use their reserved capacity to transport natural gas on the
pipeline system, subject to limited rights in favor of the shippers in certain
circumstances to receive reservation charge credits. As a result, the
Partnership's profitability generally depends upon the continued
creditworthiness of the shippers rather than upon the amount of natural gas
transported. During 2002, the energy industry, which includes the Partnership's
firm transportation shippers, experienced significant credit and liquidity
issues and credit rating agency downgrades. However, aside from a default on a
minor transportation contract with a shipper that is a subsidiary of Enron
Corporation, the Partnership has not experienced any payment defaults. There can
be no assurance however, that shippers will not default on their payment
obligations for transportation services provided in the future.
The Partnership's rates are calculated on the basis of the assumed
contracted capacity of 1,064 MDth/d and its revenue projections assume that
shippers will pay these rates as required by their contracts. A prolonged
economic downturn in the energy industry or a broader
13
economic downturn affecting the northeastern Unites States could negatively
affect the ability of some or all of the shippers to fulfill their obligations
under the transportation service contracts. A failure to pay by any of its
shippers, for any length of time during which the Partnership does not succeed
in obtaining a creditworthy replacement shipper would decrease the Partnership's
revenues and cash flows and could have an adverse impact on the Partnership's
ability to make payments on its outstanding senior notes.
Changes in regulation and rates may adversely affect the Partnership's results
of operations
Because its pipeline system is an interstate natural gas pipeline, the
Partnership is subject to regulation as a "natural gas company" under the
Natural Gas Act of 1938, as amended, or the Natural Gas Act. The Natural Gas Act
makes the rates the Partnership can charge its shippers and other terms and
conditions of service subject to FERC review and the possibility of modification
in rate proceedings. Under the Natural Gas Act, the Partnership's rates must be
"just and reasonable," as determined by the FERC. In rate review proceedings,
the FERC has the responsibility to ensure that the rates that interstate
pipelines, such as the Partnership's, charge are not greater than those
necessary to enable the pipeline to recover the costs incurred to construct,
own, operate and maintain its pipeline system and to afford the pipeline an
opportunity to earn a reasonable rate of return. Under FERC regulations,
shippers have the opportunity to contest the Partnership's rates and tariff
structure. The Partnership cannot assure you that the FERC will not alter or
refine its preferred methodology for establishing pipeline rates and tariff
structure. It is possible that changes in the FERC's ratemaking policies could
result in lower rates than those the Partnership could charge under the existing
methodology, or could make a large proportion of our rate subject to recovery on
the basis of actual quantities of natural gas that the Partnership transports,
rather than on the basis of firm capacity reservations. Such changes could
therefore adversely affect the Partnership's revenues and ability to service its
senior notes.
Under the terms of the transportation service contracts and in
accordance with the FERC's rate making principles, the Partnership is only
permitted to recover costs associated with the construction and operation of its
pipeline system which are actually, reasonably and prudently incurred and are
included in its pipeline system's regulatory rate base. There can be no
assurance that all costs the Partnership incurs, including costs we incur in
constructing its expansions, will be recoverable through its rates.
A decline in the availability of Western Canadian natural gas may reduce
shippers' willingness to contract for capacity on the Partnership's pipeline
The Partnership's long-term financial condition is dependent on the
continued availability of Western Canadian natural gas for import into the
United States. If the availability of Western Canadian natural gas were to
decline over the initial term of the Partnership's current transportation
service contracts, if upstream transportation service on the TransCanada System
were to become constrained or if the price of Western Canada natural gas were to
increase significantly, existing shippers may not extend their contracts and the
Partnership may be unable to find replacement sources of natural gas for the
pipeline system's capacity. The Partnership cannot give any assurances as to the
availability of additional sources of gas that can interconnect with its
pipeline system.
14
Continued sales of Western Canadian natural gas to the United States
will also depend on:
o the level of exploration, drilling, reserves and production
of Western Canada Sedimentary Basin natural gas and the
price of such natural gas;
o the accessibility of Western Canada Sedimentary Basin
natural gas which may be affected by weather, natural
disaster or other impediments to access, including capacity
constraints on the TransCanada System;
o the price and quality of natural gas available from
alternative United States and Canadian sources and the rates
to transport Canadian natural gas to the United States
border; and
o the regulatory environments in the United States and Canada,
including the continued willingness of the governments of
both countries to permit the import to the United States of
natural gas from Canada on a basis that is commercially
acceptable to the Partnership's shippers and their
customers.
Failure of the pipeline system's operations may result in liabilities for the
Partnership and reduce its revenues or impair its ability to meet its
obligations under its senior notes
There are risks associated with the operation of a complex pipeline
system, such as operational hazards and unforeseen interruptions caused by
events beyond the Partnership's control. These include adverse weather
conditions, accidents, breakdown or failure of equipment or processes,
performance of the facilities below expected levels of capacity and efficiency
and catastrophic events such as explosions, fires, earthquakes, floods,
landslides or other similar events beyond the Partnership's control. Liabilities
incurred and interruptions to the operation of the pipeline caused by such
events could reduce revenues generated by the Partnership and increase the
Partnership's expenses and impair the Partnership's ability to meet its
obligations under the terms of its senior notes. Insurance proceeds may not be
adequate to cover all liabilities incurred, lost revenues or increased expenses.
We face construction and other risks in connection with the Eastchester
Extension
The Partnership faces development and construction risks typical for
natural gas pipeline expansions, including, but not limited to, labor disputes,
shortages of material and skilled labor, slower than projected construction
progress, the existence of sensitive property owned by third parties and
environmental and geological problems. In addition, there are risks associated
with the construction of a large, mainly underwater, pipeline project such as
the Eastchester Extension. These risks include adverse weather conditions,
unexpected construction conditions, accidents, the breakdown or failure of
construction equipment or processes, catastrophic events such as explosions,
fires and shipwrecks and other similar events beyond our control. As a result of
delays in obtaining certain construction authorizations and permits, and delays
related to construction incidents involving damage being caused to undersea
electric transmission cables in the Long Island Sound, the projected in-service
date of the completed Eastchester Extension is
15
now late summer or early fall 2003, and the Partnership's management believes
that the final construction costs of the Eastchester Extension will be at least
$250.0 million, rather than the $210.0 million estimated during the FERC
certification process and will likely reduce the Partnership's initial margins
that were anticipated when the project application was filed with the FERC.
There can be no assurance that further similar delays and incidents will not
occur and that additional changes to the in-service date or budget associated
with the Eastchester Extension will not be made and would not have a material
adverse effect on the Partnership's financial condition.
