SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
Commission file number 0-25430
RIDGEWOOD ELECTRIC POWER TRUST IV
(Exact Name of Registrant as Specified in Its Charter)
Delaware 22-3324608
(State or Other Jurisdiction (I.R.S. Employer Identification No.)
of Incorporation or Organization)
c/o Ridgewood Power Corporation, 947 Linwood Avenue, Ridgewood, New Jersey 07450
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, including Area Code: (201) 447-9000
Securities Registered Pursuant to Section 12(b) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
Shares of Beneficial Interest(Title of Class)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.[ X ]
There is no market for the Shares. The aggregate capital contributions made
for the Registrant's voting Shares held by non-affiliates of the Registrant at
April 14, 2000 was $47,680,000.
Exhibit Index is located on page __.
<PAGE>
PART I
Item 1. Business.
Forward-looking statement advisory
This Annual Report on Form 10-K, as with some other statements made by the
Trust from time to time, has forward-looking statements. These statements
discuss business trends, year 2000 remediation and other matters relating to the
Trust's future results and the business climate and are found, among other
places, at Items 1(c)(3), 1(c)(4), 1(c)(6)(ii) and 7. In order to make these
statements, the Trust has had to make assumptions as to the future. It has also
had to make estimates in some cases about events that have already happened, and
to rely on data that may be found to be inaccurate at a later time. Because
these forward-looking statements are based on assumptions, estimates and
changeable data, and because any attempt to predict the future is subject to
other errors, what happens to the Trust in the future may be materially
different from the Trust's statements here.
The Trust therefore warns readers of this document that they should not
rely on these forward-looking statements without considering all of the things
that could make them inaccurate. The Trust's other filings with the Securities
and Exchange Commission and its Confidential Memorandum discuss many (but not
all) of the risks and uncertainties that might affect these forward-looking
statements.
Some of these are changes in political and economic conditions, federal or
state regulatory structures, government taxation, spending and budgetary
policies, government mandates, demand for electricity and thermal energy, the
ability of customers to pay for energy received, supplies of fuel and prices of
fuels, operational status of plant, mechanical breakdowns, availability of labor
and the willingness of electric utilities to perform existing power purchase
agreements in good faith. Some of these cautionary factors that readers should
consider are described below at Item 1(c)(4) - Trends in the Electric Utility
and Independent Power Industries.
By making these statements now, the Trust is not making any commitment to
revise these forward-looking statements to reflect events that happen after the
date of this document or to reflect unanticipated future events.
<PAGE>
(a) General Development of Business.
Ridgewood Electric Power Trust IV, the Registrant hereunder (the "Trust"),
was organized as a Delaware business trust on September 8, 1994 to participate
in the development, construction and operation of independent power generating
facilities ("Independent Power Projects" or "Projects") and similar capital
projects in the environmental and infrastructure areas (also "Projets").
Ridgewood Energy Holding Corporation ("Ridgewood Holding"), a Delaware
corporation, is the Corporate Trustee of the Trust.
The Trust sold whole and fractional shares of beneficial interest in the
Trust ("Investor Shares") at $100,000 per Investor Share, and terminated its
private placement offering on September 30, 1996. It raised approximately
$47,680,000. Net of offering fees, commissions and expenses, the offering
provided approximately $39,500,000 for investments in the development and
acquisition of Independent Power Projects and operating expenses. The Trust has
956 holders of Investor Shares (the "Investors"). As described below in Item
1(c)(2), the Trust has invested approximately $29.2 million of its funds to the
acquisition of interests in four Independent Power Projects, capital equipment
and in a used tire reprocessing facility.
The Trust is organized to be similar to a limited partnership. Ridgewood
Power LLC (the "Managing Shareholder"), a Delaware corporation, is the Managing
Shareholder of the Trust. For information about the merger of Ridgewood Power
Corporation, the prior Managing Shareholder, into Ridgewood Power LLC, see Item
10(b) - Directors and Executive Officers of the Registrant - Managing
Shareholder.
In general, the Managing Shareholder has the powers of a general partner
of a limited partnership. It has complete control of the day-to-day operation of
the Trust and as to most acquisitions. The Managing Shareholder is not regularly
elected by the owners of the Investor Shares (the "Investors"). The Managing
Shareholder and the Independent Trustees meet together as the Board of the Trust
and take certain actions, such as approval of the management agreement with the
Managing Shareholder and approval of acquisitions with related parties. The
Board of the Trust also provides general supervision and review of the Managing
Shareholder but does not have the power to take action on its own. The
Independent Trustees do not have any management or administrative powers over
the Trust or its property other than as expressly authorized or required by the
Declaration of Trust (the "Declaration").
The Corporate Trustee acts on the instructions of the Managing Shareholder
and is not authorized to take independent discretionary action on behalf of the
Trust. See Item 10 - Directors and Executive Officers of the Registrant below
for a further description of the management of the Trust.
The following chart summarizes some of these relationships.
<PAGE>
Ridgewood Electric Power Trust IV and certain affiliates
(some entities and relationships omitted)
Robert E. Swanson Family trusts
x x (Mr. Swanson has
Sole manager x x sole voting and
Chief executive officer x x investment power)
Owner of 46% of equity x x Owners of 54% of equity
_________________X__________________X______________________________
x x x x x x
x x x x x x
x x x x x x
Ridgewood Ridgewood Power Ridgewood Ridgewood Ridgewood Ridgewood
Securities Management LLC Power LLC Energy Power VI Capital
Corporation Holding LLC Management
Corporation LLC
Operates power Corporate Manager
Placement plants for five Managing Trustee Co-Managing of two
agent power trusts Shareholder for all Shareholder venture
("Ridgewood ("RPMCo") of six six trusts (dormant) capital
Securities") trusts x of the funds &
("Ridgewood x Growth Fund marketing
Power") x ("Power VI Co") affiliate
x x x ("Ridgewood
x x x Capital")
x x x x
______________________________x____________x_____________ x x
x x x x x x x x
x x x x x x x x
Ridgewood Ridgewood Ridgewood Ridgewood Ridgewood The Ridgewood x
Electric Electric Electric Electric Electric Power Growth x
Power Trust Power Trust Power Trust Power Trust Power Trust Fund x
I II III IV V (the x
("Power I") ("Power II") (Power III") (the ("Power V") " Growth x
"Trust") Fund") x
x
________________________________X__
x x
x x
Ridgewood Capital Ridgewood Capital
Venture Partners Venture Partners II
(the "Venture Capital Funds")
The Trust made an election to be treated as a "business development
company" under the Investment Company Act of 1940, as amended (the "1940 Act").
On January 24, 1995, the Trust notified the Securities and Exchange Commission
of such election and registered the Investor Shares under the Securities
Exchange Act of 1934, as amended (the "1934 Act"). On March 24, 1995 the
election and registration became effective. Effective October 3, 1996, the
Trust, with the approval of the Investors, withdrew its election to be a
business development company so that it could make investments together with
other programs sponsored by the Managing Shareholder without requesting
exemptive relief from the Securities and Exchange Commission. The Trust
covenanted to comply with most of the substantive restrictions on business
development companies, other than certain transactions with affiliated persons.
Unlike three prior investment programs that the Managing Shareholder has
sponsored in the independent power industry, the Trust consolidates its
subsidiaries' financial statements with its own for purposes of this Annual
Report on Form 10-K.
(b) Financial Information about Industry Segments.
The Trust has been organized to operate in only one industry segment:
independent power generation and similar facilities.
(c) Narrative Description of Business.
(1) General Description.
The Trust was formed to participate primarily in the development,
construction and operation of independent electric power projects that generate
electricity for sale to utilities and other users, and that might provide heat
energy as well to users. The Trust was also authorized to invest in capital
projects or processing plants that were anticipated to earn cash flows similar
to those of independent electric power projects.
Historically, producers of electric power in the United States consisted of
regulated utilities and of industrial users that produced electricity to satisfy
their own needs. The independent power industry in the United States was created
by federal legislation passed in response to the energy crises of the 1970s. The
Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), requires
utilities to purchase electric power from "Qualifying Facilities" (as defined in
PURPA), including "cogeneration facilities" and "small power producers," and
also exempts these Qualifying Facilities from most utility regulatory
requirements. Under PURPA, Projects that are Qualifying Facilities are generally
not subject to federal regulation, including the Public Utility Holding Company
Act of 1935, as amended, and state regulation. Furthermore, PURPA generally
requires electric utilities to purchase electricity produced by Qualifying
Facilities at the utility's avoided cost of producing electricity (i.e., the
incremental costs the utility would otherwise face to generate electricity
itself or purchase electricity from another source). The Providence, Maine Hydro
and Maine Biomass Projects are Qualifying Facilities.
(2) The Trust's Investments.
(i) Providence Project. The Trust and Ridgewood Electric Power Trust III, a
similar investment program sponsored by the Managing Shareholder ("Ridgewood
Power III"), acquired in April 1996 all of the equity interest in the Providence
State Landfill Power Plant, located near Providence, Rhode Island. Ridgewood
Power III invested $7.1 million in the Project and the Trust invested $12.9
million, which was the remainder of the $20 million investment in the Project.
The acquisition cost of the Project was approximately $15.5 million (including a
$3 million partial prepayment of Project debt as a condition of obtaining the
lenders' consents and transaction costs) and the remainder of the investment by
the programs represents funds applied to operating reserves, working capital and
cash reserves for capital improvements and expansion. The Project is encumbered
by $4.8 million of debt maturing in installments through 2004. Ridgewood Power
Management Corporation ("RPMCo"), a service company under common control with
the Managing Shareholder, as described below, operates the Project and the Trust
reimburses it for its costs and expenses.
The Project burns methane gas (the major component of natural gas)
generated by the decomposition of garbage in the landfill as fuel for a 13.8
Megawatt capacity electric generation plant. The facility has been in operation
since 1990 and has a Power Contract for 12.0 Megawatts with New England Power
Corporation with a 22 year term remaining.
The Project leases the right to use the landfill site from the Rhode Island
Resource Recovery Corporation, a state agency, for a royalty of 15% of net
Project revenues (increasing from 15% to 18% in 2006) until 2020. The Project in
turn subleases those rights to Central Gas Limited Partnership ("Gasco"). Gasco,
which is not affiliated with the Trust, operates and maintains the piping system
and other facilities to collect the methane gas from the landfill and supply it
to the Project. Gasco pays a fixed rent, computed on the basis of the Project's
generating capacity, to the Project under the sublease, and the Project in turn
buys its fuel from Gasco at a formula price per kilowatt-hour generated by the
Project.
