Back to GetFilings.com
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
--------------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from January 1, 2000 to December 31, 2000.
--------------------
Commission File Number 333-42578
Iroquois Gas Transmission System, L.P.
(Exact name of registrant as specified in its charter)
Delaware 06-1285387
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
One Corporate Drive
Suite 600
Shelton, Connecticut 06484-6211
(Address of principal executive office)
(Zip Code)
(203) 925-7200
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b)
of the Act
None None
(Title of each class) (Name of exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities 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. [ ]
================================================================================
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
Form 10-K Annual Report, for the year ended December 31, 2000
Table of Contents
Page
Special Note regarding Forward-Looking
Statements ....................................................................1
PART I
Item 1 Business .............................................................1
Item 2 Properties ..........................................................15
Item 3 Legal Proceedings ...................................................15
Item 4 Submission of Matters to a Vote of Security Holders .................16
PART II
Item 5 Market for Registrant's Common Equity and Related
Stockholder Matters .................................................16
Item 6 Selected Financial Data .............................................16
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations..................................17
Item 7A Quantitative and Qualitative Disclosures about
Market Risk .........................................................21
Item 8 Financial Statements and Supplementary Data .........................22
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure...............................22
PART III
Item 10 Directors and Executive Officers of the Partnership.................22
Item 11 Executive Compensation..............................................25
Item 12 Security Ownership of Certain Beneficial Owners and
i
Management..........................................................29
Item 13 Certain Relationships and Related Transactions......................30
PART IV
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................................30
Signatures....................................................................33
ii
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains various forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. When used in this annual
report, the words "believes", "anticipates", "expects" and similar expressions
are used to identify forward-looking statements. Such forward-looking statements
are based on current expectations, are not guarantees of future performance and
include assumptions about future market conditions, operations and results. They
are made in reliance on the "safe harbor" provisions of the Private Securities
Litigation Reform Act of 1995. Iroquois Gas Transmission System, L.P. (The
"Partnership") can give no assurance that such expectations will be achieved.
The many factors that could cause actual results to differ materially from those
in the forward-looking statements herein include, but are not limited to:
o future demand and prices for natural gas;
o availability of supplies of Canadian natural gas;
o regulatory, political, legislative and judicial developments,
particularly with regard to regulation by the Federal Energy
Regulatory Commission (the "FERC");
o competitive conditions in the marketplace;
o changes in the receptivity of the financial markets to the
Partnership or other oil and gas credits similar to the
Partnership and, accordingly, the Partnership's strategy for
financing any change in business strategy or expansion.
A discussion of these and other factors which may affect the Partnership's
actual results, performance, achievements or financial position is contained in
the "Risk Factors" section below.
PART I
ITEM 1. BUSINESS
Introduction
Iroquois Gas Transmission System, L.P. is a Delaware limited partnership.
It was formed for the purpose of constructing, owning and operating 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
1
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 with four interstate pipelines and the pipeline system
of TransCanada PipeLines Limited (the "TransCanada System") in eastern Ontario.
The Partnership has more than doubled the amount of gas that flows through its
pipeline system on an annual basis since 1992, while the transportation rates
the Partnership charges have decreased by approximately 39% as a result of FERC
rate reduction orders.
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 the 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. Currently, the Partnership has 36 shippers under
long-term firm reserved transportation service contracts and its pipeline
system's contracted capacity of 1006 thousands of dekatherms per day, or MDth/d,
is fully subscribed. As of December 31, 2000, approximately 88% of the
Partnership's capacity was contracted under firm reserved transportation service
contracts which continue until at least 2011.
The partners and their respective interests in the Partnership are as
follows:
Percentage
Ownership
Ultimate Parent of Partner Name of Partner Interest
- -------------------------- --------------- --------
TransCanada PipeLines TransCanada Iroquois Ltd. 29.0%
Limited TCPL Northeast Ltd. 6.0%
KeySpan Energy NorthEast Transmission 19.4%
Corporation Company
LILCO Energy Systems, Inc. 1.0%
Dominion Resources, Inc. Dominion Iroquois, Inc. 16.0%
The Coastal Corporation(1) ANR Iroquois, Inc. 9.4%
ANR New England Pipeline Co. 6.6%
PG&E Generating Company JMC-Iroquois, Inc. 4.93%
CTG Resources, Inc. TEN Transmission Company 4.87%
New Jersey Resources NJNR Pipeline Company 2.8%
Corporation
- --------------------
2
(1) On January 18, 2000, El Paso Energy Corp. ("El Paso") and The Coastal
Corporation ("Coastal") announced plans for the merger of El Paso and
Coastal. The merger was completed in January of 2001. As a condition of the
merger, the Federal Trade Commission ("FTC") ordered Coastal to divest all
of its interest in the Partnership. The FTC must approve the proposed
buyers. Several of the Partnership's partners have agreed to purchase
Coastal's interest, pending FTC approval.
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.
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 of December 31, 2000 the Partnership had contracts in place to
deliver 1006 MDth/d.
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 19 delivery meters to which the Partnership has primary
rights with a combined capacity of approximately 3.8 million Dth/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 total electronic failure. The Partnership also
delivers gas to the other major natural gas pipelines in the Northeast through
its five interconnections with four interstate pipelines, Algonquin Gas
Transmission Company, Dominion Transmission Corporation, Tennessee Gas Pipeline
Company, and 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
3
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 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 36
shippers. Under the firm reserved transportation service contracts, the pipeline
receives natural gas on behalf of shippers at designated receipt points and
transports the gas on a firm basis up to each shipper's maximum daily quantity.
As of December 31, 2000, approximately 88% of the 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 and the zone within which the gas is shipped. The Partnership is also
authorized by the FERC to enter into "negotiated rate" contracts with shippers
who are provided with a service which varies in some manner from the standard
tariff offering. To date, the Partnership has entered into a limited number of
negotiated rate contracts for short-term firm transportation service.
The Partnership's pipeline system is 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's shippers under firm transportation service contracts
consist of major electric and gas utility companies, marketers, gas producers
and independent electric generating
4
companies. PG&E Corporation, through its affiliates, is the only shipper that
accounted for more than 10% of the Partnership's revenues as of December 31,
2000.
As of December 31, 2000, approximately 70% 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 46% of the pipeline system's volume was under firm reserved
transportation service contract with shippers with a debt rating of "A" or
higher. Such shippers include Bay State Gas Company (28.8 MDth/d), Boston Gas
Company (44.1 MDth/d), Brooklyn Union Gas Company (70.8 MDth/d), New Jersey
Natural Gas Company (40.5 MDth/d), Central Hudson Gas & Electric Corporation
(20.2 MDth/d), ConEd (20.2 MDth/d), Duke Energy Trading & Marketing (94 MDth/d),
KeySpan Gas East Corporation (65.8 MDth/d) and New York State Electric & Gas
Corporation (17.2 MDth/d). Certain of the Partnership's shippers are not rated
by credit rating agencies. Non-rated or non-investment grade rated shippers
accounted for approximately 19% of the pipeline system's volume. The Partnership
has determined under internal credit standards that those shippers or their
guarantors are creditworthy so that they are not required to post credit support
in connection with their transportation service contracts. Approximately 11% 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 or who have made other credit support
arrangements that the Partnership finds satisfactory.
Demand for Transportation Capacity
The Partnership's market, the Northeast, is comprised of approximately 12
million natural gas customers, who account for approximately 19% of all natural
gas customers in the United States. The Northeast has experienced an overall
increase in natural gas demand in the last decade. This demand is expected to
continue to grow by 2-3% per year through 2025. The bulk of the growth in the
Northeast is expected to occur in the electric generation sector, which is
projected to grow by 5-8% per year.
The Partnership is planning an Eastchester/New York City expansion of its
pipeline system consisting of an approximately 33-mile mainline extension
running from the mainline on Long Island near Northport, through the Long Island
Sound to Eastchester, New York. As currently planned, the proposed line would
proceed on land for two miles, connecting with the northern section of ConEd's
gas distribution facilities. In the past, ConEd has experienced reliability
concerns on its system due to its over-dependence on gas supplies currently
entering the western side of its territory. In developing the Eastchester/New
York City expansion, the Partnership is working closely with ConEd to alleviate
these operating concerns. The Partnership believes that because of its location
and ability to utilize Long Island Sound, a means of direct access to the New
York City market can be developed with minimal environmental and land owner or
right-of-way issues. In contrast, other competing proposals must access this
market through congested and expensive areas. On April 28, 2000, the Partnership
filed an application with the FERC pursuant to section 7(c) of the Natural Gas
Act of 1938 (the "Natural Gas Act") for a certificate of public convenience and
necessity to construct and operate the Eastchester/New York City expansion,
requesting a November 2002 in-service date. On December 15, 2000, the
application was amended to reflect a change in the end-point of the
5
Eastchester expansion. On February 22, 2001, the Partnership announced that the
project has been fully subscribed. Under precedent agreements, five project
shippers have agreed to take all of the 230 MDth/d of transportation capacity
proposed to be built. The Eastchester shippers under contract are: Consolidated
Edison Energy, Inc., KeySpan Ravenswood, Inc., Orion Power Holdings, Inc.,
Mirant New York Management, Inc. and Virginia Power Energy Marketing, Inc. A
response from the FERC to the proposed expansion is expected in the second half
of 2001.
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 sizable
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.
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.
6
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". Under the Natural Gas Act
and the Natural Gas Policy Act of 1978, the FERC has jurisdiction over the
Partnership with respect to virtually all aspects of its business, including
transportation of gas, rates and charges, construction of new facilities,
extension or abandonment of service and facilities, accounts and records,
depreciation and amortization policies, the acquisition and disposition of
facilities, the initiation and discontinuation of services, and certain other
matters. The Partnership, where required, holds certificates of public
convenience and necessity issued by the FERC covering its facilities, activities
and services.
The Partnership's rates and charges for transportation in interstate
commerce are subject to regulation by the FERC. FERC regulations and the
Partnership's FERC-approved tariff allow the Partnership to establish and
collect rates designed to give it an opportunity to recover all actually and
prudently incurred operations and maintenance costs of its pipeline system,
including taxes, interest, depreciation and amortization and a regulated equity
return. The FERC has granted the Partnership the authority to negotiate rates
with some of 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.
Rates charged by the Partnership 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, 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 cut 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
7
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.
Regulatory Proceedings. On November 29, 1996, the Partnership submitted a
general rate change application to the FERC, and in its December 31, 1996 order,
known as the suspension order, the FERC permitted the proposed rates to become
effective (with one exception noted below). On July 29, 1998, the FERC issued
its July 1998 order, which modified significant portions of an earlier
administrative law judge's initial decision, resulting in a reduction of the
Partnership's maximum demand rate. On August 28, 1998, the Partnership filed a
request for rehearing of the July 1998 order, and by order issued March 11,
1999, the FERC granted rehearing of one aspect of the July 1998 order and
permitted the Partnership to utilize an equity structure of 35.21% in designing
its rates. On May 10, 1999, the Partnership filed a petition for review of other
aspects of the July 1998 order in the United States Court of Appeals for the
District Court of Columbia Circuit. This case was consolidated with petitions
filed by two of the Partnership's customers on this matter.