The Partnership may not succeed in its planned expansions
The Partnership's ability to engage in any expansion project will be
subject to, among other things, approval of its management committee,
restrictions under the indenture relating to the Partnership's senior notes and
numerous business, economic, regulatory, competitive and political uncertainties
beyond the Partnership's control. Therefore, the Partnership cannot guarantee
that any proposed expansion or extension project will be undertaken or, if
undertaken, will be successful.
The success of any planned expansions, once undertaken, may depend on
several factors, including, among others, the following:
o other existing pipelines may provide transportation services
to the area to which the Partnership is expanding;
o any entities, upon obtaining the proper regulatory
approvals, may construct new competing pipelines or increase
the capacity of existing competing pipelines;
o a competitor's new or upgraded pipeline could offer
transportation services that are more desirable to shippers
because of location, facilities or other factors;
o shippers may not be willing to sign long-term contracts for
service which would make use of a planned expansion; and
o laws and regulations, including permit requirements, may
become more stringent so as to affect materially the
viability of the expansions.
The Partnership would also require additional capital to fund any
planned expansions of its pipeline system. If the Partnership fails to generate
sufficient funds in the future, it may have to delay or abandon its expansion
plans, in which case it will lose the ability to capitalize expenditures on such
abandoned expansions. Also, a proposed expansion may cost more than planned to
complete and such excess costs may not be recoverable.
16
The Partnership is subject to laws relating to the protection of the environment
that could involve substantial compliance costs and liabilities
The Partnership's operations are subject to federal, state and local
laws and regulations relating to the protection of the environment and public
safety. Risks of substantial costs and liabilities are inherent in pipeline
operations and the Partnership cannot guarantee that significant costs and
liabilities will not be incurred under applicable environmental and safety laws
and regulations, including those relating to claims for damages to property and
persons resulting from the Partnership's pipeline system operations.
Moreover, it is possible that the development or discovery of other
facts or conditions, such as increasingly stringent changes to federal, state or
local environmental laws and regulations, and enforcement policies thereunder,
could result in increased costs and liabilities to the Partnership. The
Partnership is unable to predict the effect that any future changes in
environmental laws and regulations will have on its future earnings and it
cannot guarantee that environmental costs incurred by it will be recoverable
under its FERC-approved tariff.
ITEM 2. PROPERTIES
The Partnership's principal executive office is located in Shelton,
Connecticut in approximately 33,422 square feet of leased office space under a
lease agreement that expires on April 30, 2011. The Partnership has an option to
cancel approximately 4,300 square feet of that space by written notification to
the landlord of the Shelton office no later than December 31, 2003 and by making
a one-time payment to the landlord of approximately $50,000. The cancellation of
that portion of the lease would be effective January 1, 2005. The Partnership
has not yet decided if it will exercise this option. The Partnership also leases
approximately 14,000 square feet of warehouse and office space in Oxford,
Connecticut under a lease agreement that expires on March 31, 2004. The
Partnership believes that its facilities are adequate for the Partnership's
current operations and that additional leased space can be obtained if needed.
The Partnership holds the right, title and interest to and in its
pipeline system. With respect to real property, the pipeline system falls into
two categories: (i) parcels which the Partnership owns, such as compressor
station and meter station sites; and (ii) parcels in which the Partnership has a
leasehold interest, easement or right-of-way from landowners permitting the use
of land for the construction and operation of the pipeline system. The
Partnership obtained the right to construct and operate its pipeline system
across certain property through negotiations and through the exercise of the
power of eminent domain, where necessary. The Partnership continues to have the
power of eminent domain in each of the states in which it operates its pipeline
system. The Partnership also leases a right-of-way easement on Long Island, New
York, which expires in 2030. The Partnership believes that it has satisfactory
interests in all of the properties making up its pipeline system.
ITEM 3. LEGAL PROCEEDINGS
On November 16, 2002, certain undersea electric transmission cables
owned by the Long Island Power Authority, or LIPA, and Connecticut Light and
Power Company, or CL&P, were allegedly damaged and/or destroyed as a result of
an allision with an anchor deployed by the
17
DSV Mr. Sonny, a work vessel owned and operated by a subcontractor taking part
in the construction of the Eastchester Extension. In a letter dated January 8,
2003, attorneys for LIPA and CL&P advised that LIPA and CL&P intend to hold
Horizon Offshore Contractors, Inc. (the Partnership's general marine
contractor), Thales Geo Solution Group, Ltd. (Horizon's subcontractor), owners
of DSV Mr. Sonny, the Partnership and IPOC jointly and severally liable for the
full extent of their damages, including emergency response costs, repair of the
electrical cables, loss of use and disruption of services to customers, and any
other damages of whatever nature arising from or related to the incident. LIPA
and CL&P estimate that repair costs will be $33.8 million. In addition, the
Partnership has been informed that the Town of Huntington, New York, may assert
a claim against the Partnership alleging violations of certain municipal
ordinances based on a claim that dielectric fluid was released from the cable as
a result of this incident.
Under the terms of the construction contract between Horizon and the
Partnership, Horizon is required to indemnify the Partnership for Horizon's
negligence associated with the construction of the Eastchester Extension.
Pursuant to the contract, Horizon named the Partnership as an additional named
insured under Horizon's policies of insurance. The Partnership understands that
the Partnership is covered under such policies to the extent that Horizon has
assumed the liabilities under the contract with the Partnership. In any event,
the Partnership believes it is adequately insured by its own insurers.
Therefore, based on its initial investigation, the Partnership's management
believes that this matter will not have a material adverse effect on the
Partnership's financial condition or results of operations.
On February 27, 2003, the New York Power Authority, or NYPA, informed
the Partnership that one of four cables that comprise its Y-49 facility, which
is a 600 megawatt undersea electrical power interconnection between Westchester
County and LIPA's transmission system at Sands Point, New York, allegedly
sustained damage causing a rupture and leakage of dielectric fluid. NYPA has
suggested that the damage to the Y-49 cables may have been caused by an anchor
of Horizon's pipeline lay barge, Gulf Horizon, while constructing the
Eastchester Extension. The Partnership is a party to an agreement with NYPA
which provides, among other things, that in the event of damage to Y-49 cables
resulting from the Partnership's or its contractor's negligence, acts, omissions
or willful misconduct, the Partnership will indemnify NYPA for repair costs and
the costs of replacement electrical capacity while the Y-49 cables are out of
service, subject to NYPA's duty to mitigate damages.