Since the Trust purchased the Project in April 1996, average output from
the original eight engine-generator sets has risen by approximately 25% from 9.2
Megawatts in the first three months of 1996 to 12.2 Megawatts in December 1996
and 11.5 Megawatts in 1997. Since August 1997, sales have approached the 12.0
Megawatt maximum under the Power Contract. In order to increase output to the
maximum and to allow engines to be rotated off-line for preventative
maintenance, an additional engine and generator set were installed at the
Project in spring 1997. Although this increased nominal Project capacity by
approximately 12%, the actual benefit is the ability to have one engine off-line
at any time for maintenance and still produce the entire 12.0 Megawatts that can
be sold under the existing Power Contract. Net earnings from the Project (less
the minority interest of Ridgewood Power III) for 1999 totalled $310,000, down
from $530,000 for 1998. The decrease reflected higher 1999 expenditures for
equipment maintenance and loss of income resulting from the unscheduled outage
of two engines.
(ii) California Pumping Project
On December 31, 1995, the Trust purchased a package of 11 irrigation
service engines which have an aggregate power output equivalent to 1.2 Megawatts
(the "California Pumping Project") located in Ventura County, California, for a
cash purchase price of approximately $354,000. The Trust purchased the Project
from Ridgewood Power III for the same price paid by Ridgewood Power III for the
assets to the unaffiliated seller. In 1996, the Trust bought 9 additional
engines with a rated equivalent capacity of 1.2 Megawatts from unaffiliated
sellers at a price of $344,000. The total investment in the Project at December
31, 1999, after accounting for depreciation, was $442,000.
The California Pumping Project has been operating since 1992 and uses 20
natural-gas-fired reciprocating engines to provide power for irrigation wells
which furnish water for orchards of lemon and other citrus trees. The power is
purchased by local farmers and farmers' co-operatives at a price which
represents a discount from the equivalent price the customers would have paid to
purchase electric power.
Until October 1998, the Trust had a management contract with the prior
operator of the Project that provided that the operator's compensation was based
on the amount of pumping power provided by each engine, computed on the basis of
the equivalent amount of kilowatt-hours of electricity that would have been
needed to provide that amount of pumping power. Until January 1998, the Trust
received all cash flow from the engines up to $.02 per equivalent kilowatt-hour
for the first 3,000 kilowatt-hours per year, and $.01 per additional
kilowatt-hour in that year. The operator, who was responsible for all operating
costs, received the remainder. Beginning in January 1998, the Trust received
one-half of revenues after deduction of a 6/10 cent per equivalent kilowatt-hour
maintenance fee and costs of fuel for the engines. In October 1998 the Trust and
the operator terminated the management agreement and the Trust paid the operator
$94,000 to reimburse it for installation costs advanced by the operator. RPMCo
has operated the Project since that time.
Ridgewood Electric Power Trust II, a prior investment program sponsored by
the Managing Shareholder ("Ridgewood Power II"), owns a package of similar
engines located on different sites and operated under identical terms. The
engines operate independently of each other and revenues and expenses for each
Trust are segregated from those of the other.
(iii) Maine Hydro Projects
On December 23, 1996, the Trust purchased from Consolidated Hydro, Inc. a
50% interest in 14 small hydroelectric projects located in Maine. In order to
increase diversification of the Trust's investments, the remaining 50% interest
was purchased by Ridgewood Electric Power Trust V ("Ridgewood Power V"), a
similar investment program organized in 1996 by the Managing Shareholder. Each
Trust paid approximately $6,700,000 for its interest The jointly owned
partnership that acquired the Project also assumed a lease obligation in the
amount of $1,005,000.
The 14 hydroelectric projects have an aggregate rated capacity of 11.3
megawatts. All electricity generated by the projects over and above their own
requirements is sold to either Central Maine Power Company or Bangor Hydro
Company under long-term power purchase contracts. Eleven of the contracts expire
at the end of 2008 and the remaining three expire in 2007, 2014 and 2017.
Certain of the contracts are subject to price redeterminations in 2001 based on
the Maine Public Utilities Commission's computations of avoided cost.
The Trust's net equity in the income of the Maine Hydro Projects for 1999
was $849,000 (a 15.0% return on equity), up from $658,000 (a 10.6% return on
equity) in 1998.
The Trusts have entered into a five year operating and maintenance
agreement with CHI Energy, Inc. under which a subsidiary of CHI Energy will
manage and administer the projects for a fixed annual fee of $307,500 (adjusted
upwards for inflation), plus an annual incentive fee equal to 50% of the excess
of aggregate net cash flow over a target amount of $1.875 million per year. The
maximum incentive fee is $112,500 per year; to the extent the annual net cash
flow exceeds $2.1 million, the excess will be carried forward to future years;
to the extent that the annual net cash flow is less than $1.875 million, the
deficit will be carried forward to future years. In addition, the operator will
be reimbursed for certain operating and maintenance expenses. In 1999, the
operator was paid a total of $323,000 for operating and incentive fees, down
from $429,000 in 1997. The agreements has a five-year term, expiring on June 30,
2001, and can be extended for two additional five-year terms by mutual consent.
(iv) Maine Biomass Projects
On July 1, 1997, the Trust and Ridgewood Power V purchased a preferred
membership interest in Indeck Maine Energy, L.L.C., an Illinois limited
liability company ("Indeck Maine") that owns two electric power generating
stations fueled by waste wood at West Enfield and at Jonesboro, Maine. The Trust
and Ridgewood Power V purchased the interest through a limited liability company
owned equally by each. The Trust's share of the purchase price was $7,298,000
and Ridgewood Power V provided an equal amount of the total purchase price.
The junior membership interest in Indeck Maine is owned by Indeck Energy
Services, Inc. ("Indeck"). The preferred membership interest entitles the Trust
and Ridgewood Power V to receive all net cash flow from operations each year
until they receive an 18% annual cumulative return on their capital
contributions to Indeck Maine. Any additional net operating cash flow in that
year is paid to Indeck until the total paid to it equals the amount of the 18%
preferred return for that year, without cumulation. Any remaining net operating
cash flow for the year is payable 25% to the Trust and Ridgewood Power V
together and 75% to Indeck unless the Trust and Ridgewood Power V recover their
capital contributions from proceeds of a capital event. Thereafter, these
percentages change to 50% each. All non-operating cash flow, such as proceeds of
capital events, is divided equally between (a) the Trust and Ridgewood Power V
and (b) Indeck.
Under Indeck Maine's amended operating agreement, if the Trust and
Ridgewood Power V did not receive annual distributions at least equal to the 18%
preferred return requirement or if Indeck Maine, after a cure period, failed to
make distributions to them in accordance with the operating agreement, they had
the right to designate a majority of the managers of Indeck Maine. Under that
arrangement, until March 1999 Indeck Operations, Inc., an affiliate of Indeck,
managed the plant and was reimbursed for its costs. In addition, the three
managers nominated by the original Indeck Maine members received aggregate
annual fees of $300,000 and certain other fees were payable to Indeck
affiliates. The management agreement could be terminated on notice if the Trust
and Ridgewood Power V obtained the right to designate a majority of the managers
of Indeck Maine.
The Trust, Power V and Indeck agreed, effective March 1, 1999, to terminate
the arrangements described above and to transfer operating control of the
Projects to the Trust and Ridgewood Power V. This has occurred and the Trust and
Ridgewood Power V have engaged RPMCo to operate the two Projects. RPMCo is doing
so and charges its expenses to Indeck Maine at its cost.
Each of the projects has a 24.5 megawatt rated capacity and uses steam
turbines to generate electricity. The fuel is waste wood chips, bark, brush and
similar biomass. Both projects are Qualifying Facilities. The Maine Biomass
Projects are members of the New England Power Pool ("NEPOOL"), an association of
New England generators, transmission utilities, distribution utilities, power
marketers and others. NEPOOL's function is to run the New England electric grid
in the most reliable way possible and to reduce electric costs and
uncertainties. NEPOOL's control and market regulation responsibilities are
managed by ISO-New England, Inc., an independent, non-profit management company.
Under current economic conditions, the Maine Biomass Projects would not be
profitable if they were operated as "base load" plants that run most of the
time. Instead, they are operated as peak load plants on those few days per year
(typically during summer heat waves) when there are power and reserve shortages
in New England. During the rest of the year, the Projects are shut down but are
capable of being restarted on five to ten days' advance notice. Because the
Projects are capable of providing electricity, they are entitled to sell their
"installed capability," a measurement of the rated ability of a generating plant
to create electric power. Plants are credited with installed capability whether
or not they run. For an additional discussion of installed capability and other
concepts related to electricity pricing, see (3) - Plant Operation, below. Each
distribution utility that is a member of NEPOOL must own or purchase installed
capability on a monthly basis that at least equals its expected load for the
month (the maximum amount of power that its customers may demand) plus mandated
reserves. Generating facilities may enter into contracts to sell installed
capability or may auction it through the ISO. The Maine Biomass plants sold
installed capability throughout 1999 under short-term bilateral contracts and
thus earned revenues (approximately $733,000) without generating material
amounts of electric power. Prices for installed capability have tended to
decline slightly from 1999 to 2000, which may reflect seasonal variations in
demand for capability but which may also reflect maturation of the market and
the startup or anticipated startup of several new generating stations in New
England, which would increase the supply of installed capability.
In addition, the Maine Biomass Projects operated on approximately seven
days in June, July, October and December 1999 on dispatch by the ISO. As
described below at Item 1(c)(3) - Plant Operation, the Projects have claimed
that the ISO owes them approximately $14 million for the electricity products
they provided on those days and the ISO has claimed that no material revenues at
all are due to the Projects. A description of these disputes is found below.
The cost to the owners of Indeck Maine for maintaining the facilities in
operable condition and for fixed costs such as taxes and insurance was
approximately $2.5 million for both projects in 1999. Additional variable costs
were incurred to run the Projects on the days they were dispatched by the ISO
and on days on which capability or air quality tests were run.
Indeck Maine funded the approximately $2.2 million difference between
the Maine Biomass projects' revenues and operating expenses by borrowing from
its members. The Trust provided 25% of the loans ($525,000 in 1998), Ridgewood
Power V also provided an equal 25% and the remaining 50% was provided by Indeck,
all on the same terms. Indeck Maine issued demand promissory notes bearing
interest at 5% per year to evidence the indebtedness. Neither Indeck nor its
affiliates are affiliated with or has any material relationship with the Trust,
Ridgewood Power V, their Managing Shareholder or their affiliates, directors,
officers or associates of their directors and officers.
(v) Santee River Rubber Company
The Trust and Power V have purchased preferred membership interests in
Santee River Rubber Company, LLC, a South Carolina limited liability company
("Santee River"). Santee River is building a waste tire and rubber processing
facility (the "Facility") located in Berkeley County, South Carolina
approximately 90 miles north of Charleston, South Carolina. The Trust and Power
V purchased the interest through a limited liability company owned one-third by
the Trust and two-thirds by Power V. The Trust's share of the $13,470,000
purchase price for the membership interest in Santee River was $4,490,000 and
Power V provided the remaining $8,980,000 of the price.