In addition to addressing the Partnership's filed rate change application,
the suspension order granted summary disposition on one issue outstanding from
the Partnership's prior rate proceeding. On June 19, 1995, the FERC had approved
a stipulation and consent agreement in the Partnership's prior rate proceeding
which resolved all issues except for the accounting and recovery of legal
defense costs incurred in connection with certain criminal and civil
investigations into the initial construction of the Partnership's pipeline
system. The Partnership sought, and the FERC denied in the suspension under,
rehearing of its orders regarding those legal defense costs in the Partnership's
prior rate proceeding. On April 18, 1997, the Partnership filed a petition for
review of the FERC orders addressing legal defense costs in the United States
Court of Appeals for the District of Columbia. The suspension order directed the
Partnership to remove approximately $11.7 million in plant and associated costs
from its proposed rate base. The Partnership sought rehearing of the suspension
order regarding this issue, which was subsequently denied by the FERC. Following
such denial, on September 3, 1997, the Partnership filed a petition for review
of the suspension order with regard to legal defense costs in the United States
Court of Appeals for the District of Columbia, which the court consolidated with
its earlier case regarding the same issue. On July 21, 1998, the United States
Court of Appeals for the District of Columbia issued a decision reversing the
FERC orders addressing legal defense costs and remanded the matter to the FERC
for further proceedings.
After extensive negotiations with the various parties, on December 17,
1999, the Partnership filed with the FERC an offer of settlement, which shall be
referred to as the rate settlement. By order dated February 10, 2000, the FERC
approved the rate settlement, effectively resolving all remaining issues in the
Partnership's rate proceedings described above. The principal elements of the
rate settlement are:
8
o a reduction in maximum demand rates phased-in over a three-year
period beginning January 1, 2001;
o elimination of the proposed legal defense costs surcharge and
agreement of all parties not to seek recovery of such costs;
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 Section 4 of the
Natural Gas Act prior to January 1, 2004 and no party may file
for reductions in rates pursuant to Section 5 of 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 maximum demand rate
will decrease by $0.0096/Dth effective January 1, 2001, by $0.0240/Dth effective
January 1, 2002; and by $0.0144/Dth effective January 1, 2003 for a total
cumulative reduction of $0.04866/Dth. The rate settlement also provides for
similar reductions in other rates charged by the Partnership. The total
estimated revenue impact of these rate reductions is $2.38 million in 2001,
$5.92 million in 2002 and $3.55 million in 2003 based on 2000 long-term firm
reserved transportation service contracts.
Rulemaking on FERC's Regulation of Transportation Services. On February 9,
2000, the FERC adopted its Order No. 637. The order:
o institutes a two-year waiver of price ceilings on short-term
released capacity (the FERC may later consider a permanent
waiver based on the experience gained through this experiment);
o allows pipelines to make pro forma tariff filings proposing peak
and off-peak rates for short-term services;
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;
9
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.
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.
On May 19, 2000, the FERC adopted Order No. 637-A, which addressed requests
for rehearing of Order No. 637. Order 637-A largely denied rehearing on the
above-referenced Order No. 637 matters, but granted rehearing, in part, to make
clarifying adjustments to the regulations regarding penalties, reporting
requirements and the right-of-first refusal.
While Order No. 637 requires some significant changes in the functioning of
the secondary market for firm capacity, its implementation should not materially
affect the level of revenues the Partnership receives. The Partnership will have
to incur some costs to modify its tariff and information systems to allow it to
comply with Order No.'s 637 and 637-A. However, the Partnership does not expect
these expenditures to be material.
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, which shall be referred to as 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, but the industry, including the Partnership, could be
required to incur
10
additional capital expenditures and increased costs depending upon final
regulations issued by the Department of Transportation under the NGPSA and/or
future pipeline safety legislation.
Environmental Matters
Environmental laws and regulations have changed substantially and rapidly
over the last 20 years, and the Partnership anticipates that there will be
continuing changes. Increasingly strict federal, state or local environmental
restrictions, limitations and regulations have resulted in increased operating
costs for the Partnership, and it is possible that the costs of compliance with
environmental laws and regulations will continue to increase. To the extent that
environmental costs are normal costs of doing business, these costs would be
recoverable under the Partnership's rates through future rate proceedings.
Current Operations. At each of the Partnership's 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 "global" 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 million in fines and penalties and to take certain 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, 2000, IPOC had 102 employees. Pursuant to the
operating agreement, certain field operating and maintenance services were
provided to the Partnership by Tennessee Gas Pipeline Company, which shall be
referred to as Tennessee Gas. As of January 1, 2001, IPOC hired 12 employees,
including several former Tennessee Gas employees, to perform field operations
functions for the Partnership's pipeline system enabling IPOC to now perform its
own field operating and maintenance services.
11
Risk Factors
The Partnership's business involves significant risks and uncertainties
including those described below.
The Partnership may not be able to maintain existing shippers or acquire
new shippers
As of December 31, 2000, approximately 88% of the capacity of the
Partnership's pipeline system was contracted through at least November 1, 2011.
The Partnership cannot give any assurances that it will be able to extend or
replace these contracts at the end of their initial terms. The extension or
replacement of the existing long-term contracts with shippers 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. If these contracts
are not extended or replaced or are terminated the Partnership's cash flows and
ability to service its outstanding senior notes may be 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 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 when they release their firm
reserved capacity to other shippers. As a result, under the FERC-approved rate
structure, the Partnership's profitability will generally depend upon the
continued creditworthiness of the shippers rather than upon the amount of
natural gas transported.
The Partnership's rates are calculated on the basis of the assumed
contracted capacity of 1006 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 economic downturn
affecting the Northeast could impact the ability of some or all of the shippers
to fulfill
12
their obligations under the transportation service contracts. A failure to pay
by any of the shippers would decrease the Partnership's revenues and cash flows
and could have an 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
The Partnership's pipeline system is an interstate natural gas pipeline
subject to regulation as a natural gas company by the Natural Gas Act. As such,
the rates the Partnership can charge its shippers and other terms and conditions
of service are subject to FERC review and the possibility of modification in
rate proceedings. The objective of this rate setting review process is to allow
the Partnership to recover its costs to construct, own, operate and maintain its
pipeline and to afford the pipeline an opportunity to earn a reasonable rate of
return. No assurance can be given that the FERC will not alter or refine its
preferred methodology for establishing pipeline rates and tariff structure in a
way that is detrimental to the Partnership.
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, existing shippers may not extend their contracts and the
Partnership may be unable to find replacement sources of natural gas for the
pipeline system's capacity. The Partnership cannot give any assurances as to the
availability of additional sources of gas that can interconnect with its
pipeline system.
Continued sales of Western Canadian natural gas to the United States will
also depend on:
o the level of exploration, drilling, reserves and production of
Western Canada Sedimentary Basin natural gas and the price of
such natural gas;
o the accessibility of Western Canada Sedimentary Basin natural
gas which may be affected by weather, natural disaster or other
impediments to access;
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 commercially acceptable basis.
13
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.
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 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; and
o shippers may not be willing to sign long-term contracts for
service which would make use of a planned expansion.
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.
14
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. 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 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 29,100 square feet of leased office space under a
lease agreement that expires on June 30, 2003. The Partnership also leases
approximately 10,500 square feet of warehouse and office space in Oxford,
Connecticut under a lease agreement that expires on March 31, 2004.
Additionally, the Partnership leases a right-of-way easement on Long Island, New
York from the Long Island Lighting Company, the predecessor to KeySpan Energy
Corporation, the parent of LILCO Energy Systems, Inc., a general partner of the
Partnership, which expires in 2030. 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 believes that it has satisfactory interests in all of
the properties making up its pipeline system.
ITEM 3. LEGAL PROCEEDINGS
The Partnership is a party to various legal actions incident 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.
15
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, 2000, 1999,
1998, 1997 and 1996 have been derived from the Partnership's financial
statements, which have been audited by PricewaterhouseCoopers LLP, independent
public accountants.
Year ended December 31,
----------------------------------------------------------------------
2000 1999 1998 1997 1996
----------------------------------------------------------------------
(In thousands of dollars, except ratios)
Income Statement Data:
Net operating revenues ............................. $127,234 $123,919(1) $140,371 $153,652 $154,379
Operating expenses:
Operations ..................................... 21,119 21,534 21,703 23,988 22,538
Depreciation and amortization .................. 23,609 21,976 29,795 32,094 31,243
Taxes other than income taxes .................. 11,156 11,449 10,390 10,266 9,607
-------- -------- -------- -------- --------
Total operating expenses ..................... 55,884 54,959 61,888 66,348 63,388
Operating income ................................... 71,350 68,960 78,483 87,304 90,991
Other income and (expenses) .................... 1,824 1,419 6,758(2) 4,180 1,131
-------- -------- -------- -------- --------
Income before interest charges and taxes ........... 73,174 70,379 85,241 91,484 92,122
Net interest expense ........................... 31,139 30,621 32,476 34,990 37,855
-------- -------- -------- -------- --------
Income before taxes ................................ 42,035 39,758 52,765 56,494 54,267
Provisions for taxes(3) ........................ 17,083 15,580 20,788 22,408 22,163
-------- -------- -------- -------- --------
Net income ......................................... $ 24,952 $ 24,178 $ 31,977 $ 34,086 $ 32,104
======== ======== ======== ======== ========
Cash Flow Data:
Net cash from operating activities ................. $ 57,181 $ 57,961 $ 83,899 $ 87,116 $ 60,589
Capital expenditures ............................... 8,268 7,718 14,172 14,719 4,358
Balance Sheet Data (at End of Period):
Net property, plant and equipment .................. $520,172 $534,806 $548,832 $563,766 $580,592
Total assets ....................................... 584,368 594,851 606,870 624,505 655,599
16
Long-term debt, including current
maturities....................................... 388,889 336,664 365,388 394,111 423,817
Partners' capital................................... $169,423 $227,388 $212,630 $199,865 $198,371
(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 an interstate natural gas pipeline system extending
from the United States-Canada border near Waddington, New York through
Connecticut to South Commack, Long Island, New York. The Partnership's pipeline
system commenced full operations on January 25, 1992, and is operated by the
Partnership's wholly owned subsidiary, IPOC.
In accordance with its FERC certificate, the Partnership was required to
submit two rate cases. Its first rate case filing was approved by the FERC on
June 19, 1995, except for one item which involved the recovery of certain legal
costs incurred by the Partnership in defense of an investigation discussed in
Note 7 to the Financial Statements. Its second rate case was filed on December
31, 1996 and rates were approved on December 31, 1997. During the latter part of
1999, the Partnership held negotiations with its shippers, which led to the
settlement of certain remaining issues from the first and second rate cases.