At this time, NYPA has not commenced litigation against the Partnership
or otherwise made a specific written claim for specified damages against the
Partnership as a result of this incident. The Partnership is currently
investigating the incident and evaluating its rights, obligations and
responsibilities relating thereto. Given the preliminary stage of this matter,
at this time, the Partnership is unable to assess the likelihood of an
unfavorable outcome and/or the amount or range of loss, if any, in the event of
an unfavorable outcome. Under the terms of the construction contract between
Horizon and the Partnership, Horizon is required to indemnify the Partnership
for Horizon's negligence associated with the construction of the Eastchester
Extension. Pursuant to the contract, Horizon named the Partnership as an
additional named insured under their policies of insurance. The Partnership
understands that the Partnership is covered under such policies to the extent
that Horizon has assumed the liabilities under the
18
contract with the Partnership. The Partnership is currently investigating the
applicability of all available insurance coverage.
The Partnership is a party to various other legal matters incidental to
its business. However, the Partnership believes that the outcome of these
proceedings will not have a material adverse effect on the Partnership's
financial condition or results of operations. See Note 7 to the Consolidated
Financial Statements appearing elsewhere in this annual report.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Partnership has not submitted any matters to the vote of its
security holders.
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Partnership does not have any publicly-traded common equity.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and with the Partnership's financial statements, including the notes
thereto, appearing elsewhere in this annual report. The income statement,
balance sheet and cash flow data for the years ended December 31, 2002, 2001,
2000, 1999 and 1998 have been derived from the Partnership's financial
statements, which have been audited by PricewaterhouseCoopers LLP, independent
public accountants.
Year ended December 31,
-----------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(In thousands of dollars, except ratios)
Income Statement Data:
Operating revenues................... $126,320 $128,270 $127,234 $123,919(1) $140,371
Operating expenses:
Operation and maintenance........ 26,112 22,108 21,119 21,534 21,703
Depreciation and amortization.... 23,684 23,847 23,609 21,976 29,795
Taxes other than income taxes.... 11,206 10,953 11,156 11,449 10,390
--------- --------- --------- --------- ----------
Total operating expenses....... 61,002 56,908 55,884 54,959 61,888
Operating income..................... 65,318 71,362 71,350 68,960 78,483
Other income and (expenses)......... 2,708 1,829 1,824 1,419 6,758(2)
--------- --------- --------- ---------- ----------
Income before interest charges and taxes 68,026 73,191 73,174 70,379 85,241
Net interest expense............. 25,148 28,067 31,139 30,621 32,476
--------- --------- --------- --------- ---------
Income before taxes.................. 42,878 45,124 42,035 39,758 52,765
Provisions for taxes(3).......... 16,911 18,275 17,083 15,580 20,788
--------- --------- --------- --------- ---------
Net income........................... $ 25,967 $ 26,849 $ 24,952 $ 24,178 $ 31,977
-------- -------- -------- -------- --------
Cash Flow Data:
19
Net cash from operating
activities....................... $ 68,782 $ 77,265 $ 57,181 $ 57,961 $ 83,899
Capital expenditures................. $109,433 $36,340 $8,268 $7,718 $14,172
Balance Sheet Data
(at End of Period):
Net property, plant and equipment $621,475 $533,219 $520,172 $534,806 $548,832
Total assets......................... $689,385 $591,745 $584,368 $594,851 $606,870
Long-term debt, including
current maturities............... $407,222 $366,666 $388,889 $336,664 $365,388
Partners' capital.................... $232,073 $190,764 $169,423 $227,388 $212,630
- ------------------
(1) Total revenues decreased in 1999 compared to 1998 due to the implementation
of a rate reduction.
(2) Includes settlement income for releasing a shipper from its remaining
long-term firm reserved transportation service contract.
(3) The payment of income taxes is the responsibility of partners of the
Partnership. The Partnership's approved rates, however, include an
allowance for taxes (calculated as if it was a corporation) and the FERC
requires the Partnership to record such taxes in its partnership records to
reflect the taxes payable by its partners as a result of the Partnership's
operations. These taxes are recorded without regard to whether each partner
can utilize its share of the Partnership's tax deductions. The
Partnership's rate base, for rate-making purposes, is reduced by the amount
equivalent to accumulated deferred income taxes in calculating the required
return.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Overview
The Partnership owns and operates a 375-mile interstate natural gas
transmission pipeline from the Canada-United States border near Waddington, New
York to South Commack, Long Island, New York. The Partnership provides service
to local gas distribution companies, electric utilities and electric power
generators, as well as marketers and other end-users, directly or indirectly, by
connecting with pipelines and exchanges throughout the northeastern United
States. The Partnership is exclusively a transporter of natural gas in
interstate commerce and operates under authority granted by the FERC. The
Partnership commenced full operations in 1992, creating a link between markets
in the states of Connecticut, Massachusetts, New Hampshire, New Jersey, New York
and Rhode Island, and western Canada natural gas supplies. The Partnership's
pipeline system connects at four locations with three interstate pipelines and
also connects with the pipeline system of TransCanada PipeLines Limited at the
Canada-United States border near Waddington, New York.
On April 19, 2002, the Partnership began constructing its
Eastchester/New York City extension (the "Eastchester Extension"), consisting of
an addition to its pipeline system of approximately 36 miles of 24-inch diameter
pipe, which will extend from the Partnership's existing mainline at Northport in
Suffolk County, New York mostly through the navigable waters of the Long Island
Sound and the East River to Hunts Point in Bronx County, New York. At Hunts
Point, the extension of the Partnership's mainline will form an interconnection
with the New York Facilities Group. As part of the Eastchester Extension, the
Partnership is also
20
building two new compressor stations in Dover, New York and Boonville, New York.
A portion of the upstream Eastchester Extension facilities have been placed into
service.
Construction of the Long Island Sound portion of the Eastchester
Extension commenced in October 2002. As a result of delays in obtaining certain
construction authorizations and permits and delays related to construction
incidents, the projected in-service date of the entire Eastchester Extension is
now the late summer or early fall of 2003, and management believes that final
project construction costs will be at least $250.0 million, rather than the
$210.0 million in project costs estimated during the FERC's certification
process and will likely reduce the Partnership's initial margins that were
anticipated when the project application was filed with the FERC. See Note 7 to
the Consolidated Financial Statements included elsewhere in this annual report.