The Facility is designed to receive and process waste tires and other
waste rubber products and produce fine crumb rubber of various sizes. The
Facility basically freezes the tires, using liquid nitrogen obtained from a
nearby air-processing plant, shatters the frozen rubber into small pieces, and
grinds and processes the pieces to remove tire cord, steel belts and other
non-rubber materials. The product is crumb-like pieces of rubber. The processing
system includes both ambient and cryogenic processing equipment using liquid
nitrogen. In addition, magnets and other screening equipment will be used to
separate and remove ferrous material and fibers from the rubber. Santee River
believes that the final crumb rubber product will be fine enough for use in
manufacturing new tires or to replace virgin rubber in many applications. The
Facility is being constructed on an approximately 30-acre site (the "Site") in
Berkeley County, South Carolina owned by Santee River. The Site is mortgaged as
security for the bonds issued for the Facility.
Construction was substantially completed in February 2000 and the Facility
is now undergoing testing. Some remedial work is underway and the Trust
currently expects the testing period to end in early summer 2000, after which
the Facility will go into limited operations. Operation at full capacity is
expected to begin in late summer 2000.
Until January 2000, Santee River paid the Trust and Power V a fixed
distribution of 12% per year on $11,500,000 of the total capital they
contributed. The Trust and Power V are entitled to a cumulative annual
distribution preference equal to 12% of contributed capital from January 2000
until operations begin. The Trust does not anticipate any payment of that
preference until the Project has significant cash flow from operations. After
operations begin, the preferred membership interest entitles the Trust and Power
V to receive all available operating cash flow annually from Santee River after
payment of debt service and other obligations until the Trust receives a
cumulative 20% annual return on its capital investment. Thereafter, the Trust
and Power V are entitled to receive 25% of any remaining operating cash flow
available for distribution in that year from Santee River. All non-operating
cash flow, such as proceeds of capital events, is divided equally between (a)
the Trust and Power V and (b)the other owner of Santee River. All amounts and
tax items the Trust and Power V receive from Santee River are shared one-third
by the Trust and two-thirds by Power V, with neither having any preference over
the other. The Trust and Power V have the joint right to designate two of the
five managers of Santee River and have the further right to remove a third
manager and designate a successor in the event of certain defaults under Santee
River's Operating Agreement. The remaining equity interest in Santee River is
owned by a wholly-owned subsidiary of Environmental Processing Systems, Inc.
("EPS") of Garden City, New York. EPS is the developer of the Facility. EPS
contributed the contracts, permits, plans and other intangible property for the
construction of the Facility that EPS generated prior to this transaction. Until
a default, EPS has the right to designate three managers of Santee River.
Santee River estimates that approximately $52,680,000 will be needed to
construct the Facility and begin operations. After paying costs of the financing
(which included a $167,000 payment to the Trust and a $333,000 payment to Power
V from Santee River to defray the trusts' transaction costs), Santee River had
approximately $16,500,000 available. At the same time as it sold the Trust and
Power V their membership interest, Santee River borrowed $16,000,000 through
tax-exempt revenue bonds sold to institutional investors and another $16,000,000
through taxable convertible bonds sold to qualified institutional purchasers. It
also obtained $4,500,000 of subordinated financing from the general contractor
for the Facility, which is only repayable if the Facility meets specified
construction and performance criteria.
The Facility is being constructed by Bateman Engineering, Inc. (the
"Contractor") pursuant to a turnkey construction agreement between the
Contractor and Santee River for a fixed price of $30.5 million. The Contractor's
obligations under the Construction Contract will be guaranteed by its affiliate,
Bateman Project Holdings Limited, a South African company. Pursuant to the
Construction Contract, the Contractor has agreed to defer $4.5 million of its
fixed construction price and to receive such amount during the initial 4 years
of Facility operation. A pilot facility was completed in February 1999 for
testing of the equipment and processes and product from the pilot facility met
or exceeded specifications. Further testing is necessary before any conclusion
can be drawn as to the feasibility of the equipment and processes.
Santee River has entered into long-term agreements for supply of its
requirements of waste tires and other waste rubber as its raw material, of
liquid nitrogen for cryogenic processing and of electricity (from a local
electricity cooperative). Santee River intends to sell the crumb rubber
manufactured at the Facility to various companies in the tire, plastics, rubber,
building products, adhesives and paint industries.
EPS on behalf of Santee River has obtained short term crumb rubber
sales contracts for approximately 30% of the Facility's expected output with
several major rubber products manufacturers. Each contract is contingent upon
successful testing of the Facility's output.
EPS provides administrative services to Santee River during the
construction and operation of the Facility at its cost (including direct and
indirect costs and allocable overhead). Neither Santee River nor EPS is
otherwise affiliated with or has any material relationship with the Trust, Power
V, their Managing Shareholder or their affiliates, directors, officers or
associates of their directors and officers.
The Trust has substantially completed its investment program.
Project Operation.
The Trust, through the Managing Shareholder, operates the Providence
Project, the California Pumping Project (since October 1, 1998) and the Maine
Biomass Projects (since March 1, 1999). The Managing Shareholder has organized
RPMCo to provide operating management for facilities operated by its investment
programs. See Item 10 - Directors and Executive Officers of the Registrant for
further information regarding the Operation Agreement and RPMCo. The Maine Hydro
Projects are managed by their former owner, CHI Energy, Inc. (formerly known as
Consolidated Hydro, Inc.), which owns other hydroelectric facilities in the
region. Until October 1998, the California Pumping Project was managed by HEP,
Inc., its former developer, and until March 1999 the Maine Biomass Plants were
managed by their former owner, Indeck Maine.
The Trust's decisions to purchase electric generating Projects in New
England were driven in part by the relatively high prices paid for energy in the
region and a shortage of generating capacity caused in large part by the
shutdown of four large nuclear power plants previously owned by Northeast
Utilities, Inc. and other utilities for regulatory and safety violations. See
the discussion at (4) - Trends in the Electric Utility and Independent Power
Industries and (5) - Competition below for information regarding proposed
capacity additions and cost factors that may offset that shortage.
The overall demand for electrical energy is somewhat seasonal, with
demand usually peaking in the summertime as a result of the increased use of air
conditioning. Peak periods in New England generally are limited to daytime and
evening hours in the summer months (with a smaller peak in Maine for light and
heating during the winter) and power prices are significantly higher during
those periods.
(i) Providence and Maine Hydro Projects. The Providence and Maine Hydro
Projects are Qualifying Facilities under PURPA and have entered into long-term
power purchase agreements ("Power Contracts") with their local distribution
utilities. Under the Power Contracts for the Providence and Maine Hydro
Projects, the local utilities are obligated to purchase the entire output of the
Projects (up to rated levels)at formula prices. No separate payments are made
for capacity or capability and all payments under the Power Contracts are made
for energy supplied.
The utility purchaser at the Providence Project, New England Power Company,
pays 3.0 cents per kilowatt-hour for all power provided, adjusted for inflation
based on changes in the consumer price index since 1989. In addition to that
base amount, it pays a flat additional 3.5 cents per kilowatt-hour for peak
period power and 1.5 cents for non-peak power. Additional adjustments are made
to reduce payments in later years so as to levelize total amounts paid by the
utility.
The Maine Hydro Projects are licensed or operated as "run-of-river"
facilities, which means that the amount of water passing through the turbines is
directly dependent upon the fluctuating level of flow of the river or stream.
The Projects have a very limited ability to store water during high flows for
use at low flow periods. As a result, these Projects are unable to earn capacity
payments and are often unable to produce high output in the peak summer and
winter months when spot electricity rates are highest. Instead, they produce
electric energy and sell it as generated at the fixed rates provided in the
Power Contracts. Distributions of net cash flow from the Maine Hydro Projects,
whose financial statements are not consolidated with those of the Trust, are not
treated as operating revenues. Instead they are considered to be income from
investments to the extent of net earnings and as a return of capital otherwise.
The Providence and Maine Hydro Projects use landfill gas or
hydroelectric energy and are not subject to fuel price changes or supply
interruptions. Because the Maine Hydro Projects are "run-of-river" hydroelectric
plants, their output is dependent upon rainfall and snowfall in the areas above
the dams and output has varied in the range of 30% over or 25% below the average
output from 1987 through 1997. Output is generally lowest in the summer months
and in the winter and highest in the spring and fall.
(ii) Maine Biomass plants
The Maine Biomass Projects burn wood waste, including brush and chips
from woodcutting or processing of raw wood at paper mills or sawmills. The price
of wood waste fluctuates and is a primary determinant of whether the Projects
can run profitably or not. The major causes of the fluctuation are changes in
woodcutting or wood processing volumes caused by general economic conditions,
increases in the use of wood waste by paper mills for their own cogeneration
plants, changes in demand from competing generating plants using wood waste or
paper mill refuse and weather conditions. The cost of wood waste is currently
significantly in excess of that anticipated at the time the Maine Biomass
Projects were purchased.
Although the Maine Biomass Projects are Qualifying Facilities, they do
not have long-term Power Contracts and sell their capacity and output on the
market. In 1999, NEPOOL instituted a somewhat competitive market, managed by the
ISO, for generators to sell capacity and output to utilities and other entities
that distribute electricity ("loads"). Generators may sell directly to loads on
a bilateral basis, or they may sell to the ISO. The ISO dispatches generating
plants and takes their power in accordance with offers and its estimate of the
most economical means of providing sufficient reliable electricity. It computes
the clearing price for each electrical product on an hourly basis (monthly for
installed capability), bills loads for their shares of the products and is to
pay generators in accordance with the generators' offers and the market rules.
In 1999, seven "electrical products" were bought and sold on the ISO's market.
In addition to installed capability and energy (the power actually used by
consumers), the market included four types of reserves (basically, the ability
to turn on or increase the operating rate of electric generators within
specified times to provide additional power quickly) and automatic generation
control (a related ability).
The Maine Biomass Projects submitted offers to sell their electrical
products for the summer of 1999 at relatively high prices with the expectation
that the plants would be called upon by ISO only in the most extreme conditions.
This strategy was necessary because of the relatively high costs of operating
the plants without a long-term base load contract. The ISO dispatched the plants
to run on only three days during June 1999 when NEPOOL was short of resources
and accepted the Projects' offered prices, which would have entitled the
Projects to receive significant revenues for those three days.
In early July 1999, the ISO informed NEPOOL members that it would pay lower
prices than those posted on its market Website on those three days in June.
After considering ISO's stated reasons for reducing the posted prices and ISO's
actions during June, RPMCo concluded that ISO was determined to intervene in the
markets and to prevent prices from rising to clearing levels during shortage
periods. This would prevent profitable operation of the Projects. Accordingly,
RPMCo revised its offer strategy to hold the Maine Biomass Projects off the
market for the remainder of the summer and made further revisions at the end of
September.