This settlement was filed with the FERC on December 17, 1999, and subsequently
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
previous two rate cases. The first rate reduction was implemented on January 1,
2001. The settlement had no impact on the Partnership's 2000, 1999 or 1998
income, but is expected to have a revenue impact of $2.38 million in 2001, $5.92
million in 2002 and $3.55 million in 2003 based upon long-term firm reserved
transportation contracts in effect as of December 31, 2000.
Results of Operations
- -------------------------------------------------------------------------------------------
Year ended
-------------------------------
Revenues and Volumes Delivered December 31,
- ---------------------------------------------------------- --------------------------------
2000 1999 1998
17
Revenues (dollars in millions)
- -------------------------------------------------------------------------------------------
Long-term firm reserved service $116.3 $116.6 $135.7
- ---------------------------------------------------------- ---------- ---------- ----------
Short-term firm/ interruptible/other (1) 10.9 7.3 4.7
-------- ------- -------
Total revenues $127.2 $123.9 $140.4
- ---------------------------------------------------------- ---------- ---------- ----------
Volumes Transported (million dekatherms)
- ---------------------------------------------------------- ---------- ---------- ----------
Long-term firm reserved service 292.1 290.6 287.5
- ---------------------------------------------------------- ---------- ---------- ----------
Short-term firm/ interruptible/other(1) 56.0 54.3 38.0
- ---------------------------------------------------------- ---------- ---------- ----------
Total volumes transported 348.1 344.9 325.5
- -------------------------------------------------------------------------------------------
- --------------------
(1) Other revenue includes deferred asset surcharges and park and loan service
revenue.
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. It 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. Such revenues include
short-term firm reserved transportation service contracts of less than one-year
terms as well as standard interruptible transportation service contracts. While
it is common for pipelines to have some form of required revenue sharing of
their interruptible transportation service revenues with long-term firm reserved
service shippers, the Partnership does not. However, the Partnership cannot
assure you this will continue to be the case in the future.
Total revenues for 2000 were $127.2 million, an increase of $3.3 million
over 1999 revenues. This increase resulted primarily from increased volumes and
favorable market prices for interruptible and short-term firm transportation
services. Total throughput for 2000 of 348 MDth is 3.3 Mdth, or 1% higher than
1999 deliveries.
The 1999 revenues of $123.9 million were down $16.5 million, or 11.8%, from
the $140.4 million level achieved in 1998. The 1999 revenues reflect a full year
of an inter-zone rate of $0.47/Dth, effective August 31, 1998 as a result of a
FERC decision on the Partnership's rate case filed in December 1996. The 1998
revenues include four months of activity at the $0.47/Dth rate and eight months
at the previous rate of $0.65/ Dth. These rates apply to long-term firm service.
The actual rates for interruptible and short-term firm service are based on
market conditions. In 1999, revenues for these services were ahead of 1998 by
73% or $2.7 million.
Total throughput for 1999 increased 19.4 MMDth, or 6.0%, over the 1998
deliveries. Most noticeable are a 49% increase in short-term firm and a 39%
increase in interruptible volumes transported. The increase in interruptible and
short-term firm service volumes reflects favorable gas prices, electric power
generation demands and higher than normal cooling loads during the summer
period.
Operating and Maintenance Expenses. The operation and maintenance expense
category includes operating, maintenance and administrative ("OM&A") expenses
for the Partnership's corporate office in Shelton, Connecticut and the field
support for the mainline, metering and
18
compression facilities. Operation and maintenance expense for 2000, at $21.1
million, is down almost 2% from 1999 as a result of efficiency gains and cost
control measures throughout the Partnership. Also included in OM&A expense are
$3.2 million for 2000, $3.3 million for 1999 and $3.6 million in 1998 for
account "858 charges", or the fees paid to the Tennessee ("TGP") and Algonquin
("AGT") pipelines for transportation provided by them to deliver gas to certain
Iroquois customers off their system. In the last rate case, the FERC instituted
a cost tracker for this expense. The Partnership's rates will be adjusted
periodically to reflect any changes in the rates charged by TGP or AGT. The OM&A
expenses for 1999 and 1998, excluding the 858 charges, remained stable at about
$18.2 million despite the addition of the Athens Compressor Station and other
facilities.
Depreciation and Amortization Expense. Depreciation and amortization
expense increased $1.6 million in 2000 compared to 1999. This increase is
primarily due to normal additions of general and transmission plant assets.
Depreciation and amortization expense in 1999 at $22 million was $7.8 million,
or 26%, below the 1998 level. The change was due mainly to new depreciation
rates established in the July 1998 FERC order (refer to Note 7 to the financial
statements). The 1998 depreciation expense for transmission plant reflects a
composite rate of 4% for eight months and 2.77% for four months.
Taxes, other than income taxes, encompass property and school taxes paid to
various jurisdictions for mainline, metering and compression facilities along
the Partnership's pipeline system. Taxes, other than income taxes, remained
consistent in 2000 compared to 1999 and increased $1.1 million in 1999 compared
to 1998. The increase in 1999 was primarily a result of additional facilities in
Athens, New York and Stratford, Connecticut.
Other Income and Expenses. Other income includes certain investment income
and the net of income and expense adjustments not recognized elsewhere. Interest
income increased $0.6 million in 2000 compared to 1999. The increase is
primarily due to additional interest income derived from short-term investments.
Interest income in 1999, at $1.6 million, was down approximately $0.3 million
from 1998 levels as a result of lower cash balances and consequently, lower
short-term investment levels. Other income, net in 1998 of $4.4 million included
a lump sum settlement that the Partnership received for releasing AG Energy from
its remaining long-term service obligation. In 1998, AG Energy operated a power
generation facility in New York state and was a party to the Niagara Mohawk
contract restructuring.
Interest Expense. Interest expense for 2000 reflects the impact of the
long-term refinancing that closed on May 30, 2000. While the effective interest
rate on long-term debt decreased, overall interest expense increased since the
average long-term debt balance increased from $353.4 million to $376.6 million.
Interest expense for the first five months of 2000 decreased $1.1 million due to
scheduled debt repayments. Interest expense for the last seven months of 2000
increased $1.8 million, as a result of the long-term debt refinancing
activities, including $0.5 million of amortization of swap terminations and
refinancing costs. Interest expense decreased $2.5 million in 1999 compared to
1998 due to lower average long-term debt balances from scheduled debt
repayments.
19
Income Taxes. Provisions for taxes increased $1.5 million in 2000 compared
to 1999, and decreased $5.2 million in 1999 compared to 1998. The 2000 increase
was due to higher taxable income and a change implemented by New York State from
a gross receipts tax based on revenue to an income-based franchise tax. The
decrease in 1999 was due primarily to lower taxable income than the prior year.
Income taxes are the responsibility of the partners of the Partnership (refer to
Note 8 to the financial statements).
Liquidity and Capital Resources
Capital expenditures for 2000 were $8.3 million compared to $7.7 million in
1999, reflecting the increased level of construction activity over the period.
Capital expenditures in 2000 consisted of preliminary engineering expenditures
relating to the Eastchester/New York City extension, as well as general plant
purchases and other minor projects. In 1999, capital activity was restricted to
some post-completion costs for the Athens compressor station, preliminary
engineering work for the Eastchester/New York City extension and various general
plant purchases. In 1998, capital expenditures of $14.2 million included costs
for the Athens compressor station that was completed November 1, 1998 and
transferred into service. The Partnership expects that if it decides to pursue
expansion projects it may be necessary to fund such projects through internally
generated funds, the issuance of additional indebtedness and capital
contributions by partners in accordance with the partnership agreement.
Cash flow (defined as net income adjusted for non-cash items such as
depreciation and deferred income taxes) represents the cash generated from
operations available for capital expenditures, partner distributions and other
operational needs. Net cash provided by operating activities remained relatively
constant in 2000 compared to 1999. Net cash provided by operating activities
decreased 31% or $25.9 million in 1999 compared to 1998. Since the Partnership's
service rates are based on recovering its cost of service, the change in
depreciation rates and other expenses required by the 1998 FERC rate order
decreased the rates and consequently the total revenues received after the new
rates were implemented on August 31, 1998 (refer to Note 6 to the financial
statements).
Total cash distributions to partners of $100.0 million, $25.0 million and
$40.0 million were made during 2000, 1999 and 1998, respectively. The increase
in 2000 is largely the result of $40.0 million being distributed to partners in
connection with the Partnership's May 2000 refinancing.
As a result of the refinancing in 2000, the Partnership arranged a $10
million revolving line of credit to support working capital requirements. Funds
may be borrowed on a short-term basis at variable rates. As of December 31,
2000, there were no borrowings outstanding on this $10 million facility. Prior
to the refinancing, the Partnership was a party to a $10 million line of credit
for short-term borrowing purposes. As of December 31, 1999, there was $3.5
million outstanding under this facility.
Total capital expenditures for 2001 are estimated to be approximately
$61.2 million, including approximately $55.3 million for the Eastchester/New
York City expansion project. This level of expenditure is contingent upon the
timing of FERC approval of the expansion
20
project. The remaining capital expenditures planned for 2001 are for the
purchase of land for a compressor site, a meter station and interconnect, and
various general plant purchases. The Partnership currently anticipates funding
its 2001 capital expenditures by using internal sources and if necessary,
through the issuance of additional indebtedness and/or capital contributions by
its partners.
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
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.
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.
21
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 financial statements.)
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-1 through F-20 of this
report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
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 .......... 50 President
Paul Bailey ............ 54 Vice President and Chief Financial Officer
Jeffrey A. Bruner ...... 42 Vice President, General Counsel and Secretary
Herbert A. Rakebrand III 44 Vice President, Marketing and Transportation
David J. Warman ........ 43 Vice President, Engineering and Operations
Craig R. Frew is President of IPOC. Mr. Frew has 29 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 New England Gas Association and the Interstate Natural Gas Association.
22
Paul Bailey is Vice President and Chief Financial Officer of IPOC. Mr.
Bailey has 19 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 21 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 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.
23
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
- ---- --- --------------------------- -------------------
James M. Lane 61 ANR Pipeline Company ANR Iroquois, Inc./ANR
New England Pipeline Co.
Paul D. Koonce 41 Dominion Resources, Inc. Dominion Iroquois, Inc.
Larry S. McGaughy 53 Connecticut Energy Corporation TEN Transmission Company
Charles A. Daverio 51 KeySpan Energy Corporation NorthEast Transmission
Company, LILCO Energy
Systems, Inc.
Joseph P. Shields 43 New Jersey Natural Gas Company NJNR Pipeline Company
Peter Lund 42 PG&E National Energy Group JMC-Iroquois, Inc.
Paul MacGregor 44 TransCanada Pipelines Ltd. TransCanada Iroquois
Ltd./TCPL Northeast Ltd.
James M. Lane has over 30 years experience in the natural gas industry
having spent the last 20 years with The Coastal Corporation. In his current
position, Mr. Lane is responsible for managing the day-to-day business affairs
of ANR Storage Company, Mid Michigan Gas Storage Company and four joint venture
companies, and the business administration functions of ANR Pipeline Company's
Storage Operations, which are all affiliates of The Coastal Corporation. In
addition, Mr. Lane manages Coastal's business interests in 8 joint ventures. Mr.