Results of Operations
The components of Operating Revenues and Volumes Transported for the
past three years are provided in the following table:
Year ended
Revenues and Volumes Transported December 31,
--------------------------------
2002 2001 2000
---- ---- ----
Revenues (dollars in millions)
Long-term firm reserved service $114.8 $119.1 $116.3
Short-term firm (1) 4.1 5.5 4.7
Interruptible/other (1) 7.4 3.7 6.2
--- ---- ---
Total revenues $126.3 $128.3 $127.2
Volumes Transported
(millions of dekatherms)
Long-term firm reserved service 300.7 281.8 292.1
Short-term firm (1) 11.4 15.7 25.3
Interruptible/other (1) 32.3 20.6 30.7
---- ---- ----
Total volumes transported 344.4 318.1 348.1
(1) Short-term represents firm service contracts of less than one year. Other
revenue includes deferred asset surcharges, park and loan service revenue
and marketing fees.
Revenues and Expenses
Revenues. The Partnership receives revenues under long-term firm
reserved transportation service contracts with shippers in accordance with
service rates approved by the FERC. The Partnership's firm revenues are
primarily derived from long-term contracts and are not directly affected by
fluctuations in volumes. The Partnership also has interruptible transportation
service revenues which, although small relative to overall revenues, are at the
margin and thus can have a significant impact on its net income. Interruptible
transportation service revenues include short-term firm reserved transportation
service contracts of less than one-year terms as well as standard interruptible
transportation service contracts. While it is common for pipelines to have some
form of required revenue sharing of their interruptible
21
transportation service revenues with long-term firm reserved service shippers,
the Partnership does not. However, the Partnership cannot assure that this will
be the case in the future.
During the latter part of 1999, the Partnership held negotiations with
its shippers, which led to the settlement of certain remaining issues from
previous rate cases, and which received FERC approval on February 10, 2000. The
settlement provides for a schedule of rate reductions through the year 2003,
generally precludes additional rate cases during this period initiated by the
Partnership or any settling party and resolves all rate matters outstanding from
the Partnership's previous two rate cases. The settlement had no impact on 2000
income. The first rate reduction was implemented January 1, 2001. The settlement
had a negative revenue impact of $2.4 million in 2001 and $6.1 million in 2002,
and is expected to have a negative revenue impact of $3.6 million in 2003, based
upon long-term firm reserved transportation contracts in effect as of December
31, 2002.
Total revenues for 2002 were $126.3 million, a decrease of $2.0
million from 2001 revenues. Long-term firm revenues for 2002 decreased $4.3
million from 2001 primarily due to a rate decrease of $.024/Dth. The rate
decrease resulted in a $6.1 million decrease in long-term firm revenues for
2002, which was partially offset by the addition of new long-term firm
contracts. Short-term firm revenues for 2002 decreased $1.4 million from 2001
while interruptible/other revenues increased $3.7 million to $7.4 million over
2001 levels due primarily to a shift in demand for services from short-term firm
to interruptible.
Despite the 2001 rate decrease of $0.01/Dth, long-term firm revenues
for 2001 increased $2.8 million, from $116.3 million in 2000 to $119.1 million,
largely as a result of the addition of a power plant contract to the
Partnership's system in November 2000, as well as additional winter firm
contracts added in December 2000. Short-term firm revenues increased $0.8
million, from $4.7 million in 2000 to $5.5 million in 2001, despite a decrease
in volumes transported, primarily due to higher peak-period pricing in 2001.
Interruptible/other revenues decreased $2.5 million, from $6.2 million in 2000
to $3.7 million in 2001, due to warmer temperatures and competitive alternative
fuel pricing, as evidenced by the decrease in volumes in 2001 as compared to
2000.
Operation and Maintenance Expense. Operation and maintenance expense
includes operating, maintenance and administrative expenses for the
Partnership's corporate office in Shelton, Connecticut and field support for the
mainline, metering and compression facilities. Operation and maintenance expense
for 2002 increased $4.0 million over 2001 to $26.1 million primarily due to a
$2.2 million expense related to the Partnership's investment in its Eastern Long
Island Project, which has been withdrawn from the FERC certification process, as
well as increased payroll, benefit, outside service and insurance costs.
Operation and maintenance expenses increased 4.7%, from $21.1 million
in 2000 to $22.1 million in 2001, primarily due to increased payroll and
benefits expense, partially offset by a reduction in outside services employed.
In January 2001, the Partnership assumed responsibility for operating and
maintenance activities related to its pipeline system, which it had previously
contracted to a third-party. This change contributed to the increase in payroll
and benefits expense and the decrease in the cost of outside services employed.
22
Other Income and Expenses. Other income includes certain investment
income and the net of income and expense adjustments not recognized elsewhere.
Interest income decreased approximately $1.0 million to $0.4 million in 2002
compared to 2001 primarily due to a decrease in the interest rate realized from
investments as well as lower average cash balances during 2002. Interest income
decreased approximately $0.8 million to $1.4 million in 2001 compared to 2000
primarily due to a decrease in the interest rate realized from investments as
well as lower average cash balances during 2001.
Allowance for equity funds used during construction increased $1.9
million to $2.3 million in 2002 due primarily to the Partnership's expenditures
for the Eastchester Extension. Allowance for equity funds used during
construction increased $0.3 million to $0.4 million in 2001 due primarily to
preliminary expenditures for the Eastchester Extension.
Interest Expense. Interest expense decreased $0.8 million to $27.9
million in 2002 compared to 2001, primarily due to a lower average long-term
debt balance due to scheduled debt repayments and lower interest rates on
floating rate debt during the first half of 2002, partially offset in the latter
half of 2002 by an increase in the Partnership's average debt balance,
reflecting the Partnership's $170.0 million bond offering completed in August
2002. See Note 3 to the Consolidated Financial Statements included elsewhere in
this annual report.
Interest expense decreased $2.5 million to $28.7 million in 2001
compared to 2000, primarily due to a lower average long-term debt balance due to
scheduled debt repayments and lower interest rates on floating rate debt in the
latter half of 2001. This decrease was partially offset by an increase of
interest expense in the first half of 2001, reflecting an increase in average
debt balance due to the long-term debt refinancing, which closed May 30, 2000.
See Note 3 to the Consolidated Financial Statements included elsewhere in this
annual report.
Allowance for borrowed funds used during construction increased $2.1
million to $2.7 million in 2002 due primarily to the Partnership's expenditures
for the Eastchester Extension. Allowance for borrowed funds used during
construction increased $0.6 million to $0.7 million in 2001 due primarily to
preliminary expenditures for the Eastchester Extension.