In early October 1999, the ISO informed RPMCo that a scheduled transmission
outage for October 16 and 17 required ISO to activate all possible generation in
Maine. The Maine Biomass Projects, which had been shut down and which did not
have full crews available, had a pre-existing offer to supply electric energy at
an high price, reflecting the costs of restarting the plants, obtaining a crew
on short notice and covering fixed costs. The ISO accepted the offer subject to
its market rules and conditions. The Maine Biomass Plants operated as dispatched
by the ISO on October 16 and, if they were paid in accordance with their offer
terms, would have received in excess of $2.2 million. In November 1999, the ISO
advised RPMCo that it would pay a total of $5,000 for the energy the Projects
produced on October 16. The ISO has stated that, in its opinion, the Projects
had monopoly-like market power on October 16 and that under the existing market
rules it was only obligated to pay a rate based on variable costs unless the
Projects could cost-justify a higher rate.
RPMCo is vigorously disputing all elements of the ISO's arguments for
reducing the June and October payments and is preparing to bring a legal action
in the appropriate forum.
The Maine Biomass Projects ran on approximately seven other days during
1999 in order to undergo NEPOOL capacity testing, testing for air pollution
control permit requirements or modifications, and to meet ISO dispatch orders on
three of those days. On each of the days, the ISO cancelled the orders just
before the plants would have begun providing synchronized electricity to NEPOOL.
As a result, the plants had to be crewed and restarted but no revenues were
earned. RPMCo is also disputing these actions by the ISO.
(iii) California Pumping Project
Although drier weather in 1999 increased revenues for the California
Pumping Project over 1998 levels, in late 1999 petroleum prices rose sharply
because of supply reductions by the Organization of Petroleum Exporting
Countries, continued high demand, cold weather and previous drawdowns of
inventory. As often occurs when oil prices rise, natural gas fuel prices also
rose. Increased demand for natural gas, including use as power station fuel, and
cold weather also contributed to the price increases. The price of the Pumping
Project's fuel has almost doubled since January 1999. As a result, the
California Pumping Project is operating at a loss and is expected to continue at
that level unless gas prices fall significantly. Hydrocarbon fuels, such as
natural gas, have been generally available in recent years for use by
Independent Power Projects, although there have been serious supply impairments
for both oil and natural gas at times during the last 20 years. Market prices
for natural gas and oil have fluctuated significantly over the last few years
and those fluctuations are expected to continue.
(iv) Santee River Project
The Santee River Project is expected to begin full scale operation in
summer 2000, assuming successful completion of performance tests. The primary
raw materials for the Santee River Project are used tires, which are readily
available, electricity (purchased from the local rural electric cooperative) and
liquid nitrogen for freezing the tires (which is available, as described above,
under a long-term contract from a producer of liquid oxygen). Accordingly, the
Santee River Project is not currently expected to be subject to unexpected,
adverse raw material price changes or supply interruptions.
(v) General considerations
Customers of Projects that accounted for more than 10% of annual revenues
from operating sources to the Trust in each of the last three fiscal years are:
Calendar year
1999 1998 1997
New England power Corporation 89.4% 91.0% 90.0%
(Providence Project)
Note that - the financial statements of the Maine Hydro Projects, the Maine
Biomass Projects and the Santee River Project are not consolidated with those of
the Trust and, accordingly, their revenues are not considered to be operating
revenues.
The major costs of an independent power Project while in operation will be
debt service (if applicable), fuel, taxes, maintenance and operating labor. The
ability to reduce operating interruptions and to have a Project's capacity
available at times of peak demand are critical to the profitability of a
Project. Accordingly, skilled management is a major factor in the Trust's
business.
Electricity produced by a Project is typically delivered to the purchaser
through transmission lines which are built to interconnect with the utility's
existing power grid, or in the case of the Maine Biomass Projects, via utility
lines owned by Bangor Hydro-Electric Company ("Bangor Hydro") to the ISO's
transmission facilities. Bangor Hydro's tariffs for transmission and for
electricity demand (incurred by the need for start-up electricity at the Maine
Biomass Projects) imposed a significant burden on their potential profitability.
After extended investigation, the Managing Shareholder and Indeck Operations,
Inc. concluded that the Projects were eligible under regulations of the New
England Power Pool and ISO-New England to be considered as directly connected to
the ISO's "pooled transmission facilities." That status would significantly
reduce transmission charges for the Projects. Indeck Maine petitioned the New
England Power Pool and ISO-New England to recognize the Projects as being
connected to pooled transmission facilities and when those petitions were
disapproved, brought administrative complaints in October 1998 before the
Federal Energy Regulatory Commission ("FERC") alleging that the failures to
recognize the Projects were anti-competitive, in violation of system rules
approved by FERC actions and in violation of FERC deregulatory orders. Those
complaints were rejected by FERC in February 2000 and RPMCo is considering
whether further proceedings with other similarly situated NEPOOL members will be
appropriate. Indeck Maine has negotiated a package of tariff amendments and
special facilities agreements with Bangor Hydro that would remove most of the
tariff disadvantages. Bangor Hydro filed a request for approval of the tariff
changes with FERC in March 2000. The special facilities agreements will also
require approval by the Maine Public Utility Commission.
The technology involved in conventional power plant construction and
operations as well as electric and heat energy transfers and sales is widely
known throughout the world. There are usually a variety of vendors seeking to
supply the necessary equipment for any Project. So far as the Trust is aware,
there are no limitations or restrictions on the availability of any of the
components which would be necessary to complete construction and commence
operations of any Project. Generally, working capital requirements are not a
significant item in the independent power industry. The cost of maintaining
adequate supplies of fuel is usually the most significant factor in determining
working capital needs.
In order to commence operations, most Projects require a variety of
permits, including zoning and environmental permits. Inability to obtain such
permits will likely mean that a Project will not be able to commence operations,
and even if obtained, such permits must usually be kept in force in order for
the Project to continue its operations.
Compliance with environmental laws is also a material factor in the
independent power industry. The Trust believes that capital expenditures for and
other costs of environmental protection have not materially disadvantaged its
activities relative to other competitors and will not do so in the future.
Although the capital costs and other expenses of environmental protection may
constitute a significant portion of the costs of a Project, the Trust believes
that those costs as imposed by current laws and regulations have been and will
continue to be largely incorporated into the prices of its investments and that
it accordingly has adjusted its investment program so as to minimize material
adverse effects. If future environmental standards require that a Project spend
increased amounts for compliance, such increased expenditures could have an
adverse effect on the Trust to the extent it is a holder of such Project's
equity securities.
Of the 14 Maine Hydro Projects, six operate under existing hydroelectric
project licenses from the Federal Energy Regulatory Commission ("FERC") and two
have license applications pending. Changes to the six other, unlicensed Projects
(which are currently exempt from licensing) may trigger a requirement for FERC
licensing. FERC licensing requirements have become progressively more stringent
and often require that output of a Project that is being licensed or relicensed
be restricted in order to allow a more natural flow of water, that
archaeological and historical surveys be undertaken, that public access to
waterways be provided (sometimes requiring purchase of property rights by the
hydroelectric licensee) and that various site improvements be made. These
requirements can materially impair a project's profitability. See Item 1(c)(6) -
Business - Narrative Description of Business Regulatory Matters.
Trends in the Electric Utility and Independent Power Industries
There are numerous references for further information on the electric
power industry. Interested persons may particularly wish to refer to the U.S.
Department of Energy's Annual Energy Outlooks and special studies, prepared by
the department's Energy Information Administration (the "EIA"). Much of this
information is available on EIA's World Wide Web site at http://www.eia.doe.gov
under the "Electric" heading. Neither the Department of Energy nor EIA nor any
other agency of the United States Government has endorsed or approved the Trust
or the Investor Shares and the Trust takes no responsibility for the preparation
or content of the Department of Energy's publications.
(i) Qualifying Facilities with long-term Power Contracts
The Trust is somewhat insulated from recent deregulatory trends in the
electric industry because the Providence and Maine Hydro Projects are Qualifying
Facilities with long-term formula-price Power Contracts. Each Power Contract now
provides for rates in excess of current short-term rates for purchased power.
There has been much speculation that in the course of deregulating the electric
power industry, federal or state regulators or utilities would attempt to
invalidate these power purchase contracts as a means of throwing some of the
costs of deregulation on the owners of independent power plants.
To date, the Federal Energy Regulatory Commission and state authorities
have ruled that existing Power Contracts will not be affected by their
deregulation initiatives. The regulators have so far rejected the requests of a
few utilities to invalidate existing Power Contracts. Instead, most state plans
for deregulation of the electric power industry (including those in Maine) treat
the value of long-term Power Contracts that are above current and anticipated
market prices as "stranded costs" of the utilities. The utilities are to be
allowed to recover those costs during a transition period. This is typically
done by imposing a transition fee or surcharge on rates that is paid to the
utility.
No action has yet been taken by federal or state legislators to date to
impair Independent Power Projects' existing power sales contracts, and there are
federal constitutional provisions restricting actions to impair existing
contracts. There can not be any assurance, however, that the rapid changes
occurring in the industry and the economy as a whole would not cause regulators
or legislative bodies to attempt to change the regulatory structure in ways
harmful to Independent Power Projects or to attempt to impair existing
contracts. In particular, some regulatory agencies have urged utilities to
construe Power Contracts strictly and to police Independent Power Projects'
compliance with those Power Contracts vigorously.
Predicting the consequences of any legislative or regulatory action is
inherently speculative and the effects of any action proposed or effected in the
future may harm or help the Trust. Because of the consistent position of the
regulatory authorities to date and the other factors discussed here, the Trust
believes that so long as it performs its obligations under the Power Contracts,
it will be entitled to the benefits of the contracts.
In recent years, many electric utilities have attempted to exploit all
possible means of terminating Power Contracts with independent power projects,
including requests to regulatory agencies and alleging violations of even
immaterial terms of the Power Contracts as justification for terminating those
contracts. If such an attempt were to be made, the Trust might face material
costs in contesting those utility actions. Other utilities have from time to
time made offers to purchase and terminate Power Contracts for lump sums. No
such offer has been suggested or made to the Trust, although the Trust would
entertain such an offer.
Finally, the Power Contracts are subject to modification or rejection in
the event that the utility purchaser enters bankruptcy. There can be no
assurance that the utility purchaser will stay out of bankruptcy.
After the Power Contracts for the Providence and Maine Hydro Projects
expire at varying times from 2008 to 2020 or those contracts terminate for other
reasons, those Projects under currently anticipated conditions would be free to
sell their output on the competitive electric supply market, either in spot,
auction or short-term arrangements or under long-term contracts if those Power
Contracts could be obtained. There is no assurance that the Projects could then
sell their output or do so profitably. While the Providence Project is not
subject to natural gas price fluctuations and it may benefit from environmental
requirements for utilities to purchase power from environmentally favorable
sources, the supply of fuel gas from the landfill is not assured. Both it and
the Maine Hydro Projects may have diseconomies of small scale. The Trust is
unable to anticipate whether the Projects would have cost disadvantages or
advantages after their Power Contracts expire. It is thus impossible to predict
the profitability of those Projects after termination of the Power Contracts.
(ii) Maine Biomass Projects
The Maine Biomass Projects do not have long-term Power Contracts and
are exposed to the newly-deregulating market for electricity generation. Those
Projects are sometimes described as "merchant power plants" because they sell
their output on the open market. As a consequence of federal and state moves to
deregulate large areas of the electric power industry and the existence, spurred
by PURPA, of private competitors to electric utilities in the market for
generating electricity, a number of interrelated trends are occurring that will
affect merchant power plants.