Lane has served on the management committee of the Partnership since 1997.
Paul D. Koonce joined Dominion Resources, Inc. as Senior Vice President,
Commercial Operations in January 1999. He is responsible for various businesses
of Dominion Energy. From 1982 through 1992, he worked for East Tennessee Natural
Gas, Entrade Corporation, Texas Gas Transmission and Transcontinental Gas
Pipeline Corporation. In 1992, he joined Sonat Marketing Company where he was
promoted to Senior Vice President of Sonat Energy Services and was later named
Executive Vice President of Sonat Power Systems. Mr. Koonce has served on the
management committee of the Partnership since the beginning of 2000.
Larry S. McGaughy is the President of three non-utility affiliates at
Connecticut Energy Corporation (CNE Energy Services Group, Inc., CNE
Development Corporation and CNE
24
Venture-Tech, Inc.). From 1990 to 1995, he served as a Vice President of
Southern Connecticut Gas Company in the various functional areas of Marketing,
Corporate Planning, Corporate Engineering and Gas Control. Prior to joining
Southern, Mr. McGaughy served as Director of Marketing and Energy Services and
as Director of Regulatory Control and Budgets at Tampa Electric Company over a
period of eleven years. Mr. McGaughy has served as a member of the management
committee of the Partnership since November 2000.
Charles A. Daverio has served as Vice President of KeySpan Energy Trading
Services, LLC since December 1996. He joined KeySpan Energy Corporation in 1976
as an associate engineer. He held various supervisory and managerial positions
in the Nuclear Engineering Department, Gas Supply and Planning, and Gas
Operators from 1979 through 1996. Mr. Daverio has served as the representative
of KeySpan Energy Corporation on the management committee of the Partnership
since 1991.
Joseph P. Shields is a Senior Vice President of New Jersey Natural Gas
Company, a subsidiary of New Jersey Resources Corporation. Since 1983, he has
served as Manager, Director and Vice President of Gas Supply in New Jersey
Natural Gas Company. Prior to joining New Jersey Natural Gas Company, he was
employed by the State of New Jersey Board of Public Utilities. He joined the
management committee of the Partnership as of August 16, 2000.
Peter Lund has been Vice President-Pipeline Marketing and Development of
PG&E National Energy Group, since March 2000. Prior to his current role, Mr.
Lund served as Vice President - Transportation and Storage Operations of PG&E
Gas Transmission. 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 of the Pacific Coast Gas Association, the Private Industry Sponsors
of the Canadian Energy Research Institute and a board member and former
president of the Northwest Gas Association. Mr. Lund has been a member of the
management committee of the Partnership since 1999.
Paul F. MacGregor has served as Vice President of North American Pipeline
Ventures TransCanada since September 1999. 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 2000 and 1999 paid to
the President and each of the four other most highly compensated executive
officers of IPOC who were serving as such as of
25
December 31, 2000. All compensation to the executive officers is paid by IPOC
and reimbursed by the Partnership.
Other Annual All Other
Name and Salary Bonus Compensation Compensation
Principal Position Year ($) (1) ($) ($)(2) ($) (3)
- ------------------ -------- ------- --- ------ -------
Craig R. Frew 2000 $262,058.23 $125,000.00 $65,598.34 $10,500.00
President 1999 256,913.55 111,150.00 10,000.00
Paul Bailey 2000 $184,293.98 $55,000.00 $72,429.11 $9,448.94
Vice President and Chief 1999 177,177.00 46,000.00 8,695.75
Financial Officer
Jeffrey A. Bruner 2000 $148,580.38 $44,000.00 --- $7,428.98
Vice President, General 1999 142,506.00 38,500.00 7,215.26
Counsel and Secretary
Herbert A. Rakebrand III 2000 $164,588.58 $69,000.00 --- $8,089.90
Vice President, Marketing 1999 147,502.00 43,500.00 7,340.06
and Transportation
David J. Warman 2000 $126,011.79 $37,000.00 --- $6,190.08
Vice President, 1999 115,011.00 29,000.00 5,840.55
Engineering
and Operations
- -----------------------------
(1) Amounts reported for the 1999 and 2000 fiscal years, respectively include
salary paid in lieu of vacation for the following: Mr. Frew -- $9,692.55
and $4,754.25; Mr. Rakebrand -- $2,500 and $2,788.50; and Mr. Warman -- $0
and $2,211.75, respectively.
(2) Other Annual Compensation 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) The amounts presented in this column represent 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 1999 and 2000 fiscal years,
respectively under the 401(K) Plan: Mr. Frew received $8,000 and $8,500;
Mr. Bailey received $8,000 and $8,500; Mr. Bruner received $7,215.26 and
$7,428.98; Mr. Rakebrand received $7,340.06 and $8,089.90; and Mr. Warman
received $5,840.55 and $6,190.08, respectively. In addition,
26
the following amounts were received during the 1999 and 2000 fiscal years,
respectively under the Supplemental Plan: Mr. Frew received $2,000 and
$2,000; and Mr. Bailey received $697.75 and $948.94, respectively.
Long-Term Incentive Plan Awarded In Last Fiscal Year
Effective as of January 1, 1999, IPOC adopted a performance share unit
plan, which provides financial incentives to certain key executives. All key
employees of IPOC and its subsidiaries are eligible to participate in the
performance plan. The participants for each year will be selected by the
compensation committee. Participants are awarded "phantom shares" of the
partnership ("Performance Units") which are valued annually based upon our
year-end book value and our average return on rate base equity. The payout value
of the Performance Units is based on the sum of (i) the value of the Performance
Units at the end of a performance period and (ii) the amount of dividends per
Performance Unit during the period. Payment on the Performance Units is made in
cash within 30 days following completion of our audited financial statements.
The Performance Units generally vest and become payable over five years,
with 50% of each award vesting at the end of the third year and 25% vesting at
the end of each of the fourth and fifth years. Upon a termination of a
participant's employment with IPOC or its subsidiaries, for any reason other
than death, disability, or retirement, all unvested Performance Units will be
forfeited. Upon a termination due to the participant's death, disability or
retirement, the committee may, in its sole discretion, provide for the vesting
and payment of any unvested Performance Units.
The following table provides information concerning the Performance Units
granted to the named executive officers in fiscal year 2000.
Estimated Future Payouts
Performance Period Until Under Non-Stock
Name Number of Units Maturation or Payout Price-Based Plan (5)
- ------------------------------- ---------------------------- ---------------------------- ----------------------------
Craig R. Frew 150 (1) 2000-2001 $65,419.20
150 (2) 2000-2002 $73,408.80
300 (3) 2000-2003 $162,219.30
300 (4) 2000-2004 $186,565.50
Paul Bailey 65 (1) 2000-2001 $28,348.32
65 (2) 2000-2002 $31,810.48
130 (3) 2000-2003 $70,295.03
130 (4) 2000-2004 $80,845.05
Jeffrey A. Bruner 35 (1) 2000-2001 $15,264.48
35 (2) 2000-2002 $17,128.72
70 (3) 2000-2003 $37,851.17
70 (4) 2000-2004 $43,531.95
Herbert A. Rakebrand III 47.5 (1) 2000-2001 $20,716.08
47.5 (2) 2000-2002 $23,246.12
95 (3) 2000-2003 $51,369.45
95 (4) 2000-2004 $59,079.08
David J. Warman 35 (1) 2000-2001 $15,264.48
35 (2) 2000-2002 $17,128.72
27
Engineering and 70 (3) 2000-2003 $37,851.17
Operations 70 (4) 2000-2004 $43,531.95
- --------------
(1) Grants vest in full on December 31, 2001.
(2) Grants vest in full on December 31, 2002
(3) 50% of the grant vests on December 31, 2001 and the remaining 50% vests
as to 25% on each of December 31, 2002 and December 31, 2003.
(4) 50% of the grant vests on December 31, 2002 and the remaining 50% vests
as to 25% on each of December 31, 2003 and December 31, 2004.
(5) The estimated future payout values under the performance share unit plan
are estimated solely for purposes of this annual report based on certain
management projections. The actual amount of the payouts under the
performance plan may be lesser or greater than these estimates. Management
makes no guarantees about IPOC's actual performance during the performance
periods.
Pension Plans
IPOC sponsors a qualified non-contributory, cash balance retirement plan
covering substantially all of its employees and an excess retirement plan
covering certain key employees. Under the pension plan, each participant is
given a hypothetical account balance, which is credited with a specified
percentage of a portion of the participant's covered compensation based on his
or her age and service. The excess pension plan is an unfunded pension
arrangement that provides certain highly compensated employees with the benefit
that they would have been entitled to but for the limitations set forth in the
Internal Revenue Code of 1986, as amended. In addition, under the excess pension
plan, the benefits provided to Messrs. Frew, Bailey and Warman take into account
their years of service with TransCanada Pipelines Limited. The benefits under
the excess pension plan are not subject to the provisions of the Internal
Revenue Code that limit the compensation used to determine benefits and the
amount of annual benefits payable under the qualified pension plan.
The following table illustrates, for representative annual covered
compensation and years of benefit service classifications, the annual retirement
benefit that would be payable to employees under both the non-contributory cash
balance retirement plan and the excess pension plan if they retired in 2001 at
age 65, based on the straight-life annuity form of benefit payment and not
subject to deduction or offset. In calculating the benefits shown in the
following table, salaries were assumed to remain level and hypothetical account
balances were assumed to grow at 6.28% per year.
28
PENSION PLAN TABLE
Years of Service
- --------------------------------------------------------------------------------
Remuneration 15 20 25 30 35
- --------------------------------------------------------------------------------
150,000 48,815 73,543 108,585 149,219 207,034
200,000 66,502 100,314 148,177 203,903 283,086
250,000 84,189 127,085 187,770 258,588 359,141
300,000 101,876 153,856 227,363 313,273 435,193
350,000 119,563 180,627 266,955 367,956 511,247
400,000 137,250 207,398 306,548 422,640 587,301
450,000 154,937 234,169 346,140 477,324 663,354
500,000 172,624 260,941 385,734 532,008 739,407
The number of years of credited service, as of December 31, 2000, for
Messrs. Frew, Bailey, Bruner, Rakebrand and Warman are 24.50, 18.33, 8.58, 9.33
and 18.42, respectively. These numbers include the credited service with
TransCanada Pipelines Limited pursuant to the excess pension plan.
Supplemental Executive Retirement Agreements
Mr. Frew is a party to a supplemental executive retirement agreement, dated
July 1, 1997 that provides a guaranteed retirement benefit of 60% of his average
annual compensation, including salary and bonus for the three highest
consecutive calendar years during his employment with IPOC. This amount is
reduced by any retirement benefits that Mr. Frew is entitled to pursuant to the
IPOC pension plan and excess pension plan, certain TransCanada Pipelines pension
plans, the IPOC 401(k) plan and his social security benefits.