Income Taxes. Provision for taxes decreased $1.4 million to $16.9
million in 2002 compared to 2001 due primarily to a decrease in taxable income.
Provision for taxes increased $1.2 million to $18.3 million in 2001 compared to
2000 due primarily to an increase in taxable income.
Critical Accounting Policies and Estimates
The Partnership's discussion and analysis of its financial condition,
results of operations and cash flows are based upon the Partnership's
consolidated financial statements, which have been prepared in accordance with
accounting principles generally accepted in the United States of America, or
GAAP. The preparation of these consolidated financial statements required
management to make estimates and judgments that affect the reported amount of
assets and liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities at the date of the consolidated financial
statements. Actual results may differ from these estimates under different
assumptions or conditions.
23
Critical accounting policies and estimates are defined as those that
are reflective of significant judgment and uncertainties, and potentially may
result in materially different outcomes under different assumptions and
conditions. The Partnership believes that its accounting policies and estimates
that are most critical to the reported results of operations, cash flows and
financial position are described below.
Regulatory accounting
The Partnership follows accounting policies prescribed by GAAP and the
FERC. As a rate-regulated Partnership, the Partnership is subject to the
Financial Accounting Standards Board ("FASB") Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation". The application of SFAS 71 results in differences in the timing of
recognition of certain revenues and expenses from that of other businesses and
industries. The Partnership's gas transmission business remains subject to
rate-regulation and continues to meet the criteria for application of SFAS 71.
This ratemaking process results in the recording of regulatory assets based on
current and future cash inflows. Regulatory assets represent incurred costs that
have been deferred because they are probable of future recovery in customer
rates. As of December 31, 2002 and 2001, the Partnership recorded regulatory
assets of $15.7 million and $15.1 million, respectively. The Partnership
continuously reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. The Partnership expects to fully recover
these regulatory assets in its rates. If future recovery of costs ceases to be
probable, the Partnership would be required to charge these assets to current
earnings. However, impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
Derivatives and hedging
The Partnership utilizes derivative contracts to hedge interest rate
risk associated with the Partnership's existing variable rate debt, and to hedge
the net proceeds of new fixed rate debt. SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities", as amended, requires that the Partnership
document its hedging strategies and estimates of hedge effectiveness prior to
initiating a hedge, as well as continuing to assess hedge effectiveness for the
life of the hedging instrument. Currently, the Partnership has two interest rate
swaps outstanding with a total notional amount of $36.1 million, and a fair
value of ($2.8) million, net of taxes. The Partnership records the market value
of these interest rate swaps on its financial statements as a component of Other
Comprehensive Income (Partners' Equity) and Other Non-current Liabilities.
Contingent liabilities
The Partnership establishes reserves for estimated loss contingencies
when it is management's assessment that a loss is probable and the amount of the
loss can be reasonably estimated. Revisions to contingent liabilities are
reflected in income in the period in which different facts or information become
known or circumstances change that affect the previous assumptions with respect
to the likelihood or amount of loss. Reserves for contingent liabilities are
based upon management's assumptions and estimates, advice of legal counsel or
other third parties regarding the probable outcome of the matter. Should the
outcome differ from the
24
assumptions and estimates, revisions to the estimated reserves for contingent
liabilities would be required. See Note 7 to the Consolidated Financial
Statements included elsewhere in this annual report for information about
regulatory, judicial and business developments that cause operating and
financial uncertainties.
Liquidity and Capital Resources
The Partnership's primary source of financing has been cash flow from
operations, its May 2000 offering of $200.0 million of senior notes, and its
August 2002 offering of $170.0 million of senior notes and bank borrowings. The
Partnership's ongoing operations will require the availability of funds to
service debt, fund working capital, and make capital expenditures on the
Partnership's existing facilities and expansion projects.
Net cash provided by operating activities decreased to $68.8 million in
2002 compared to $77.3 million in 2001, partially due to an increase in debt
issuance costs associated with the financing completed on August 14, 2002
related to the Eastchester Extension, and more fully described below. Net cash
provided by operating activities increased to $77.3 million in 2001 compared to
$57.2 million in 2000, due to a change in the timing of interest payments and
amounts capitalized during the refinancing of the Partnership's debt, which
closed May 30, 2000, as well as increased accounts payable due to the
Eastchester Extension and increased net income. Net cash flow related to
financing activities increased by $84.8 million in 2002, as compared to 2001,
due to the Eastchester Extension financing. No new borrowings were made in 2001.
Net cashflow used for financing activities decreased from 2000 to 2001 due
primarily to the transactions surrounding the refinancing of debt in May 2000.
On August 14, 2002, the Partnership issued $170.0 million of senior
unsecured notes that mature on October 31, 2027. The proceeds from the sale of
the notes were used to repay a portion of the first tranche of term loans under
the Partnership's amended credit agreement. This agreement provides for
borrowings from time to time against a second tranche of term loans in an
aggregate amount not to exceed $120.0 million, which, with cash from operations,
will be used to finance the remaining construction of the Eastchester Extension,
an additional expansion at Athens and for general corporate purposes. As of
December 31, 2002, the debt outstanding under our amended credit agreement was
$37.2 million.
On August 9, 2000, the Partnership entered into an interest rate swap
agreement to hedge a portion of the interest rate risk on its credit facilities.
The interest rate swap agreement terminates on the last business day in May
2009. Under its terms, the Partnership agreed to pay a fixed rate of 6.82% on an
initial notional amount of $25.0 million, which is being amortized during the
term of the interest rate swap agreement, in return for payment of a floating
rate of 3-month LIBOR on the amortizing notional amount. The Partnership also
agreed to grant an option to the swap counter-party to enter into an additional
interest rate swap agreement. The option was exercised on December 26, 2000 with
a termination date on the last business day in May 2009. This additional
interest swap agreement has the same fixed and floating rate terms as the
initial interest rate swap agreement and is for an initial notional amount of
$24.3 million, which is being amortized during the term of the additional
interest rate swap agreement. The two interest swap agreements were amended on
August 14, 2002 to match the term of the Partnership's amended credit agreement,
which was also completed on that date. As of
25
December 31, 2002 and December 31, 2001, the aggregate notional principal amount
of these two swaps was $36.1 million and $41.7 million, respectively. The fair
value of these interest rate swaps, net of taxes at December 31, 2002 and
December 31, 2001, was ($2.8) million and ($1.8) million, respectively.