Continued Deregulation of the Generating Market
The Comprehensive Energy Policy Act of 1992 (the "1992 Energy Act")
encourages electric utilities to expand their wholesale generating capacity by
removing some, but not all, of the limitations on their ownership of new
generating facilities that qualify as "exempt wholesale generators" ("EWG's")
and on their ability to participate in merchant power plants. Many state
electric utility regulators are considering plans to further encourage
investment in wholesale generators and to facilitate utility decisions to spin
off or divest generating capacity from the transmission or distribution
businesses of the utilities. As a result, merchant power plants in the future
will face competition not only from other independent power plants seeking to
sell electricity on a wholesale basis but also from EWG's, electric utilities
with excess capacity and independent generators spun off or otherwise separated
from their parent utilities.
Wholesale-level Access to Transmission Capacity
The 1992 Energy Act empowered FERC to require electric utilities and
power pools to transmit electric power generated by other wholesale generators
to wholesale customers. This process is referred to as "wheeling" the electric
power. Essentially, the generator contributes power to a utility or power pool
and is credited with that contribution, and the utility or power pool serving
the wholesale customer makes available that amount of electric power to the
customer and debits the generator. Wheeling is effected between power pools on a
similar basis.
Without access to transmission capacity, an independent power plant or
other wholesale generator can only sell to the local electric utility or to a
facility on which it is located (or, in some states, which adjoins its
location). FERC has required that transmission capacity owners or the power
pools that operate transmission facilities (such as NEPOOL through the ISO)
provide transmission capacity to all generators and power marketers on a
non-discriminatory basis pursuant to "open-access" tariffs. FERC in its recent
Order 2000 has mandated improvements to the power pool systems. When combined
with the increased competition in the generating area, this is likely to create
an electricity supply market that may profoundly change the operations of
electric utilities, consumers and independent power plants.
On April 24, 1996 the Federal Energy Regulatory Commission adopted
Order 888, which requires electric utilities and power pools to provide
wholesale transmission facilities and information to all power producers on the
same terms, and endorses the recovery by utilities of uneconomic capital costs
from wholesale customers who change suppliers. The utilities would also be
required to furnish ancillary services, such as scheduling, load dispatch, and
system protection, as needed. These rights, however, would apply only to sales
of new electric power over and above existing utility supply arrangements.
Non-utility wholesale deliveries of electricity have grown vigorously and
according to the federal government grew at the rate of 21% per year in the ten
years from 1986 to 1996.
The Maine Biomass Projects are dependent on wheeling power in order to
sell their capacity or energy to purchasers other than Bangor Hydro, as
described above. Order 888 takes no action to modify existing Power Contracts.
The order intends to create a competitive national market in electricity
generation and thus may create additional pressure on electric utilities to seek
changes to long-term power purchase contracts, as described further below. State
public utility regulatory agencies must also review and approve certain aspects
of wholesale power deregulation, and those agencies are currently holding
proceedings and making determinations. In addition to the FERC order or other
Congressional or regulatory actions that may result in freer access to
transmission capacity, agreements with Canada, and to a lesser extent with
Mexico, are leading toward access for those countries' generators to U.S.
markets. In particular, certain Canadian suppliers, such as HydroQuebec (the
Quebec provincial utility) are already offering substantial amounts of
electricity in New England, and more may be offered if sufficient transmission
capacity can be approved and built. These agreements may also afford access to
those countries' markets in the future for independent power plants. As a
result, there is the possibility that a North American wholesale market will
develop for electricity, with additional competitive pressures on U.S.
generators.
Retail-level Competition
An even more radical prospect for the electric power industry is
retail-level competition, in which generators would be allowed to sell directly
to customers by using (and paying a fee for) the local utility's distribution
facilities. Retail-level competition presupposes the ability to wheel power in
the appropriate amounts at economic costs from the generating Project to the
electric utility whose wires link to the retail customer (typically a large
industrial, commercial or governmental unit) and the ability to use the local
utility's facilities to deliver the electricity to the customer. In addition to
the business and regulatory issues arising from wholesale wheeling, retail-level
competition raises fundamental concerns as to the ability of utilities to
recover stranded costs at the generating and distribution levels, the
possibility that smaller customers will have less ability to demand pricing
concessions, incentives for governmental agencies to act as intermediaries for
consumers and the functions of state-level regulatory agencies in a
price-competitive environment which may be inconsistent with their traditional
price-setting and service-prescribing roles. Maine, Massachusetts and
Connecticut are implementing retail competition in April 2000; Rhode Island has
already done so.
Although retail deregulation is being implemented currently on a
state-by-state basis, there are some common elements which are expected to be
included in the Maine and Massachusetts deregulation plans. First, most
deregulating states will require that local utilities will be the "suppliers of
last resort," which are required to serve any customers in their existing
territories who do not purchase generated electricity from another source and
which are required to obtain adequate generating capacity to meet those needs.
Second, most deregulating states are requiring that utilities and other
suppliers of electricity work through "independent system operators" such as the
ISO, which coordinate purchase, transmission and sale of electricity between
generators and distribution utilities. Independent system operators will have
significant responsibility for supply reliability.
Third, most deregulating states are requiring that utilities be
compensated for stranded costs (which include long-term Power Contracts with
Independent Power Projects that are above current and anticipated market prices)
for a transition period. This is typically done by imposing a transition fee or
surcharge on rates that is paid to the utility. In some states, utilities are
being encouraged or ordered to issue bonds or other financial instruments to
retire stranded cost assets or contracts, supported by transition charges.
Fourth, many states are requiring local utilities to divest a large portion or
all of their generating assets or to sell their rights under long-term Power
Contracts. The states have cited concerns such as the anti-competitive effects
of allowing the utilities, which retain a monopoly over the wires that take
electricity the last stages to the customer, to own generating assets. Further,
the sale of assets (or above-market Power Contracts) sets a market price for
those assets and allows a somewhat objective computation of the stranded costs
related to those assets or contracts. For example, the true stranded cost of a
nuclear plant is approximately the difference between the value assigned to it
under state regulation and the price someone will pay for it at auction.
Fifth, utilities having stranded costs are expected to mitigate those
costs by buying out contracts or selling costly assets. Finally, many states are
attempting to protect generators who use "renewable fuels" or that are
considered to have environmental or social benefits. As discussed below, Maine
and Massachusetts are doing so.
Price and Cost Pressures
The pricing pressures that retail and wholesale deregulation are
bringing are expected to decrease the marginal cost of electricity. Competition
will force utilities and generators to reduce overhead and administrative costs,
to trim operation and maintenance costs and to more efficiently buy and use
fuel. Further, wholesale and retail deregulation and new generating technologies
discussed below are expected to significantly reduce capital costs. For example,
electric utilities currently maintain large amounts of generating capacity in
reserve to meet peak loads (for example, to serve customers during a heat wave
in July). According to the federal government, competition may lead to pricing
strategies that reduce these peak loads. Competition may also force utilities to
stop maintaining high-cost reserve capacity and to take greater risks. The
widening wholesale market for electricity may increase efficiency by allowing
utilities and power consumers to obtain distant, lower-cost capacity for reserve
purposes rather than maintain local, higher cost, underutilized reserve
capacity. Finally, political and economic pressures may induce market regulators
such as the ISO to manipulate prices downward. For these and other reasons, the
federal government currently estimates that national average electricity rates
in real terms (adjusted for inflation) will decline to about 6.3 cents per
kilowatt-hour in 2015 from the 1996 average level of 7.1 cents per
kilowatt-hour.
As these trends continue, high-cost generators will be disadvantaged
and may fail. The Trust's small-scale generating plants have tended to have
higher per-kilowatt hour costs (except for fuel) than new, large scale
generating plants. The fuel cost advantages, if any, of landfill gas,
hydroelectricity or waste biomass are thus critical to the competitiveness of
the Trust's merchant power plants. To date, the cost of wood chips and other
biomass suitable for use at the Maine Biomass Projects is not low enough to
allow the Projects to compete for base load contracts.
Conversely, decreases in electricity costs may reduce Santee River's
production costs, although Santee River's business plan does not assume any such
decreases.
New Generating Technologies and New Industry Participants
Recent improvements in turbine technology, coupled with what is seen as
the ample supply and relative cheapness of natural gas, have made gas turbines
the favored technology for new electric generating plants. The federal
government estimates that 80% of the new electric generating capacity to be
added from 1995 to 2015 will be fueled by natural gas and that the amount of
generation fueled by natural gas will increase from the current 10% to 29%.
According to the federal government, new gas turbines only need 15 days per year
of maintenance, on the average, compared with 30 days a year for steam turbines.
Although gas turbines historically have been used to meet peak demand rather
than baseload demand, new "combined cycle" units (which use heat from the
turbine's exhaust to drive a second steam or gas turbine) have thermal
efficiencies approaching 60% (60% of the theoretical maximum heat from the
burning gas is converted to electricity) and can be used as baseload units. In
contrast, steam turbines fired by coal have efficiencies in the 36% range and
have operating and maintenance costs higher than those of combined cycle plants.
Further, natural gas-fired turbines emit relatively low levels of sulfur
dioxide, particulates and complex carbon compounds and thus may have lower
environmental compliance costs than coal-fired or oil-fired plants. The federal
government estimates that combined cycle gas turbine plants alone will account
from 96,000 to 143,000 Megawatts of the 319,000 Megawatts of additional capacity
to be added in the next 17 years.
The new emphasis on natural gas-fired generation is causing large
natural gas transmission or brokering companies to enter the electricity
generation market rapidly. They have access to large volumes of gas and have the
ability to raise large amounts of capital. Accordingly, most new investment in
combined cycle gas Projects and other large-scale gas turbine Projects is being
made by these natural gas/energy companies or by large utilities that are
entering the competitive generation industry.
A number of large participants in the independent generating industry
have announced their intentions to build large gas turbine merchant power plants
in Connecticut, Massachusetts and Maine in sizes from 250 to 750 Megawatts. The
capacity of the proposed plants exceeds one-half of the total deficit in
capacity caused by the shutdown of the Northeast Utilities nuclear power plants.
If all or many of the announced plants were built, there might be a material
increase in low-cost generation capacity in the New England area. There have
also been reports, especially from the northeastern states, that large
non-utility generating companies and utilities entering the competitive
generating market outside their existing service territories are buying large
numbers of older plants from local utilities with the intention of replacing
them on site with new, large, natural gas-fueled plants. It is unclear whether
many of the announced merchant power plants will actually be built, given the
uncertainties of the market for electricity and the possibility that there may
be insufficient gas pipeline capacity or supplies to fuel all of the recently
announced plants.