Mr. Bailey is party to a similar supplemental executive retirement
agreement dated July 1, 1997; however, Mr. Bailey's guaranteed retirement
benefit is 40% of his three-year average annual compensation, including salary
and bonus for the three highest consecutive calendar years during his employment
with IPOC.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The Partners
The Partnership is a limited partnership wholly owned by its partners. The
following information summarizes the ownership interest of the partners:
29
General Limited Total
Partner Partner Partnership
Ultimate Parent Name of Partner Interest Interest Interest
TransCanada TransCanada 29.0% -- 29.0%
PipeLines Iroquois Ltd. 6.0% -- 6.0%
Limited TCPL Northeast
Ltd.
KeySpan Energy NorthEast 18.07% 1.33% 19.4%
Corporation Transmission
Company
LILCO Energy 1.0% -- 1.0%
Systems, Inc.
Dominion Dominion 16.0% -- 16.0%
Resources, Inc. Iroquois, Inc.
The Coastal ANR Iroquois, 9.4% -- 9.4%
Corporation(1) Inc.
ANR New England 6.6% -- 6.6%
Pipeline Co.
PG&E Generating JMC-Iroquois, 4.57% .36% 4.93%
Company Inc.
CTG Resources, Inc. TEN Transmission 4.46% .41% 4.87%
Company
New Jersey NJNR Pipeline 2.8% -- 2.8%
Resources Company
Corporation
- -------------------
(1) On January 18, 2000, El Paso Energy Corp. ("El Paso") and The Coastal
Corporation ("Coastal") announced plans for the merger of El Paso and
Coastal. The merger was completed in January, 2001. As a condition of the
merger, the Federal Trade Commission ("FTC") ordered Coastal to divest all
of its interest in Iroquois and must approve the proposed buyers. Several
existing partners of the Partnership have agreed to purchase Coastal's
interest pending FTC approval.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Affiliates of each partner of the Partnership transport natural gas on the
Partnership's pipeline system, at rates, terms and conditions contained in its
FERC approved tariff. At December 31, 2000, approximately 58% of natural gas
under long-term firm contract was transported by affiliates of partners. The
Partnership also leases a right-of-way easement which requires annual payments
escalating 5% a year over the 39-year term of the lease on Long Island, New
York, from the Long Island Lighting Company, the predecessor to KeySpan Energy
Corporation, the parent of LILCO Energy Systems, Inc., a general partner of the
Partnership.
PART III.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Exhibits
30
Index to Exhibits
Exhibit
Number Description
- ------ -----------
3.1* Amended and Restated Limited Partnership Agreement of the Partnership
dated as of February 28, 1997 among the partners of the Partnership.
3.2* First Amendment to Amended and Restated Limited Partnership Agreement
of the Partnership dated as of January 27, 1999 among the partners of
the Partnership.
4.1* Indenture dated as of May 30, 2000 between the Partnership and the
Chase Manhattan Bank, as trustee (the "Trustee") for $200,000,000
aggregate principal amount of 8.68% senior notes due 2010.
4.2* First Supplemental Indenture, dated as of May 30, 2000 between the
Partnership and the Trustee for $200,000,000 aggregate principal amount
of 8.68% senior notes due 2010.
4.3* Form of Exchange Note.
4.4* Exchange and Registration Rights Agreement dated as of May 30, 2000
among the Partnership and the Initial Purchasers for $200,000,000
aggregate principal amount of 8.68% senior notes due 2010.
10.1* Credit Agreement among the Partnership, The Chase Manhattan Bank, as
administrative agent, Bank of Montreal, as syndication agent and Fleet
National Bank, as documentation agent, and other financial
institutions, dated May 30, 2000.
10.2* Amended and Restated Operating Agreement dated as of February 28, 1997
between Iroquois Pipeline Operating Company and the Partnership.
10.3* Agreement Between Iroquois Pipeline Operating Company and Tennessee Gas
Pipeline Company with respect to operating pipelines of the Partnership
dated as of March 15, 1991.
10.4* FERC Gas Tariff, First Revised Volume No. 1 of the Partnership filed
with the Federal Energy Regulatory Commission.
10.5* Stipulation and Agreement dated as of December 17, 1999 between the
Partnership, the Federal Energy Regulatory Commission Staff and all
active participants in Docket Nos. RP94-72-009, FA92-59-007,
RP97-126-015, and RP97-126-000 as approved by the Federal Energy
Regulatory Commission on February 10, 2000.
31
10.6* Supplemental Executive Retirement Agreement dated as of July 1, 1997
between the Partnership and Craig R. Frew.
10.7* Supplemental Executive Retirement Agreement dated as of July 1, 1997
between the Partnership and Paul Bailey.
10.8* Supplementary Pension Plan of Iroquois Pipeline Operating Company
adopted on December 31, 1998.
10.9* Performance Share Unit Plan of Iroquois Pipeline Operating Company
effective as of January 1, 1999.
12.1* Statements regarding computation of ratios.
21.1* List of Subsidiaries of the Partnership.
- -----------------------
* Previously filed as an exhibit to the Partnership's Registration
Statement on Form S-4 (No. 333-42578)
(b) Reports on Form 8-K
None.
32
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
IROQUOIS GAS TRANSMISSION SYSTEM, L.P. as Registrant
By: Iroquois Pipeline Operating Company, its Agent
Date: March 30, 2001 By: /s/ Paul Bailey
-------------------------------------
Name: Paul Bailey
Title: Vice President and
Chief Financial Officer
By: /s/ Craig R. Frew
-------------------------------------
Name: Craig R. Frew
Title: President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on March 30, 2001.
Signatures Title
---------- -----
/s/ Paul Bailey Vice President and Chief Financial Officer of
- ------------------------ Iroquois Pipeline Operating Company
Paul Bailey
/s/ Craig R. Frew President of Iroquois Pipeline Operating
- ------------------------ Company
Craig R. Frew
/s/ Nicholas A. Rinaldi Controller of Iroquois Pipeline
- ------------------------ Operating Company
Nicholas A. Rinaldi
/s/ Paul F. MacGregor Representative on the Management Committee
- ------------------------
Paul F. MacGregor
/s/ Charles A. Daverio Representative on the Management Committee
- ------------------------
Charles A. Daverio
/s/ Paul D. Koonce Representative on the Management Committee
- ------------------------
Paul D. Koonce
/s/ Larry S. McGaughy Representative on the Management Committee
- ------------------------
Larry S. McGaughy
33
/s/ Joseph P. Shields Representative on the Management Committee
- ------------------------
Joseph P. Shields
/s/ Peter G. Lund Representative on the Management Committee
- ------------------------
Peter G. Lund
34
PART IV. INDEX TO FINANCIAL STATEMENTS
Page
Report of Independent Accountants.............................................................F-2
Financial Statements
Consolidated Statements of Income for the years ended December 31,
2000, 1999 and 1998..............................................................F-3
Consolidated Balance Sheets as of December 31, 2000 and 1999..............................F-4
Consolidated Statements of Cash Flows for the years ended December 31,
2000, 1999 and 1998.............................................................F-6
Statements of Changes in Partners' Equity for the years ended December
31, 2000, 1999, 1998 and 1997 ...................................................F-8
Notes to Financial Statements.................................................................F-9
F-1
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of
Iroquois Gas Transmission System L.P.:
In our opinion, the consolidated financial statements listed in the index
appearing under Part II, Item 8 on page 22 present fairly, in all material
respects, the financial position of Iroquois Gas Transmission System L.P. ("the
Company") and its subsidiary at December 31, 2000 and 1999, and the results of
their operations and cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America. These financial statements are the responsibility
of the Company's management; our responsibility is to express an opinion on
these financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing principles generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
- ------------------------------
Boston, Massachusetts
February 7, 2001
F-2
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31 2000 1999 1998
(thousands of dollars)
OPERATING REVENUES $127,234 $123,919 $140,371
OPERATING EXPENSES:
Operation and maintenance 21,119 21,534 21,703
Depreciation and amortization 23,609 21,976 29,795
Taxes other than income taxes 11,156 11,449 10,390
-------- -------- --------
Total Operating Expenses 55,884 54,959 61,888
-------- -------- --------
OPERATING INCOME 71,350 68,960 78,483
-------- -------- --------
OTHER INCOME/(EXPENSES):
Interest income 2,203 1,644 1,908
Allowance for equity funds used
during construction 126 -- 457
Other, net (505) (225) 4,393
-------- -------- --------
1,824 1,419 6,758
-------- -------- --------
INCOME BEFORE INTEREST CHARGES AND TAXES 73,174 70,379 85,241
INTEREST EXPENSE:
Interest expense 31,283 30,621 33,169
Allowance for borrowed funds used
during construction (144) -- (693)
-------- -------- --------
NET INTEREST EXPENSE 31,139 30,621 32,476
-------- -------- --------
INCOME BEFORE TAXES 42,035 39,758 52,765
PROVISION FOR TAXES 17,083 15,580 20,788
-------- -------- --------
NET INCOME $ 24,952 $ 24,178 $ 31,977
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-3
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED BALANCE SHEETS
ASSETS
AT DECEMBER 31 2000 1999
(thousands of dollars)
CURRENT ASSETS:
Cash and temporary cash investments $ 25,013 $ 27,375
Accounts receivable - trade 7,655 6,938
Accounts receivable - affiliates 5,667 5,440
Other current assets 3,138 3,422
--------- ---------
Total Current Assets 41,473 43,175
--------- ---------
NATURAL GAS TRANSMISSION PLANT:
Natural gas plant in service 777,577 773,588
Construction work in progress 7,646 3,292
--------- ---------
785,223 776,880
Accumulated depreciation and
amortization (265,051) (242,074)
--------- ---------
Net Natural Gas Transmission Plant 520,172 534,806
--------- ---------
OTHER ASSETS AND DEFERRED CHARGES:
Regulatory assets - income tax related 13,634 12,767
Regulatory assets - other 2,038 2,226
Other assets and deferred charges 7,051 1,877
--------- ---------
Total Other Assets and Deferred Charges 22,723 16,870
--------- ---------
TOTAL ASSETS $ 584,368 $ 594,851
========= =========
The accompanying notes are an integral part of these financial statements.
F-4
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND PARTNERS' EQUITY
AT DECEMBER 31 2000 1999
(thousands of dollars)
CURRENT LIABILITIES:
Accounts payable $ 3,970 $ 3,624
Accrued interest 2,909 4,781
Short-term borrowings -- 3,500
Current portion of long-term debt (Note 3) 22,222 28,789
Accrued property taxes 3,541 3,737
Other current liabilities 1,513 1,574
--------- ---------
Total Current Liabilities 34,155 46,005
--------- ---------
LONG-TERM DEBT (NOTE 3) 366,667 307,875
OTHER NON-CURRENT LIABILITIES 489 816
--------- ---------
367,156 308,691
AMOUNTS EQUIVALENT TO DEFERRED INCOME
TAXES:
Generated by Partnership 79,866 70,037
Payable by Partners (66,232) (57,270)
--------- ---------
Total Amounts Equivalent to
Deferred Income Taxes 13,634 12,767
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 7) -- --
TOTAL LIABILITIES 414,945 367,463
--------- ---------
PARTNERS' EQUITY 169,423 227,388
--------- ---------
TOTAL LIABILITIES AND PARTNERS' EQUITY $ 584,368 $ 594,851
========= =========
The accompanying notes are an integral part of these financial statements.