On June 19, 2002, the Partnership entered into forward interest rate
agreements with two major financial institutions in the aggregate notional
amount of $120.0 million. On July 31, 2002, the Partnership entered into
additional forward interest rate agreements with the same institutions in the
aggregate notional amount of $50.0 million. The forward interest rate agreements
were entered into to hedge the underlying interest rate for the unsecured senior
notes which the Partnership issued on August 14, 2002. Upon the closing of the
financing transaction, the forward interest rate agreements were terminated and
the Partnership paid $5.8 million to settle those contracts. The Partnership has
deferred and is amortizing this amount over the life of the senior notes.
The Partnership also is party to a $10.0 million, 364-day, variable
rate revolving line of credit to support working capital requirements. As of
December 31, 2002 and December 31, 2001, there were no borrowings outstanding
under this facility.
Capital expenditures for 2002 were $109.4 million, compared to $36.3
million in 2001, reflecting primarily the increased construction activity
related to the Eastchester Extension during the year. In addition, there were
expenditures related to a meter station and interconnect, a compressor station,
general plant purchases and other miscellaneous projects. Capital expenditures
in 2001 also consisted of expenditures relating to the Eastchester Extension, as
well as general plant purchases and other minor projects, including a project
currently in the development stage that involves a possible expansion of the
pipeline to access additional gas supplies from the west. In 2000, capital
expenditures of $8.3 million were restricted to some post-completion costs for
the original Athens compressor station, preliminary engineering costs relating
to the Eastchester Extension, as well as general plant purchases and other minor
projects.
Total capital expenditures for 2003 are estimated to be approximately
$126.0 million, including approximately $106.0 million for the Eastchester
Extension. The remaining capital expenditures planned for 2003 are primarily for
the purchase of land for a compressor site, a meter station and interconnect,
and various general plant purchases. The Partnership expects to fund its 2003
capital expenditures through additional borrowings under its existing credit
facilities, and internal sources, including cash from operations and increased
equity contributions (by limiting distribution to partners) in accordance with
the partnership agreement. The Partnership's management makes recommendations to
the partnership management committee regarding the amount and timing of
distributions to partners. The amount and timing of distributions is subject to
internal cash requirements for construction, financing and operational
requirements. Distributions and cash calls require the approval of the
management committee. There were no cash distributions to partners during 2002.
Total cash distributions to partners of $22.0 million and $100.0 million were
made during 2001 and 2000, respectively. The larger distribution in 2000 was a
result of the May 2000 long-term debt refinancing.
26
Off-Balance Sheet Transactions
At December 31, 2002, the Partnership had no off-balance sheet
transactions, arrangements, or other relationships with unconsolidated entities
or persons that would adversely affect liquidity, availability of capital
resources, financial position, or results of operations.
Contractual Obligations
The Partnership is committed to making payments in the future on two
types of contracts: long-term debt and leases. The Partnership has no
off-balance sheet debt or other such unrecorded obligations and has not
guaranteed the debt of any other party. Below is a schedule of the future
payments the Partnership was obligated to make based on agreements in place as
of December 31, 2002.
Total 2003 2004 2005 2006 2007 Thereafter
----- ---- ---- ---- ---- ---- ----------
(in thousands of dollars)
Long-Term Debt $407,200 $22,200 $15,000 -- -- -- $370,000
Operating Leases 11,100 1,000 900 800 800 800 6,800
-------- ------- ------- ---- ---- ---- --------
Total
Contractual
Obligations $418,300 $23,200 $15,900 $800 $800 $800 $376,800
======== ======= ======= ==== ==== ==== ========
New Accounting Standards
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations", which provides the accounting requirements for
retirement obligations associated with tangible long-lived assets. SFAS 143 is
effective for fiscal years beginning after June 15, 2002. The Partnership does
not expect the implementation of SFAS 143 to have a material impact on the
Partnership's financial position or results of operations.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". SFAS 144 supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of" and the accounting and reporting provisions of Accounting
Principles Board Opinion No. 30, "Reporting the Results of Operations -
Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions," related to the disposal of a
segment of a business. SFAS 144 establishes a single accounting model for
long-lived assets to be disposed of by sale and resolves significant
implementation issues related to SFAS 121. SFAS 144 is effective for fiscal
years beginning after December 15, 2001. Implementation of this standard has not
had a material impact on the Partnership's financial position or results of
operations.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities", which nullifies Emerging Issues
Task Force Issue No. 94-3,
27
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)". The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002. Implementation of this standard is not
expected to have a material impact on the Partnership's financial position or
results of operations.
FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others" is effective for the year ended December 31, 2002. FASB Interpretation
No. 45 elaborates on the disclosures to be made by a guarantor about its
obligations under certain guarantees it has issued. It also clarifies that a
guarantor is required to recognize, at the inception of a guarantee, a liability
for the fair value of the obligation undertaken in issuing the guarantee. The
initial recognition and initial measurement provisions of FASB Interpretation
No. 45 are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002, however the disclosure requirements are effective with
respect to the 2002 financial statements contained in this annual report. The
application of this Interpretation is not expected to materially impact the
financial position, results of operations, or cash flows of the Company.
Other
The Partnership's transmission activities are subject to regulation by
the FERC under the Natural Gas Act and under the Natural Gas Policy Act of 1978
because the Partnership owns and operates an interstate natural gas pipeline
system that provides interstate transmission services. As a result, the
Partnership's rates and charges for natural gas transportation, the terms and
conditions of the services it offers, the extension, enlargement or abandonment
of its jurisdictional facilities, and its accounting, among other things, are
all subject to such regulation.
The Partnership is also subject to the National Environmental Policy
Act and other federal and state legislation regulating the environmental aspects
of its business. The Partnership believes that it is in substantial compliance
with existing environmental requirements. The Partnership believes that, if
expenditures were required in the future to meet applicable standards and
regulations, the FERC would grant requisite rate relief so that, for the most
part, such expenditures and a return thereon would be permitted to be recovered.
Based on current information, the Partnership believes that compliance with
applicable environmental requirements is not likely to have a material effect
upon its earnings or competitive position.
The majority of the Partnership's plant and equipment and inventory is
subject to ratemaking treatment, and under current FERC practices, recovery of
increased costs for replacing facilities due to inflation is limited to
prudently incurred, historical costs as established in the prior rate
proceeding. Under current FERC practice, amounts in excess of historical cost
are not recoverable between rate proceedings, leading to a delay between
incurrence of costs and their recovery. However, the Partnership believes that
in future rate proceedings it will be allowed to recover and earn a return based
on increased actual costs incurred when existing facilities are replaced and new
facilities are placed in service. Cost-based regulation, along with competition
and other market factors, limit the Partnership's ability to take inflation into
account in pricing services and products.