Many companies, including affiliates of fuel suppliers and utilities,
have applied to FERC to act as electric power marketers, because they anticipate
that if wholesale wheeling becomes significant there will be strong demand for
brokers or market makers in electric power. It is uncertain whether power
marketers will become significant factors in the electric power market. A
related development is the creation of derivative contracts for hedging of and
speculation in electricity supplies, which may offer generators, utilities and
large industrial or commercial consumers the ability to reduce the volatility of
competitive prices. To date, the effects of derivative contracts on the market
for electricity in the Northeast have not been material.
Renewable Power
The pressures of competition are expected to harm the "renewable power"
segment of the industry, which includes the Maine Biomass Projects. "Renewable
power" (often called "green power") is a catchphrase that includes Projects
(such as solar, wind, small hydroelectric, biomass, geothermal and landfill-gas)
that do not use fossil fuels or nuclear fuels. Renewable power plants typically
have high capital costs and often have total costs that are well above current
total costs for new gas-turbine production. Many observers believe that
renewable power plants without existing Power Contracts (with the possible
exception of biomass, hydroelectric and geothermal plants with very low or zero
fuel costs) will be non-competitive in the new markets unless they are given
governmental protection. A number of states, including Massachusetts,
Connecticut and Maine, are requiring that retailers of electricity purchase a
certain minimum amount of electricity (often between 5% to 30% of their total
requirements) from renewable power sources. Although the Massachusetts and
Connecticut requirements were to have gone into effect by spring 2000, delays in
writing regulations defining renewable sources have effectively suspended the
requirements. The Trust does not anticipate that Massachusetts and Connecticut
or the other New England states that are considering such requirements will have
requirements for loads to purchase renewable energy before 2001. Because there
is yet no substantial enforced demand for renewable energy, these state
requirements have not had a material effect on the price of renewable energy.
Renewable energy is currently priced almost identically to that of non-renewable
energy. It is possible that even after renewable energy requirements come into
effect that the price for renewable power will not increase enough to make the
Maine Biomass Projects profitable.
Initial Effects of Trends
Within the last 12 months, several negative trends have developed in
the independent power sector. There have been industry-wide moves toward
consolidation of participants. A number of utilities and equipment suppliers
have proposed or entered into joint ventures to reduce risks and mobilize
additional capital for the more competitive environment, while many electric
utilities are in the process of combining, either as a means of reducing costs
and capturing efficiencies, or as a means of increasing size as an
organizational survival tactic.
A second trend has been the continuing divestiture of generating assets
by utilities, creating a competitive generating market, especially in New
England. Most of the divested plants have been acquired by subsidiaries or
affiliates of utilities located outside New England. In effect, a game of
musical assets has occurred, with utilities in one area selling their generating
assets and using the proceeds, plus borrowings, to purchase the same types of
generating assets in different areas of the United States.
These pressures to acquire suddenly divested assets and to enlarge
organizations caused the prices of large generating stations or strategically
located generating stations to rise sharply. The Trust elected not to purchase
additional generating capacity in New England or elsewhere because the
anticipated rates of return at the inflated prices were too low. The Trust
currently believes that many owners of large generating stations in New England
are currently operating at marginal or negative margins and there is intense
pressure on prices for base load contracts as purchasers of power stations
attempt to keep their stations running. The competitive pressures have been
intensified by the importation of power at peak periods from HydroQuebec and the
New York Power Pool and by the construction of several large gas turbine power
plants in New England, which have increased base load capacity. The ISO's
decision to allow these imports to reduce perceived demand for electricity and
thus to depress quoted peak period prices for energy below the cost of the
imported electricity has exacerbated these pressures.
Finally, the ISO's actions to cap prices of reserve products and energy
during system peak demand periods have caused RPMCo to take the Maine Biomass
Projects offline and have caused at least one other generator company to remove
a power plant designed for peak usage periods from New England entirely.
Paradoxically, although there is more generation capacity in New England now for
non-emergency periods and prices for that capacity are depressed, there is less
capacity available for meeting emergency peaks because of the effects of the
capped prices. The Trust believes that continued interference with the power
market could start a vicious circle of failure and additional price regulation,
as emergency capacity shortages cause the ISO to add more controls and more
mandatory runtimes to meet reliability needs.
This may already be occurring. In response to the high prices offered
by the Trust and other generators for reserve products in the summer of 1999,
and in response to what the ISO believed were flaws in the markets, the ISO
requested and obtained approval from FERC in February 2000 to abolish the market
for operable capability, to cap the price for other reserves at the energy price
and to propose a restructuring of the electric products markets.
In the long term, there seem to be three primary strategies for
non-utility generating plants to succeed in the United States: first, Projects
that have existing, firm, long-term Power Contracts may do well for the life of
those Contracts so long as regulatory or legislative actions do not abrogate the
Contracts. Second, Projects that are low-cost producers of electricity, either
from efficiencies or good management or as the result of successful cogeneration
technologies, will have advantages in the market. Third, the viability of small
Projects or Projects generating electricity from "renewable sources" will depend
on favorable legislative and regulatory action unless electricity prices climb
sharply.
(5) Competition
There are a large number of participants in the independent power industry.
Several large corporations specialize in developing, building and operating
independent power plants. Equipment manufacturers, including many of the largest
corporations in the world, provide equipment and planning services and provide
capital through finance affiliates. Many regulated utilities are preparing for a
competitive market, and a significant number of them already have organized
subsidiaries or affiliates to participate in unregulated activities such as
planning, development, construction and operating services or in owning exempt
wholesale generators or up to 50% of independent power plants. In addition,
there are many smaller firms whose businesses are conducted primarily on a
regional or local basis. Many of these companies focus on limited segments of
the cogeneration and independent power industry and do not provide a wide range
of products and services. There is significant competition among non-utility
producers, subsidiaries of utilities and utilities themselves in developing and
operating energy-producing projects and in marketing the power produced by such
projects.
The Trust is unable to accurately estimate the number of competitors but
believes that there are many competitors at all levels and in all sectors of the
industry. Many of those competitors, especially affiliates of utilities and
equipment manufacturers, are far better capitalized than the Trust.
Please also review the discussion of changes in the industry above at (4) -
Trends in the Electric Utility and Independent Power Industries.
(6) Regulatory Matters.
Projects are subject to energy and environmental laws and regulations at
the federal, state and local levels in connection with development, ownership,
operation, geographical location, zoning and land use of a Project and emissions
and other substances produced by a Project. These energy and environmental laws
and regulations generally require that a wide variety of permits and other
approvals be obtained before the commencement of construction or operation of an
energy-producing facility and that the facility then operate in compliance with
such permits and approvals. Since the Trust has agreed to comply with most of
the requirements for "business development companies" under the 1940 Act, it
also is contractually bound to comply with the requirements summarized below and
others described at Exhibit 99 to this Annual Report on Form 10-K.
(i) Energy Regulation.
(A) PURPA. The enactment in 1978 of PURPA and the adoption of regulations
thereunder by FERC provided incentives for the development of cogeneration
facilities and small power production facilities meeting certain criteria.
Qualifying Facilities under PURPA are generally exempt from the provisions of
the Public Utility Holding Company Act of 1935, as amended (the "Holding Company
Act"), the Federal Power Act, as amended (the "FPA"), and, except under certain
limited circumstances, state laws regarding rate or financial regulation. In
order to be a Qualifying Facility, a cogeneration facility must (a) produce not
only electricity but also a certain quantity of heat energy (such as steam)
which is used for a purpose other than power generation, (b) meet certain energy
efficiency standards when natural gas or oil is used as a fuel source and (c)
not be controlled or more than 50% owned by an electric utility or electric
utility holding company. Other types of Independent Power Projects, known as
"small power production facilities," can be Qualifying Facilities if they meet
regulations respecting maximum size (in certain cases), primary energy source
and utility ownership. Recent federal legislation has eliminated the maximum
size requirement for solar, wind, waste and geothermal small power production
facilities (but not for hydroelectric or biomass) for a fixed period of time.
In addition, PURPA requires electric utilities to purchase electricity
generated by Qualifying Facilities at a price equal to the purchasing utility's
full "avoided cost" and to sell back up power to Qualifying Facilities on a non
discriminatory basis. Avoided costs are defined by PURPA as the "incremental
costs to the electric utility of electric energy or capacity or both which, but
for the purchase from the Qualifying Facility or Qualifying Facilities, such
utility would generate itself or purchase from another source." While public
utilities are not required by PURPA to enter into long-term Power Contracts to
meet their obligations to purchase from Qualifying Facilities, PURPA helped to
create a regulatory environment in which it has become more common for such
contracts to be negotiated until recent years.
The exemptions from extensive federal and state regulation afforded by
PURPA to Qualifying Facilities are important to the Trust and its competitors.
The Trust believes that the Providence and Maine Hydro Projects, which sells
electricity to public utilities, are Qualifying Facilities. Maintaining the
Qualified Facility status of an electric generating Project is of utmost
importance to the Trust. Such status may be lost if a Project does not meet the
operational or ownership requirements of PURPA. For small power production
facilities such as the Providence, Maine Hydro and Maine Biomass Projects, the
requirements are limited to maximum size, fuel use and ownership requirements
that are currently unlikely to be violated. Cogeneration Projects that are
Qualifying Facilities have more stringent requirements, such as minimum
operating efficiency standards and minimum use of thermal energy by customers of
a cogeneration Project.
The Trust endeavors to comply with applicable PURPA requirements and does
not believe that the Providence, Maine Hydro or Maine Biomass Projects are
subject to any requirement that could jeopardize their statuses as Qualified
Facilities. If the Trust were to invest in cogeneration Projects or certain
other types of Qualifying Facilities, the PURPA standards could raise material
compliance questions. In any event, there can be no assurance that a Project
will maintain its Qualified Facility status. If a Project loses its Qualifying
Facility status, the utility can reclaim payments it made for the Project's
non-qualifying output to the extent those payments are in excess of current
avoided costs (which are generally substantially below the Power Contract rates)
or the Project's Power Contract can be terminated by the electric utility.
States may require utilities to institute monitoring systems under which
electric utilities continuously meter a cogeneration Project's performance.
(B) The 1992 Energy Act. The Comprehensive Energy Policy Act of 1992 (the "1992
Energy Act") empowered FERC to require electric utilities to make available
their transmission facilities to and wheel power for Independent Power Projects
under certain conditions and created an exemption for electric utilities,
electric utility holding companies and other independent power producers from
certain restrictions imposed by the Holding Company Act. Although the Trust
believes that the exemptive provisions of the 1992 Energy Act will not
materially and adversely affect its business plan, the act may result in
increased competition in the sale of electricity.
The 1992 Energy Act created the "exempt wholesale generator" category for
entities certified by FERC as being exclusively engaged in owning and operating
electric generation facilities producing electricity for resale. Exempt
wholesale generators remain subject to FERC regulation in all areas, including
rates, as well as state utility regulation, but electric utilities that
otherwise would be precluded by the Holding Company Act from owning interests in
exempt wholesale generators may do so. Exempt wholesale generators, however, may
not sell electricity to affiliated electric utilities without express state
approval that addresses issues of fairness to consumers and utilities and of
reliability.