F-5
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED
DECEMBER 31 2000 1999 1998
(thousands of dollars)
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net Income $ 24,952 $ 24,178 $ 31,977
Adjusted for the following:
Depreciation and amortization 23,609 21,976 29,795
Allowance for equity funds used
during construction (126) -- (457)
Deferred regulatory assets -
income tax related (867) 1,071 548
Amounts equivalent to
deferred income taxes 867 (1,071) (548)
Income and other taxes payable by
Partners 17,083 15,580 20,788
Other assets and deferred
charges (5,567) (1,007) (28)
Changes in working capital:
Accounts receivable (944) (1,352) 3,276
Other current assets 284 (932) (323)
Accounts payable 346 (604) (679)
Accrued interest (1,872) (430) (402)
Other liabilities (584) 552 (48)
-------- -------- --------
Net Cash Provided by
Operating Activities 57,181 57,961 83,899
-------- -------- --------
CASH FLOWS USED FOR
INVESTING ACTIVITIES:
Capital expenditures (8,268) (7,718) (14,172)
-------- -------- --------
Net Cash Used for Investing
Activities (8,268) (7,718) (14,172)
-------- -------- --------
CASH FLOWS FROM
FINANCING ACTIVITIES:
Partner distributions (100,000) (25,000) (40,000)
Long-term debt borrowings 400,000 -- --
Repayments of long-term debt (347,775) (28,724) (28,723)
Short-term borrowings
(repayments) (3,500) 3,500 --
-------- -------- --------
Net Cash Used for Financing
Activities (51,275) (50,224) (68,723)
NET INCREASE (DECREASE) IN CASH (2,362) 19 1,004
F-6
AND TEMPORARY CASH INVESTMENTS
CASH AND TEMPORARY CASH
INVESTMENTS AT BEGINNING
OF YEAR 27,375 27,356 26,352
-------- -------- --------
CASH AND TEMPORARY CASH
INVESTMENTS AT END OF YEAR $ 25,013 $ 27,375 $ 27,356
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
Cash paid for interest $ 32,628 $ 31,051 $ 33,571
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-7
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
STATEMENT OF CHANGES IN PARTNERS' EQUITY
(thousands of dollars)
PARTNERS' EQUITY
BALANCE AT DECEMBER 31, 1997 $199,865
Net income 1998 31,977
Taxes payable by Partners 20,788
Equity distributions to Partners (40,000)
--------
BALANCE AT DECEMBER 31, 1998 $212,630
Net income 1999 24,178
Taxes payable by Partners 15,580
Equity distributions to Partners (25,000)
--------
BALANCE AT DECEMBER 31, 1999 $227,388
Net income 2000 24,952
Taxes payable by Partners 17,083
Equity distributions to Partners (100,000)
--------
PARTNERS' EQUITY BALANCE
AT DECEMBER 31, 2000 $169,423
========
The accompanying notes are an integral part of these financial statements.
F-8
NOTE 1
DESCRIPTION OF PARTNERSHIP:
Iroquois Gas Transmission System, L.P. ("Iroquois" or "Company") is a Delaware
limited partnership formed for the purpose of constructing, owning and operating
a natural gas transmission pipeline from the Canada-United States border near
Waddington, NY, to South Commack, Long Island, NY. In accordance with the
limited partnership agreement, the Partnership shall continue in existence until
October 31, 2089, and from year to year thereafter, until the Partners elect to
dissolve the Partnership and terminate the limited partnership agreement.
As of December 31, 2000, the Partners consist of TransCanada Iroquois
Ltd. (29.0%), North East Transmission Company (19.4%), Dominion Iroquois,
Inc. (16.0%), ANR Iroquois, Inc. (9.4%), ANR New England Pipeline Company
(6.6%), TCPL Northeast Ltd. (6.0%), JMC-Iroquois, Inc. (4.93%), TEN
Transmission Company (4.87%), NJNR Pipeline Company (2.8%), and LILCO
Energy Systems, Inc. (1.0%). Effective December 31, 1998, Alenco
Iroquois Pipeline, Inc. sold its interest in the Company to TCPL
Northeast Ltd. The Iroquois Pipeline Operating Company, a wholly-owned
subsidiary, is the administrative operator of the pipeline.
Income and expenses are allocated to the Partners and credited to their
respective equity accounts in accordance with the partnership agreements and
their respective percentage interests. Distributions to Partners are made
concurrently to all Partners in proportion to their respective partnership
interests. Total cash distributions of $100.0 million, $25.0 million and $40.0
million were made during 2000, 1999 and 1998, respectively.
NOTE 2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Basis of Presentation The consolidated financial statements of the Company are
prepared in accordance with generally accepted accounting principles and with
accounting for regulated public utilities prescribed by the Federal Energy
Regulatory Commission ("FERC"). Generally accepted accounting principles for
regulated entities allow the Company to give accounting recognition to the
actions of regulatory authorities in accordance with the provisions of Statement
of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects
of Certain Types of Regulation". In accordance with SFAS No. 71, the Company has
deferred recognition of costs (a regulatory asset) or has recognized obligations
(a regulatory liability) if it is probable that such costs will be recovered or
obligation relieved in the future through the rate-making process.
Principles of Consolidation The consolidated financial statements include the
accounts of the Company and Iroquois Pipeline Operating Company, a wholly-owned
subsidiary. Intercompany transactions have been eliminated in consolidation.
F-9
Cash and Temporary Cash Investments Iroquois considers all highly liquid
temporary cash investments purchased with an original maturity date of three
months or less to be cash equivalents. Cash and temporary cash investments of
$25.0 million at December 31, 2000 consisted primarily of discounted commercial
paper. Cash and temporary cash investments of $27.4 million in 1999, consisted
primarily of low-risk mutual funds, carried at cost, which approximated market.
At December 31, 1999, $9.7 million of cash and temporary cash investments were
held to satisfy the terms of the Loan Agreement (refer to Note 3).
Natural Gas Plant In Service Natural gas plant in service is carried at original
cost. The majority of the natural gas plant in service is categorized as natural
gas transmission plant which began depreciating over 20 years on a straight line
basis from the in-service date through January 31, 1995. Commencing February 1,
1995, transmission plant began depreciating over 25 years on a straight-line
basis as a result of a rate case settlement. Effective August 31, 1998 the
depreciation rate was changed to 2.77% (36 years average life) in accordance
with the FERC rate order issued July 29, 1998. General plant is depreciated on a
straight-line basis over five years.
Construction Work In Progress At December 31, 2000, construction work in
progress included preliminary construction costs relating to the proposed
Eastchester expansion project and other on-going minor capital projects.
Allowance for Funds Used During Construction The allowance for funds used during
construction ("AFUDC") represents the cost of funds used to finance natural gas
transmission plant under construction. The AFUDC rate includes a component for
borrowed funds as well as equity. The AFUDC is capitalized as an element of
natural gas plant in service.
Provision for Taxes The payment of income taxes is the responsibility of the
Partners and such taxes are not normally reflected in the financial statements
of partnerships. Iroquois' approved rates, however, include an allowance for
taxes (calculated as if it were a corporation) and the FERC requires Iroquois to
record such taxes in the Partnership records to reflect the taxes payable by the
Partners as a result of Iroquois' operations. These taxes are recorded without
regard as to whether each Partner can utilize its share of the Iroquois tax
deductions. Iroquois' rate base, for rate-making purposes, is reduced by the
amount equivalent to accumulated deferred income taxes in calculating the
required return.
The Company accounts for income taxes under Statement of Financial Accounting
Standards ("SFAS") No. 109, "Accounting for Income Taxes". Under SFAS No. 109,
deferred taxes are provided based upon, among other factors, enacted tax rates
which would apply in the period that the taxes become payable, and by adjusting
deferred tax assets or liabilities for known changes in future tax rates. SFAS
No. 109 requires recognition of a deferred income tax liability for the equity
component of AFUDC.
Estimates The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
F-10
Reclassifications Certain prior year amounts have been reclassified to conform
with current year classifications.
New Accounting Standard In June of 1998, The Financial Accounting Standards
Board ("FASB") issued SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities" ("SFAS 133"). This statement establishes accounting and
reporting standards for derivative instruments and for hedging activities. The
statement requires recognition of derivatives in the statement of financial
position, to be measured at fair value. Gains or losses resulting from changes
in the value of derivatives would be accounted for depending on the intended use
of the derivative and whether it qualifies for hedge accounting. In June 1999,
the FASB issued SFAS 137 "Accounting for Derivative Instruments and Hedging
Activities-Deferral of the Effective Date of FASB Statement 133," which deferred
SFAS 133's effective date for all fiscal quarters of all fiscal years beginning
after June 15, 2000. In June 2000, the FASB issued SFAS 138 "Accounting for
Certain Derivative Instruments and Certain Hedging Activities," which amended
SFAS 133. The Company has adopted SFAS 133 beginning January 1, 2001. However,
due to the Company's limited use of derivative financial instruments which are
applied only to the Company's interest rate swap agreement (see Note 3),
adoption of SFAS 133 will not have a material effect on the Company's
consolidated results of operations, financial position, or cash flows. The
transition adjustment as of January 1, 2001, recorded in other comprehensive
income was $1.7 million.
NOTE 3
FINANCING:
On June 11, 1991, Iroquois entered into a loan agreement which provided a loan
facility totaling $522.6 million to be amortized over a 14-year period
commencing November 1, 1992. During 1993, Iroquois entered into Expansion Loan
Agreement No. 1 in the amount of $17.6 million to construct the Wright
Compressor Station. This loan had a maturity date of November 2007. During 1995,
Iroquois entered into Expansion Loan Agreement No. 2 in the amount of $13.4
million to finance the Croghan Compressor Station. This loan had a maturity date
of November 2008. On May 30, 2000, Iroquois exercised its option to prepay these
three loans in full with the proceeds of the Term Loan Facility and Senior Notes
which are described below.
As of December 31, 1999, Iroquois was party to interest rate swap transactions
for aggregate notional principal amounts of $537.6 million relating to the
original loan and Expansion Loan No. 1. The fair value of the interest rate
swaps was the estimated amount that Iroquois would receive or pay to terminate
the swap agreements at the reporting date, taking into account current interest
rates and current creditworthiness of the swap counterparties. The fair value of
these interest rate swaps was ($8.6) million at December 31, 1999. These
interest rate swap agreements were terminated during the first six months of
2000.
On May 30, 2000, Iroquois completed a private offering of $200 million of 8.68%
senior notes due 2010, which were exchanged in a registered offering for notes
with substantially identical terms on September 25, 2000 ("Senior Notes"). Also
on May 30, 2000, Iroquois entered into a credit agreement with certain financial
institutions providing for a term loan facility of $200 million ("Term Loan
Facility") and a $10 million, 364-day revolving credit facility. The credit
agreement permits Iroquois to choose among various interest rate options, to
specify the portion of the borrowings to be covered by specific interest rate
options and to specify the interest rate period, subject to certain parameters.