28
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of changes in value of a financial
instrument, derivative or non-derivative, caused by fluctuations in interest
rates and prices. The following discussion of the Partnership's risk management
activities includes forward-looking statements that involve risks and
uncertainties. Actual results could differ materially from those contemplated in
the forward-looking statements. The Partnership handles market risks in
accordance with established policies, which may include various derivative
transactions.
The financial instruments held or issued by the Partnership are for
purposes other than trading or speculation. The Partnership is exposed to risk
resulting from interest rate changes on its variable-rate debt. The Partnership
uses interest rate swap agreements to manage the risk of increases in certain
variable rate issues. It records amounts paid and received under those
agreements as adjustments to the interest expense of the specific debt issues.
The Partnership believes that there is no material market risk associated with
these agreements. See Note 3 to the Consolidated Financial Statements included
elsewhere in this annual report. As of December 31, 2002, the Partnership had
$37.2 million of variable-rate debt outstanding. Holding other variables
constant, including levels of indebtedness, a one- percentage point increase in
interest rates would impact pre-tax earnings by less than $0.1 million.
The Partnership's pension plan assets are made up of equity and fixed
income investments. Fluctuations in those markets could cause the Partnership to
recognize increased or decreased pension income or expense.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial statements are contained on pages F-2 through F-24 of this
report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
29
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP
Executive Officers
The following table sets forth the names, ages and positions of the
executive officers of IPOC.
Name Age Position
---- --- --------
Craig R. Frew 52 President*
Paul Bailey 56 Vice President and Chief Financial Officer
Jeffrey A. Bruner 44 Vice President, General Counsel and Secretary
Herbert A. Rakebrand III 46 Vice President, Marketing and Transportation
David J. Warman 45 Vice President, Engineering and Operations
Craig R. Frew is President of IPOC. Mr. Frew has 30 years of experience
in the natural gas industry. Mr. Frew joined TransCanada PipeLines Limited in
1976 and transferred to IPOC in 1994 while TransCanada PipeLines Limited was the
operator of the Partnership's pipeline system. With TransCanada PipeLines
Limited, Mr. Frew held a number of senior management positions including the
position of President of its wholly owned subsidiary, Western Gas Marketing
Limited, from 1989 to 1993. Mr. Frew currently serves on the board of directors
of the Interstate Natural Gas Association and is Chairman and member of the
board of directors of the New England Gas Association.
Paul Bailey is Vice President and Chief Financial Officer of IPOC. Mr.
Bailey has 20 years of experience in the natural gas industry and an additional
14 years in the electric industry. Mr. Bailey joined TransCanada PipeLines
Limited in 1982 and transferred to IPOC in 1992 while TransCanada PipeLines
Limited was the operator of the Partnership's pipeline system. With TransCanada
PipeLines Limited, Mr. Bailey held a variety of senior management positions in
the accounting and finance areas of the company. From 1968 to 1982 Mr. Bailey
was employed by Ontario Hydro and held a number of positions in the accounting
and financial planning departments.
Jeffrey A. Bruner is Vice President, General Counsel and Secretary of
IPOC. Mr. Bruner joined IPOC in 1992. Prior to joining IPOC he was with Transco
Energy Company for eight years where he held various positions in the legal
department, including the position of General Attorney in charge of the legal
department for Transcontinental Gas Pipe Line Corporation, an interstate
pipeline affiliate of Transco Energy.
Herbert A. Rakebrand III is Vice President of Marketing and
Transportation of IPOC. Mr. Rakebrand has 23 years of experience in the natural
gas industry. Mr. Rakebrand assisted in establishing IPOC's transportation
department, having joined IPOC in 1991, prior to the pipeline
- --------------------
* Mr. Frew has indicated that he will be resigning as President of the
Partnership in April 2003 and the Partnership expects to announce a new
President at that time.
30
being placed in service. From 1980 to 1991, Mr. Rakebrand was employed by the
Long Island Lighting Company where he held various positions in the gas
engineering and gas supply departments.
David J. Warman is Vice President of Engineering and Operations of
IPOC. Mr. Warman joined TransCanada PipeLines Limited in 1982 and transferred to
IPOC in 1990 while TransCanada PipeLines Limited managed the construction of the
Partnership's pipeline system. With TransCanada PipeLines Limited, Mr. Warman
held a number of positions in the engineering area, in particular pipeline
design, materials engineering, pipeline construction and project management.
Management Committee Composition
The representatives on the Partnership's management committee are
employed at affiliates of partners of the Partnership. The following table sets
forth the names of the representatives on the Partnership's management
committee, the names of the affiliates of the partners at which they are
employed and the names of relevant partners.
Name Age Affiliate at Which Employed Partner Represented
---- --- --------------------------- -------------------
Georgia B. Carter 45 Dominion Resources, Inc. Dominion Iroquois, Inc.
Michael I. German 52 Energy East TEN Transmission Company
Richard A. Rapp 53 KeySpan Energy Corporation NorthEast Transmission
Company, LILCO Energy
Systems, Inc.
Joseph P. Shields 45 New Jersey Natural Gas Company NJNR Pipeline Company
Peter Lund 44 PG&E National Energy Group JMC-Iroquois, Inc.
Iroquois Pipeline
Investment, LLC
Paul MacGregor 46 TransCanada Pipelines Ltd. TransCanada Iroquois
Ltd./TCPL Northeast Ltd.
Georgia B. Carter is Managing Counsel for Gas Transmission and Storage
for Dominion Resources Inc. Prior to this position, she served as Senior Counsel
for Dominion Resource Services, Inc. Ms. Carter joined Consolidated Gas Supply
Company as an attorney in 1983, became General Manager Marketing in 1993, and
was promoted to Vice President, Marketing and Customer Services in 1996.
Subsequent to the merger of Dominion Resources, Inc. and Consolidated Natural
Gas Company in January 2000, she held the same position until a reorganization
in late 2001.
31
Michael I. German is Senior Vice President of the Energy East
Management Corporation, and President, CEO and board representative for the
companies within The Energy Network and Energy East Enterprises. He is
responsible for growth and business development across these businesses. Mr.