(C) The Federal Power Act. The FPA grants FERC exclusive rate-making
jurisdiction over wholesale sales of electricity in interstate commerce. The FPA
provides FERC with ongoing as well as initial jurisdiction, enabling FERC to
revoke or modify previously approved rates. Such rates may be based on a
cost-of-service approach or determined through competitive bidding or
negotiation. While Qualifying Facilities under PURPA are exempt from the
rate-making and certain other provisions of the FPA, non-Qualifying Facilities
are subject to the FPA and to FERC rate-making jurisdiction.
Companies whose facilities are subject to regulation by FERC under the FPA
because they do not meet the requirements of PURPA may be limited in
negotiations with power purchasers. However, since such projects would not be
bound by PURPA's heat energy use requirement for cogeneration facilities, they
may have greater latitude in site selection and facility size. If any of the
Trust's electric power Projects failed to be a Qualifying Facility, it would
have to comply with the FPA.
The FPA also provides that any hydroelectric facility that is located on a
navigable stream or that affects public lands or water from a government dam may
not be constructed or be operated without a license from FERC. Certain
facilities that were operating before 1935 are exempt, if the waterway is
non-navigable, or "grandfathered" and do not require licenses so long as the
facilities are not modernized or otherwise materially altered. Licenses are
granted for 30 to 50 year terms. All but two of the Maine Hydro Projects (with a
rated capacity of 2.1 Megawatts) are subject to licensing. Of these 12 Projects,
six (with a rated capacity of 6.4 Megawatts) have current licenses that expire
from time to time between the years 2019 and 2037 and two (1.5 Megawatts) are
currently in the licensing process, which can take from three to five years. The
Trust believes that it will obtain licenses for each of these.
The proposed conditions for one pending license, at the Pittsfield Project
on the Kennebec River (1.1 Megawatt), have been received. The Project will have
to provide upstream fish passages no earlier than 2002 or, if later, the time
when all dams further upstream have provided passage. The Project will also have
to provide interim fish passage both upstream and downstream to the extent
warranted by fishery studies; downstream mitigation measures may require the
Project to restrict flow through its turbines during certain spring peak flow
periods that could materially impair electricity output. Until studies are
complete, it is not possible to estimate the effects of these conditions.
Further, as noted above at Item 1(c)(3) - Business - Narrative Description of
Business - Project Operation, the licenses may include other onerous conditions.
The Trust is a member of the Kennebec Hydro Developers Group, which is
negotiating with Maine agencies and environmental groups for watershed-wide
studies and remediation programs.
Finally, six of the Maine Hydro Projects (with a rated capacity of 3.7
Megawatts) are exempt, grandfathered or are not otherwise subject to FERC
licensing.
(D) Fuel Use Act. Projects that may be developed or acquired may also be subject
to the Fuel Use Act, which limits the ability of power producers to burn natural
gas in new generation facilities unless such facilities are also coal-capable
within the meaning of the Fuel Use Act.
(E) State Regulation. State public utility regulatory commissions have broad
jurisdiction over Independent Power Projects which are not Qualifying Facilities
under PURPA, and which are considered public utilities in many states. In states
where the wholesale or retail electricity market remains regulated, Projects
that are not Qualifying Facilities may be subject to state requirements to
obtain certificates of public convenience and necessity to construct a facility
and could have their organizational, accounting, financial and other corporate
matters regulated on an ongoing basis. Although FERC generally has exclusive
jurisdiction over the rates charged by a non-Qualifying Facility to its
wholesale customers, state public utility regulatory commissions have the
practical ability to influence the establishment of such rates by asserting
jurisdiction over the purchasing utility's ability to pass through the resulting
cost of purchased power to its retail customers. In addition, states may assert
jurisdiction over the siting and construction of non-Qualifying Facilities and,
among other things, issuance of securities, related party transactions and sale
and transfer of assets. The actual scope of jurisdiction over non-Qualifying
Facilities by state public utility regulatory commissions varies from state to
state.
(ii) Environmental Regulation.
The construction and operation of Independent Power Projects and the
exploitation of natural resource properties are subject to extensive federal,
state and local laws and regulations adopted for the protection of human health
and the environment and to regulate land use. The laws and regulations
applicable to the Trust and Projects in which it invests primarily involve the
discharge of emissions into the water and air and the disposal of waste, but can
also include wetlands preservation and noise regulation. These laws and
regulations in many cases require a lengthy and complex process of renewing
licenses, permits and approvals from federal, state and local agencies.
Obtaining necessary approvals regarding the discharge of emissions into the air
is critical to the development of a Project and can be time-consuming and
difficult. Each Project requires technology and facilities which comply with
federal, state and local requirements, which sometimes result in extensive
negotiations with regulatory agencies. Meeting the requirements of each
jurisdiction with authority over a Project may require extensive modifications
to existing Projects.
In May 1999 the Providence Project settled the administrative proceedings
against the Providence Project for violations of training, recordkeeping and
signage requirements brought by the Environmental Protection Agency ("EPA"). The
alleged violations and the proceedings are described at Item 3 - Legal
Proceedings, below.
In February 2000, in response to complaints of odors from the Rhode Island
landfill, the EPA ordered the Providence Project, the gas collection company and
the state agency owing the landfill to jointly respond in an investigation of
the landfill gas control system at the landfill, of which the Providence Project
is a part. The Project's systems are performing within environmental
requirements and the Trust does not believe that it will be responsible for any
material liability. It is possible, however, that the EPA will require the other
parties at the landfill to change their operations, which might have a material
effect on the Trust. At this time, there is no indication of what action, if
any, the EPA might take.
The Clean Air Act Amendments of 1990 contain provisions which regulate the
amount of sulfur dioxide and oxides of nitrogen which may be emitted by a
Project. These emissions may be a cause of "acid rain." Qualifying Facilities
are currently exempt from the acid rain control program of the Clean Air Act
Amendments. However, non-Qualifying Facility Projects will require "allowances"
to emit sulfur dioxide after the year 2000. Under the Amendments, these
allowances may be purchased from utility companies then emitting sulfur dioxide
or from the EPA. Further, an Independent Power Project subject to the
requirements has a priority over utilities in obtaining allowances directly from
the EPA if (a) it is a new facility or unit used to generate electricity; (b)
80% or more of its output is sold at wholesale; (c) it does not generate
electricity sold to affiliates (as determined under the Holding Company Act) of
the owner or operator (unless the affiliate cannot provide allowances in certain
cases) and (d) it is non-recourse project-financed. The market price of an
allowance cannot be predicted with certainty at this time. In recent years,
supply of allowances has tended to exceed demand, primarily because of improved
control technologies and the increased use of natural gas.
Title V of the Clean Air Act Amendments added a new permitting requirement
for existing sources that requires all significant sources of air pollution to
submit new applications to state agencies. Title V implementation by the states
generally does not impose significant additional restrictions on the Trust's
Projects, other than requirements to continually monitor certain emissions and
document compliance. The Trust has filed Title V applications with the
appropriate states for the Providence and Maine Biomass Projects, and has been
advised by EPS that an application has been approved for the Santee River
Project, which are all the Projects that are required to file. The permitting
process is voluminous and protracted and the costs of fees for Title V
applications, of testing and of engineering firms to prepare the necessary
documentation have increased. The Trust believes that all of its facilities will
be in compliance with Title V requirements with only minor modifications such as
the installation of an additional catalytic converter on some engines.
In July 1997 the Environmental Protection Agency adopted more stringent
standards for levels of ozone and small particulate matter (particles less than
25 microns in diameter) in geographic areas. These new standards may cause some
areas in which Projects are located to be classified as non-attainment areas. If
so, states will be required to impose additional requirements for industries to
reduce emissions. It is uncertain whether or how any reductions would be applied
to small facilities such as the Trust's Projects. If reductions were required,
the Trust might have to make significant capital investments to install new
control technology or might have to reduce operations. In addition, many eastern
states, including Maine, have organized in the Ozone Transport Assessment Group
to require further restrictions on emissions of nitrogen oxides. The
Environmental Protection Agency is considering the Group's recommendations as
well as other proposals to reduce emissions of nitrogen oxides and other
ozone-forming chemicals. If adopted, new regulations could require the Trust to
install additional equipment to reduce those emissions or to change operations.
Nitrogen oxide reductions can be difficult to achieve with add-on equipment and
often require decreases in operating efficiency, both of which could cause
material cost to the Trust. It is not possible at this time to estimate whether
or not any potential regulatory changes would materially affect the Trust.
The Clean Air Act Amendments empower states to impose annual operating
permit fees of at least $25 per ton of regulated pollutants emitted up to
$100,000 per pollutant. To date, no state in which the Trust operates has done
so. If a state were to do so, such fees might have a material effect on the
Trust's costs of generation, in light of the relatively small size of the
Trust's facilities as opposed to large utility generation plants that might
benefit from the cap on fees.
The Trust's Projects must comply with many federal and state laws and
regulations governing wastewater and stormwater discharges from the Projects.
These are generally enforced by states under "NPDES" permits for point sources
of discharges and by stormwater permits. Under the Clean Water Act, NPDES
permits must be renewed every five years and permit limits can be reduced at
that time or under re-opener clauses at any time. The Projects have not had
material difficulty in complying with their permits or obtaining renewals. The
Projects use closed-loop engine cooling systems which do not require large
discharges of coolant except for periodic flushing to local sewer systems under
permit and do not make other material discharges.
The Providence Project operates filtration and condensation equipment
for the purpose of removing contaminants from the landfill gas supply. The
condensate is further treated and then discharged to a local treatment plant
under an NPDES permit. The contaminants removed from the condensate are
incinerated at an approved facility. The Trust believes that these discharges
and contaminants are being disposed of in compliance with NPDES and other
requirements.
The Trust's Projects are subject to the reporting requirements of the
Emergency Planning and Community Right-to-Know Act that require the Projects to
prepare toxic inventory release forms. These forms list all toxic substances on
site that are used in excess of threshold levels so as to allow governmental
agencies and the public to learn about the presence of those substances and to
assess potential hazards and hazard responses. The Trust does not anticipate
that this requirement will result in any material adverse effect on it.
Based on current trends, the Managing Shareholder expects that
environmental and land use regulation will become more stringent. The Trust and
the Managing Shareholder have developed limited expertise and experience in
obtaining necessary licenses, permits and approvals, which in the case of the
Maine Hydro Project are the responsibility of Consolidated Hydro, Inc. The Trust
will rely upon qualified environmental consultants and environmental counsel
retained by it or by Project Sponsors to assist in evaluating the status of
Projects regarding such matters.
(iii) The 1940 Act
Since its Shares are registered under the 1934 Act, the Trust is required
to file with the Commission certain periodic reports (such as Forms 10-K (annual
report), 10-Q (quarterly report) and 8-K (current reports of significant events)
and to be subject to the proxy rules and other regulatory requirements of that
act that are applicable to the Trust. The Trust has no intention to and will not
permit the creation of any form of a trading market in the Shares in connection
with this registration.