The Term Loan Facility will amortize over nine years. At December 31, 2000 there
were no amounts outstanding under the revolving credit facility. The proceeds
from the Senior Notes and Term Loan Facility were used to repay borrowings under
the above mentioned three loan agreements, terminate related interest rate swap
agreements, make a cash distribution to Iroquois' partners of $40 million, pay
certain financing fees and expenses and for general corporate purposes.
During the first six months of 2000, Iroquois paid approximately $0.9 million
for the termination of its entire portfolio of interest rate swap agreements,
which had an aggregate notional principal amount of $437.6 million. Under the
provisions of SFAS 71, Iroquois intends to recover these costs in future rate
proceedings and therefore has deferred and is amortizing these amounts over the
life of the original loan agreements.
On August 9, 2000, the Company entered into an interest rate swap agreement with
The Chase Manhattan Bank to hedge a portion of the interest rate risk on the new
credit facilities. This interest rate swap agreement was effective on August 30,
2000 and will terminate on the last business day in May 2009. Pursuant to the
terms of this interest rate swap agreement, Iroquois has agreed to pay to The
Chase Manhattan Bank a fixed rate of 6.82% on an initial notional amount of
$25.0 million, which will be amortized during the term of the interest rate swap
agreement, in return for a payment from The Chase Manhattan Bank of a floating
rate of 3-month LIBOR on the amortizing notional amount. On August 9, 2000, the
Company also entered into an option with The Chase Manhattan Bank pursuant to
which The Chase Manhattan Bank had the option to enter into an additional
interest rate swap agreement. The Chase Manhattan Bank exercised this option
which was effective on December 26, 2000 and will terminate 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 will be amortized during the
term of the additional interest rate swap agreement. As of December 31, 2000,
the aggregate notional principle amount of these two swaps was $47.2 million.
The interest rate and margin over the term of the swaps average 6.820% and
1.260% respectively. The fair value of these interest rate swaps at December 31,
2000, was ($1.7) million.
As of December 31, 1999, Iroquois was party to interest rate swap transactions
for aggregate dule of repayments at December 31, 2000 is as follows (millions of
dollars):
YEAR Scheduled
Repayment
2001 $ 22.2
2002 $ 22.2
2003 $ 22.2
2004 $ 22.2
2005 $ 22.2
Thereafter $277.9
F-11
At December 31, 1999, the short-term borrowings consisted of an unsecured line
of credit which permitted borrowings up to a maximum of $10 million at a rate
equal to the lower of the lenders' alternate base rate or one, two or three
month LIBOR plus 3/8% per annum. This facility was reviewed on an annual basis
and expired in May 2000. As of December 31, 1999, $3.5 million was outstanding
under this agreement at an annual interest rate of 6.8363%. The line of credit
contained a subjective acceleration clause as its most restrictive covenant.
NOTE 4
CONCENTRATIONS OF CREDIT RISK:
Iroquois' cash and temporary cash investments and trade accounts receivable
represent concentrations of credit risk. Management believes that the credit
risk associated with cash and temporary cash investments is mitigated by its
practice of limiting its investments primarily to commercial paper rated P-1 or
higher by Moody's Investors Services and A-1 or higher by Standard and Poor's,
and its cash deposits to large, highly-rated financial institutions. Management
also believes that the credit risk associated with trade accounts receivable is
mitigated by the restrictive terms of the FERC gas tariff which requires
customers to pay for service within 20 days after the end of the month of
service delivery.
NOTE 5
FAIR VALUE OF FINANCIAL INSTRUMENTS:
The fair value amounts disclosed below have been reported to meet the disclosure
requirements of SFAS No. 107, "Disclosures About Fair Values of Financial
Instruments" and are not necessarily indicative of the amounts that the Company
could realize in a current market exchange.
The carrying amount of cash and temporary cash investments, accounts receivable,
accounts payable and accrued expenses approximates fair value.
The fair value of long-term debt is estimated based on currently quoted market
prices for similar types of issues. The carrying amounts and estimated fair
values of the Company's long-term debts including current maturities are as
follows (thousands of dollars):
Year Carrying Fair Value
Amount
2000 $388,889 $408,441
1999 $336,664 $336,664
NOTE 6
F-12
GAS TRANSPORTATION CONTRACTS:
As of December 31, 2000, Iroquois had contracts in place to provide firm
reserved transportation service to 36 shippers of 1005.9 MDth/d of natural gas
which breaks down as follows:
TERM IN YEARS QUANTITY IN MDTH/D
1-10 127.5
11-15 784.4
16-20 94.0
-------
Total 1005.9
The long-term firm service gas transportation contracts expire between October
31, 2002 and August 1, 2018.
NOTE 7
COMMITMENTS AND CONTINGENCIES:
Regulatory Proceedings
FERC Docket No. RP97-126 On November 29, 1996, Iroquois submitted a general rate
change application to the Federal Energy Regulatory Commission ("FERC" or
"Commission") in Docket No. RP97-126-000. In an order issued on December 31,
1996 ("Suspension Order"), the Commission accepted and suspended the rates,
permitted them to become effective (with one exception noted below) on January
1, 1997, and established a hearing. Pursuant to that Suspension Order, the
Presiding Administrative Law Judge conducted a hearing on all issues raised by
Iroquois' filing, which was concluded on August 28, 1997.
Following the December 31, 1997 issuance of an Initial Decision ("1997 Initial
Decision") by the Presiding Administrative Law Judge, on January 30, 1998
Iroquois filed its brief on exceptions vigorously opposing certain aspects of
the 1997 Initial Decision. On July 29, 1998 the Commission issued its "Order
Affirming in Part and Reversing in Part Initial Decision" ("July 29 Order")
which modified significant portions of the 1997 Initial Decision. Iroquois'
filing in compliance with the July 29 Order was accepted and the lower rates
became effective on August 31, 1998. In addition, on August 28, 1998 Iroquois
filed a request for rehearing of the July 29 Order. By order issued March 11,
1999 ("March 11 Order") the Commission granted rehearing on one aspect of the
July 29 Order. The March 11 Order reversed the earlier decision on Iroquois'
capital structure and permitted Iroquois to utilize an equity structure of
35.21% (in place of the 31.85% required by the July 29 Order) in designing its
rates. This resulted in an increase of approximately 1(cent) per dekatherm in
Iroquois' 100% load factor interzone rate. All other requests for rehearing of
the July 29 Order were denied. Iroquois filed a petition for review of these
orders in the United States Court of Appeals for the District of Columbia
Circuit docketed as DC Cir. No. 99-1175. This case was consolidated with DC Cir.
No. 99-1177, which involved a petition for review of these same orders that was
filed by Selkirk Cogen Partners, L.P. and MassPower (customers of Iroquois). As
a result of the Commission's
F-13
February 10, 2000 approval of the rate settlement discussed below, these
petitions for review were withdrawn.
The Suspension Order granted summary disposition on one issue: as a result of
the Commission's December 20 Opinion in Docket No. RP94-72 (discussed below),
Iroquois was ordered to remove approximately $11.7 million in plant and
associated costs from its proposed rate base. This resulted in an additional
reduction in Iroquois' test-period revenues of approximately $2.0 million from
those set forth in the filing. Iroquois sought rehearing (on January 30, 1997)
of the Suspension Order. This was denied by the Commission by an order issued
August 5, 1997 ("August 5 Order"). On September 3, 1997, Iroquois filed a
Petition for Review of the Commission's Suspension and August 5 Orders in the
United States Court of Appeals for the District of Columbia Circuit, docketed as
D.C. Cir. No. 97-1533, which was consolidated with D.C. Cir. No. 97-1276
(discussed below).
FERC Docket No. RP94-72 The Commission, on June 19, 1995, approved a Stipulation
and Consent Agreement in Iroquois' prior rate proceeding in Docket No. RP94-72,
which resolved all issues except for the accounting and recovery of legal
defense costs incurred in connection with certain criminal and civil
investigations into the initial construction of the Iroquois facility. A hearing
was held on this reserved issue on April 5, 1995. On July 19, 1995 the Presiding
Administrative Law Judge issued an Initial Decision ("1995 Initial Decision")
that would have permitted Iroquois to capitalize those legal defense costs and
recover $4.1 million (the dollar amount of such costs which Iroquois filed to
recover in Docket No. RP94-72) from its customers. Various participants,
including the Commission Staff, filed exceptions to the 1995 Initial Decision
with the Commission (which were opposed by Iroquois on September 7, 1995). On
December 20, 1996 the Commission issued an order reversing the 1995 Initial
Decision and disallowing recovery of the legal defense costs at issue. Iroquois
filed a request for rehearing of the Commission's December 20 Order on January
21, 1997. By Order issued March 3, 1997, the Commission denied rehearing.
Consolidated Proceedings Iroquois filed a petition for review of the December 20
and March 3 Orders in the United States Court of Appeals for the District of
Columbia Circuit on April 18, 1997 in D.C. Cir. No. 97-1276. Following oral
argument on May 14, 1998, the court on July 21, 1998 issued a decision reversing
the Commission's December 20 and March 3 Orders as well as the Suspension and
August 5 Orders and remanded the matter to the agency for further proceedings.
The court subsequently denied rehearing of its opinion on November 13, 1998 and
issued its mandate. On June 16, 1999 the Commission issued an "Order on Remand
and Establishing Rehearing" ("June 16 Order"). The June 16 Order concluded that
a hearing was necessary to determine whether Iroquois' incurrence of the legal
expenditures was prudent and set forth the procedures and burdens which were to
govern that hearing. A preliminary conference to establish a procedural schedule
and to clarify the positions of the participants was convened on July 12, 1999.
As a result of the Commission's
Settlement (FERC Docket Nos. RP97-126 and RP94-72 et al.) After extensive
negotiations, on December 17, 1999 Iroquois, with the support of all active
participants, filed with the Commission a settlement of all of the above
outstanding rate matters. Pursuant to the settlement
F-14
the parties agreed to a rate moratorium whereby, with limited exceptions, no new
rates could be placed in effect on Iroquois' system until January 1, 2004.
During the period of the moratorium, Iroquois would reduce its 100% load factor
interzone rate by approximately 4.8(cent) per dekatherm (approximately 1(cent)
in 2001, an additional 2.4(cent) in 2002 and an additional 1.4(cent) in 2003).
Based on 1999 long-term firm service contracts the settlement will result in the
following reductions in revenues: $2.3 million in 2001, $5.7 million in 2002,
and $3.4 million in 2003. In addition, Iroquois would not seek in any future
rate proceedings to recover defense costs associated with the criminal and civil
investigations into the initial construction of the Iroquois facility. These
costs were removed from the proposed rate base and reflected in the Company's
results from operations in previous years. Finally, Iroquois, Selkirk Cogen
Partners, L.P. and MassPower would withdraw their petitions for review in DC
Cir. Nos. 99-1175 and 99-1177. By letter order issued February 10, 2000, the
Commission approved the rate settlement without modification. The period for
filing rehearing requests of such order has expired. No such requests were
filed. The settlement became effective on March 10, 2000.