German also represents Energy East on the management committee for Iroquois Gas
Transmission System. Prior to this, Mr. German was President and COO of NYSEG,
and before joining NYSEG was the AGA's Sr. Vice President. He also worked for
the U.S. Department of Energy and the Energy Research and Development
Administration. Mr. German is a member of the Washington, DC Bar Association.
Richard A. Rapp is Senior Vice President of KeySpan Energy Supply, Inc.
Until March 2003, he was the Vice President and Deputy General Counsel of
KeySpan Corporation. Mr. Rapp served in various attorney and supervisory
positions in KeySpan's Legal Department, beginning in August 1984.
Joseph P. Shields is a Senior Vice President of New Jersey Natural Gas
Company, a subsidiary of New Jersey Resources Corporation. Since 1983, he has
served as Manager, Director and Vice President of Gas Supply in New Jersey
Natural Gas Company. Prior to joining New Jersey Natural Gas Company, he was
employed by the State of New Jersey Board of Public Utilities. He joined the
management committee of the Partnership as of August 16, 2000.
Peter Lund is the Vice President-Pipeline Marketing and Development of
PG&E National Energy Group. He has led the commercial aspects of PG&E's
interstate pipeline operations since becoming Vice President of PG&E Gas
Transmission - Northwest in 1995. Before joining PG&E Gas Transmission Northwest
in 1988, Mr. Lund worked as a resource analyst for Pacific Gas and Electric
Company and as a mineral exploration geologist for various firms. In addition,
Mr. Lund is a board member and chair-elect of the Western Energy Institute, and
a board member and former president of the Northwest Gas Association. Mr. Lund
has been a member of the management committee of the Partnership since 1999.
Paul F. MacGregor has served as Vice President-East Business
Development for TransCanada Pipelines Ltd. since January 2001. Mr. MacGregor is
responsible for the business development activities of TransCanada's
non-regulated pipeline services and investments. In addition, he oversees
TransCanada's ownership interests in several of its Canadian and U.S. pipeline
investments. Mr. MacGregor joined TransCanada in 1981 and since then he has held
various positions including in Facilities Planning and Vice President, North
American Pipeline Investments for TransCanada's energy transmission business
unit. Mr. MacGregor has been a member of the management committee of the
Partnership since 1999.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table. The following summary compensation table
sets forth information regarding compensation for fiscal years 2002, 2001 and
2000 paid to the President and each of the four other most highly compensated
executive officers of IPOC. All compensation to the executive officers is paid
by IPOC and reimbursed by the Partnership.
32
Other Annual All Other
Name and Salary Bonus Compensation Compensation
Principal Position Year ($) (1) ($) ($)(2) ($) (3)
------------------ -------- ------- --- ------ -------
Craig R. Frew 2002 $270,169.12 $108,100.00 --- $232,725.00
President 2001 297,231.80 160,000.00 --- 137,347.00
2000 262,058.23 125,000.00 65,598.34 10,500.00
Paul Bailey 2002 $193,089.42 $57,000.00 --- $106,122.20
Vice President and Chief 2001 186,200.04 84,000.00 --- 64,181.70
Financial Officer 2000 184,293.98 55,000.00 72,429.11 9,448.94
Jeffrey A. Bruner 2002 $157,103.91 $39,100.00 --- $59,409.00
Vice President, General 2001 150,000.24 60,000.00 --- 37,180.77
Counsel and Secretary 2000 148,580.38 44,000.00 --- 7,428.98
Herbert A. Rakebrand III 2002 $190,895.76 $54,400.00 --- $79,268.01
Vice President, Marketing 2001 177,107.86 65,000.00 --- 48,668.00
and Transportation 2000 164,588.58 73,000.00 --- 8,089.90
David J. Warman 2002 $144,853.33 $35,000.00 --- $58,584.92
Vice President, 2001 131,257.96 54,000.00 --- 36,162.50
Engineering 2000 126,011.79 37,000.00 --- 6,190.08
and Operations
- -----------------------------
(1) Amounts reported for the 2000, 2001, and 2002 fiscal years, respectively
include salary paid in lieu of vacation for the following: Mr. Frew --
$4,754.25, $3,492.70, and $0; Mr. Bailey, $0, $0, and $3165.40, Mr. Bruner,
$0, $0, and $653.85, Mr. Rakebrand -- $2,788.50, $4,307.70, and $9455.28;
and Mr. Warman -- $2,211.75, $1,657.84, and $4884.93 respectively.
(2) Other Annual Compensation for fiscal year 2000 includes loan forgiveness
and certain personal benefits, including the following for the 2000 fiscal
year: Mr. Frew -- $56,193.64 for loan forgiveness; and Mr. Bailey --
$60,560.18 for loan forgiveness. Other Annual Compensation below the
disclosure thresholds has been omitted.
(3) A portion of the amounts presented in this column represent amounts that
became vested and payable to the named-executive officers under the IPOC
long-term incentive plan on December 31, 2002. The general terms of the
long-term incentive plan are discussed below in a separate section. For
fiscal year 2002, the named executive officers became entitled to receive
the following amounts under the long-term incentive plan: Mr. Frew became
entitled to receive $220,725.00; Mr. Bailey became entitled to receive
$95,647.00; Mr. Bruner became entitled to receive $51,502.00; Mr. Rakebrand
became entitled to receive $69,896.00; and Mr. Warman became entitled to
receive $51,502.00. Another portion of the amounts presented in this column
represent the matching contributions made by IPOC under the Iroquois
Pipeline Operating Company Savings Plan (the "401(k) Plan") and the IPOC
Supplemental 401(k) Savings Plan (the "Supplemental Plan"). Under the
401(k) Plan, which is generally available to all employees, IPOC currently
matches a participant's tax-deferred contributions by an amount equal to
100% of such contribution for each year, up to 5% of the participant's
annual compensation. Under the Supplemental Plan, IPOC currently matches
the tax-deferred contributions by a select group of management or highly
compensated employees in an amount equal to 100% of such contribution for
each year, up to 5% of the participant's annual compensation, less any
matching contributions allocated to the participant's account under the
401(k) Plan. The following contributions were made during the 2000, 2001
and 2002 fiscal years, respectively under the 401(k) Plan: Mr. Frew
received $8,500, $8,500 and $10,000; Mr. Bailey received $8,500, $8,500.00,
and $9,580.70; Mr. Bruner received $7,428.98,
33
$7,582.77 and $7,907.00; Mr. Rakebrand received $8,089.90, $8,500; and
$9,147.50, and Mr. Warman received $6,190.08, $6,564.50, and $7082.92