FERC Order No. 637 On February 9, 2000, the Commission issued Order No. 637 in
Docket Nos. RM98-10 and RM98-12. According to the Commission, the order was to
reflect "steps to guarantee effective competition, remove constraints on market
power, and eliminate regulatory bias". Among other things, the order required
pipelines to submit Commission filings to 1) remove the price cap applicable to
pipeline capacity released by firm shippers to new shippers, 2) revise pipeline
scheduling procedures applicable to such released capacity, 3) permit firm
shippers to segment their capacity for their own use or release, 4) revise
pipeline penalty provisions, and 5) expand, modify and consolidate certain
pipeline reporting requirements. On July 17, 2000 and September 1, 2000,
Iroquois submitted filings in (respectively) Docket Nos. RP00-411 and RP00-529
to implement the provisions of Order No. 637. Certain parties, including a
number of Iroquois shippers, opposed certain aspects of the filings. The
Commission has not yet acted on the filing in Docket No. RP00-411; the tariff
sheets submitted in Docket No. RP00-529 were accepted in a letter order dated
September 28, 2000. Management believes that the outcome of these proceedings
will not have a material adverse effect on Iroquois' financial condition or
results of operations.
Eastchester Certificate Application (FERC Docket No. CP00-232) On April 28,
2000, Iroquois filed an application with the Commission to construct and operate
its "Eastchester Extension Project". Under this proposal, Iroquois would
construct and operate certain facilities, including additional compression
facilities and approximately 33 miles of pipeline and associated facilities from
Northport, Long Island to the Bronx, New York. Those proposed facilities would
serve 220,000-230,000 dekatherms of natural gas per day on a long-haul basis to
the New York City area. Iroquois would provide firm transportation service to
the shippers with whom it has executed precedent agreements. Iroquois proposed
to place the facilities into service on a staggered basis, with certain
facilities placed into service on April 1, 2002 and the remainder on November 1,
2002. In order to meet the proposed in-service dates, Iroquois requested action
by the Commission by June 1, 2001. Certain parties have intervened in opposition
to certain aspects of the Eastchester proposal, including the location of the
pipeline through the Bronx and the treatment of the costs associated with the
project in future rate cases. Subsequent to the filing of those interventions,
the Commission submitted several data requests to Iroquois, to which
F-15
Iroquois has responded. In addition, on August 9, 2000 the Commission issued a
"Notice of Intent to Prepare an Environmental Impact Statement" regarding the
project, and conducted scoping sessions in various locations in New York state.
On December 15, 2000 Iroquois filed an amendment to its application, proposing
to relocate the terminus to a different location in the Bronx. Certain persons
have objected to this proposed relocation in comments filed with the Commission.
Additional meetings regarding this proposed relocation have been scheduled by
the FERC staff.
Legal Proceedings-Other Iroquois is party to various other legal actions
incident to its business. However, management believes that the outcome of these
proceedings will not have a material adverse effect on Iroquois' financial
condition or results of operations.
Leases Iroquois leases its office space under operating lease arrangements. The
leases expire at various dates through 2003 and are renewable at Iroquois'
option. Iroquois also leases a right-of-way easement on Long Island, NY, from
the Long Island Lighting Company ("LILCO"), a general partner, which requires
annual payments escalating 5% a year over the 39-year term of the lease. In
addition, Iroquois leases various equipment under non-cancelable operating
leases. During the years ended December 31, 2000, 1999 and 1998, Iroquois made
payments of $1.0 million, $1.0 million and $0.9 million respectively, under
operating leases which were recorded as rental expense. Future minimum rental
payments under operating lease arrangements are as follows (millions of
dollars):
YEAR AMOUNT
2001 $ 0.9
2002 $ 0.8
2003 $ 0.5
2004 $ 0.1
2005 $ 0.1
Thereafter $ 4.5
NOTE 8
INCOME TAXES:
Deferred income taxes which are the result of operations will become the
obligation of the Partners when the temporary differences related to those items
reverse. The Company recognizes a decrease in the Amounts Equivalent to Deferred
Income Taxes account for these amounts and records a corresponding increase to
Partners' equity. Deferred income taxes with respect to the equity component of
AFUDC remain on the accounts of the Partnership until the related deferred
regulatory asset is recognized.
Total income tax expense includes the following components (thousands of
dollars):
U.S State-
2000 Federal State Other Total
Current $ 5,501 $ 2,620 $ -- $ 8,121
F-16
Deferred 8,342 620 -- 8,962
------- ------- ----- -------
Total $13,843 $ 3,240 $ -- $17,083
======= ======= ======= ========
U.S State-
1999 Federal State Other Total
Current $ 5,082 $ 540 $ 1,124 $ 6,746
Deferred 8,285 549 -- 8,834
------- ------- ------- --------
Total $13,367 $ 1,089 $ 1,124 $15,580
======= ======= ======= ========
U.S State-
1998 Federal State Other Total
Current $ 8,910 $ 1,793 $ 1,221 $11,924
Deferred 8,530 334 -- 8,864
------- ------- ------- -------
Total $17,440 $ 2,127 $ 1,221 $20,788
======= ======= ======= ========
For the years ended December 31, 2000, 1999 and 1998, the effective tax rate
differs from the Federal statutory rate due principally to the impact of state
taxes.
Deferred income taxes included in the income statement relate to the following
(thousands of dollars):
2000 1999 1998
Depreciation $ 8,410 $ 8,930 $ 4,224
Deferred regulatory asset (75) (70) (71)
Property taxes (1) 23 27
Legal cost -- (16) 104
Accrued expenses -- 16 (104)
Alternative minimum tax 277 (37) 4,487
credit
Other 351 (12) 197
------- ------- -------
Total deferred taxes $ 8,962 $ 8,834 $ 8,864
======= ======= =======
The components of the net deferred tax liability are as follows (thousands of
dollars):
AT DECEMBER 31 2000 1999
DEFERRED TAX ASSETS:
Alternative minimum tax credit $ 2,496 $ 2,773
Accrued expenses 5,474 5,474
-------- --------
Total deferred tax assets 7,970 8,247
DEFERRED TAX LIABILITIES:
Depreciation and related items (67,456) (59,072)
Deferred regulatory asset (808) (883)
F-17
Property taxes (879) (879)
Legal costs (4,662) (4,662)
Other (1,058) (707)
--------- ---------
Total deferred tax liabilities (74,863) (66,203)
--------- ---------
Net deferred tax liabilities (66,893) (57,956)
--------- ---------
Less deferral of tax rate change 661 686
--------- ---------
Deferred taxes-operations (66,232) (57,270)
Deferred tax related to (12,973) (12,081)
equity AFUDC
Deferred tax related to
change in tax rate (661) (686)
Total deferred taxes --------- ---------
$(79,866) $(70,037)
========= =========
NOTE 9
RELATED PARTY TRANSACTIONS:
Operating revenues and amounts due from related parties were primarily for gas
transportation services. Amounts due from related parties are shown net of
payables, if any.
The following table summarizes Iroquois' related party transactions (millions of
dollars):
Payments Due from Revenue from
to Related Related Related
2000 Parties Parties Parties
TransCanada Iroquois Ltd. $0.2 $0.7 $ 7.6
NorthEast Transmission -- 1.1 9.1
Company
ANR Iroquois, Inc. -- -- 2.8
JMC-Iroquois, Inc. -- 1.7 18.1
TEN Transmission Company -- 0.6 7.4
NJNR Pipeline Company -- 0.6 7.0
LILCO Energy Systems, Inc. -- 1.0 11.3
------------- ------------- -------------
Totals $0.2 $5.7 $63.3
============= ============= =============
Payments Due from Revenue from
to Related Related Related
1999 Parties Parties Parties
TransCanada Iroquois Ltd. $0.5 $1.3 $ 7.7
NorthEast Transmission -- -- --
Company
ANR Iroquois, Inc. -- 0.3 3.7
JMC-Iroquois, Inc. -- 1.4 16.4
TEN Transmission Company -- 0.6 9.0
NJNR Pipeline Company -- 0.7 7.1
LILCO Energy Systems, Inc. 0.1 1.0 11.4
------------- ------------- -------------
Totals $0.6 $5.3 $55.3
============= ============= =============
F-18
NOTE 10
RETIREMENT BENEFIT PLANS:
During 1997, the Company established a noncontributory retirement plan ("Plan")
covering substantially all employees. Pension benefits are based on years of
credited service and employees' career earnings, as defined in the Plan. The
Company's funding policy is to contribute, annually, an amount at least equal to
that which will satisfy the minimum funding requirements of the Employee
Retirement Income Security Act plus such additional amounts, if any, as the
Company may determine to be appropriate from time to time.
During 1997 and 1998 the Company also adopted excess benefit plans (EBPs) that
provide retirement benefits to executive officers and other key management
staff. The EBPs recognize total compensation and service that would otherwise be
disregarded due to Internal Revenue Code limitations on compensation in
determining benefits under the regular retirement plan. The EBPs are not funded
and benefits are paid when due from general corporate assets.
The consolidated net cost for pension benefit plans included in the consolidated
statements of income for the years ending December 31, include the following
components (thousands of dollars):
2000 1999 1998
Service cost $504 $388 $328
Interest cost 98 68 40
Expected return on plan assets (92) (52) (25)
Amortization of prior
service cost 22 22 22
Recognition of net
actuarial loss 2 9 1
------------- ------------- -------------
Net periodic pension cost $534 $435 $366
============= ============= =============
The following tables represent the two Plans' combined funded status reconciled
to amounts included in the consolidated balance sheets as of December 31, 2000
and 1999 (thousands of dollars):
CHANGE IN BENEFIT OBLIGATION 2000 1999
Benefit obligation at beginning of year $1,456 $ 928
Service cost 504 388
Interest cost 98 68
Actuarial (gain) or loss (84) 92
Benefits paid (29) (20)
Benefit obligation at end of year ------------- -------------
$1,945 $1,456
============= =============
F-19
CHANGE IN PLAN ASSETS 2000 1999
Fair value of plan assets at beginning $ 862 $ 315
of year
Actual return on plan assets 30 47
Employer contribution 592 520
Benefits paid (29) (20)
------------- -------------
Fair value of plan assets at end of year $1,455 $ 862
============= =============
RECONCILIATION OF FUNDED STATUS 2000 1999
Funded status $ (490) $ (594)
Unrecognized net actuarial loss 98 122
Unrecognized prior service cost 169 191
Additional minimum liability,
non-qualified plans (96) (80)
------------- -------------
Accrued benefit cost $ (319) $ (361)
============= =============
The weighted average assumptions used in developing the projected benefit
obligations were:
2000 1999 1998
Discount rate 7.00% 7.00% 7.00%
Expected return on plan N/A 9.00% 9.00%
assets
Increase in future 5.00% 5.00% 5.00%
compensation
Cash balance interest 6.00% 6.00% 6.00%
credit rate
F-20