On January 24, 1995, the Trust notified the Securities and Exchange
Commission (the "Commission") of its election to be a "business development
company" and registered its Shares under the 1934 Act. On March 24, 1995, the
election and registration became effective. As a "business development company,"
the Trust was subject to prohibitions and restrictions on transactions between
business development companies and their affiliates as defined in that act, and
required that a majority of the board of the company be persons other than
"interested persons" as defined in the act.
In particular, Commission approval was required for certain transactions
involving certain closely affiliated persons of business development companies,
including many transactions with the Managing Shareholder and the other
investment programs sponsored by the Managing Shareholder. The decision to
co-invest in the Providence Project with Power III required approval of the
Commission, which took more than eight months to obtain. The decision to
co-invest in the Maine Hydro Projects with Power V would also have required
approval of the Commission. There was no assurance that the necessary approval
for that co-investment or others could be obtained.
Accordingly, in September 1996 the Managing Shareholder made a proxy
solicitation requesting that the Investors in this Trust approve a proposal to
end the Trust's status as a business development company. The purpose of the
change was to allow the Trust to invest with other programs sponsored by the
Managing Shareholder, with only the approval of the Trust's Independent
Trustees. The Independent Trustees may not be "interested persons" (as defined
by law) of the Trust or the Managing Shareholder. The Managing Shareholder
advised the Investors of its belief that the change would end the delays and
uncertainties of seeking approval from the Securities and Exchange Commission
(the "Commission") for such transactions and therefore would increase
opportunities for the Trust to diversify its investments and to increase the
size and quality of the potential investment pool.
A majority in interest of the Investors approved an amendment to the
Trust's Declaration of Trust by written consent. The amendment and the
termination of business development company status became effective on October
3, 1996. In summary, the amendment authorized the Trust to withdraw the business
development company election. It also defined a "Ridgewood Program Transaction"
as a transaction with a Ridgewood Program, an entity controlled by a Ridgewood
Program or Programs, or an entity in which a Ridgewood Program has invested,
that would otherwise be prohibited by the 1940 Act. The amendment stated that
Ridgewood Program Transactions will not be subject to any provision of the 1940
Act or rules thereunder that would restrict the Trust, or entities the Trust
controls or has invested in, form entering into Ridgewood Program Transactions.
Instead, a Ridgewood Program Transaction must be approved either by the Managing
Shareholder and a majority of the Independent Trustees, or by a majority of the
Independent Trustees and a Majority of the Investors. No express standards for
approval are specified, although the Managing Shareholder and the Independent
Trustees are subject to the fiduciary requirements of Delaware law in making
their decisions.
The amendment also required the Trust to continue to comply with all other
requirements of the 1940 Act as if the Trust continued to be a business
development company, except that the Trust would not be required to file any
reports required of business development companies with the Commission or any
other regulatory agency. With regard to the requirements that the Trust will
continue to adhere to, the Trust will not be able to request exemptive relief
from or to take actions requiring approval by the Commission, and the Commission
will not have the ability to regulate the Trust under the 1940 Act, because the
Trust will no longer be subject to the Commission's authority over business
development companies.
The requirements of the 1940 Act that the Trust has promised to comply
with, and those that it will not be required to follow, are listed in Exhibit 99
to this Annual Report on Form 10-K. Some of those requirements that are
particularly relevant to the Trust's acquisitions of Projects are described
below.
The Trust may not acquire any asset other than a "Qualifying Asset" unless,
at the time the acquisition is made, Qualifying Assets comprise at least 70% of
the Trust's total assets by value. The principal categories of Qualifying Assets
that are relevant to the Trust's activities are:
(A) Securities issued by "eligible portfolio companies" that are purchased by
the Trust from the issuer in a transaction not involving any public offering
(i.e., private placements of securities). An "eligible portfolio company" (1)
must be organized under the laws of the United States or a state and have its
principal place of business in the United States; (2) may not be an investment
company other than a small business investment company licensed by the Small
Business Administration and wholly-owned by the Trust and (3) may not have
issued any class of securities that may be used to obtain margin credit from a
broker or dealer in securities. The last requirement essentially excludes all
issuers that have securities listed on an exchange or quoted on the National
Association of Securities Dealers, Inc.'s national market system, along with
other companies designated by the Federal Reserve Board. Except for temporary
investments of the Trust's available funds, substantially all of the Trust's
investments are expected to be Qualifying Assets under this provision.
(B) Securities received in exchange for or distributed on or with respect to
securities described in paragraph (A) above, or on the exercise of options,
warrants or rights relating to those securities.
(C) Cash, cash items, U.S. Government securities or high quality debt securities
maturing not more than one year after the date of investment.
A business development company must make available "significant managerial
assistance" to the issuers of Qualifying Assets described in paragraphs (A) and
(B) above, which may include without limitation arrangements by which the
business development company (through its directors, officers or employees)
offers to provide (and, if accepted, provides) significant guidance and counsel
concerning the issuer's management, operation or business objectives and
policies.
A business development company also must be organized under the laws of the
United States or a state, have its principal place of business in the United
States and have as its purpose the making of investments in Qualifying Assets
described in paragraph (A) above.
(d) Financial Information about Foreign and Domestic Operations and Export
Sales.
The Trust has committed funds to Projects located in Rhode Island, Maine,
South Carolina and California. The Trust has not acquired any Project located
outside the United States.
(e) Employees.
The Trust has no employees. The persons described below at Item 10 -
Directors and Executive Officers of the Registrant serve as executive officers
of the Trust and have the duties and powers usually applicable to similar
officers of a Delaware corporation in carrying out the Trust business.
Item 2. Properties.
Pursuant to the Management Agreement between the Trust and the Managing
Shareholder (described at Item 10(c)), the Managing Shareholder provides the
Trust with office space at the Managing Shareholder's principal office at The
Ridgewood Commons, 947 Linwood Avenue, Ridgewood, New Jersey 07450.
The following table shows the material properties (relating to Projects)
owned or leased by the Trust's subsidiaries or partnerships or limited liability
companies in which the Trust has an interest.
Approximate
Square
Ownership Ground Approximate Footage of Description
Interests Lease Acreage Project of
Projects Location in Land Expiration of Land (Actual Project
or Projected)
Provi- Providence,
dence Rhode Leased 2020 4 10,000 Landfill
Island gas-fired
generation
facility
Maine Hydro 14 sites
in Maine Owned n/a 24 n/a Hydro-
by joint electric
venture* facilities
Pump Ser- Ventura License n/a n/a nominal Natural-
vices County, gas-fueled
California engines for
irrigation
pumps located
on various
farms
Maine West Enfield Owned n/a less 18,000 Wood waste-
Bio- and Jonesboro, by joint than fired genera-
mass Maine venture** 25 tion facility
Santee Berkeley Owned by n/a 30 Used tire
River County, joint processing
South venture*** facility
Carolina
*Joint venture equally owned by Trust and Power V.
** Joint venture owned by Indeck, the Trust and Power V.
*** Joint venture owned by EPS, the Trust and Power V.
Item 3. Legal Proceedings.
In September 1998, the Region I office of the U.S. Environmental Protection
Agency (the "EPA") filed an administrative proceeding against Ridgewood
Providence Power Partners, L.P. ("RPPP"), a subsidiary of the Trust, seeking to
recover civil penalties of up to $190,000 for alleged violations of operational
recordkeeping and training requirements at the Providence Project. The penalty
was reduced to $86,000 and was paid by the Providence Project in June 1999.
In October 1998, Indeck Maine brought two administrative complaints before
FERC, naming ISO-New England and the New England Power Pool as defendants,
alleging that the defendants had violated their own rules and applicable FERC
orders in denying pooled transmission facility status for the transmission links
between Indeck Maine's two Projects and the ISO's other transmission facilities.
In February 1999, FERC rejected the complaints. Indeck Maine is considering
whether to bring a new action together with other NEPOOL members based on new
facts.
In March 2000, Indeck Maine intervened in a complaint before FERC, Dighton
Power Assoc., L.P. et. al. v. ISO-New England, Inc., Docket No. EL00-40-000, in
which several generators alleged that the ISO had improperly capped operable
capability prices during emergency conditions in NEPOOL. See Item 1(c)(3)(ii) -
Plant Operation - Maine Biomass Projects, above. The complaint requests FERC to
rule that the operable capability prices should be based on the highest bids on
those dates. If this were successful, the Maine Biomass Projects might be
entitled to substantial additional payments from the ISO. The matter is in the
preliminary stages of pleading and motion practice. Indeck Maine intends to
participate vigorously in the proceedings.
Item 4. Submission of Matters to a Vote of Security Holders.
The Trust has not submitted any matters to a vote of its security holders
during the fourth quarter of 1999.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
(a) Market Information.
The Trust sold 476.8 Investor Shares of beneficial interest in the Trust in
its private placement offering, which concluded on September 30, 1996. There is
currently no established public trading market for the Investor Shares and the
Trust does not intend to allow a public trading market to develop. As of the
date of this Form 10-K, all such Investor Shares have been issued and are
outstanding. There are no outstanding options or warrants to purchase, or
securities convertible into, Investor Shares.
Investor Shares are restricted as to transferability under the Declaration,
as well as under federal and state laws regulating securities. The Investor
Shares have not been and are not expected to be registered under the Securities
Act of 1933, as amended (the "1933 Act"), or under any other similar law of any
state (except for certain registrations that do not permit free resale) in
reliance upon what the Trust believes to be exemptions from the registration
requirements contained therein. Because the Investor Shares have not been
registered, they are "restricted securities" as defined in Rule 144 under the
1933 Act.
The Managing Shareholder is considering the possibility of a combination of
the Trust and five other investment programs sponsored by the Managing
Shareholder (Ridgewood Electric Power Trusts I, II, III and V and the Ridgewood
Power Growth Fund) into a publicly traded entity. This would require the
approval of the Investors in the Trust and the other programs after proxy
solicitations complying with requirements of the Securities and Exchange
Commission, compliance with the "rollup" rules of the Securities and Exchange
Commission and other regulations, and a change in the federal income tax status
of the combined entity from a partnership (which is not subject to tax) to a
corporation. The process of considering and effecting a combination, if the
decision is made to do so, will be very lengthy. There is no assurance that the
Managing Shareholder will recommend a combination, that the Investors of the
Trust or other programs will approve it, that economic conditions or the
business results of the participants will be favorable for a combination, that
the combination will be effected or that the economic results of a combination,
if effected, will be favorable to the Investors of the Trust or other programs.
(b) Holders
As of the date of this Form 10-K, there are 956 record holders of Investor
Shares.
(c) Dividends
The Trust made distributions as follows in 1998 and 1999:
Year ended December 31,
1998 1999
Total distributions to Investors $3,383,174 $ 1,859,871
Distributions per Investor Share 7,096 3,900
Distributions to Managing Shareholder $ 34,173 $ 18,787
Distributions are made on a quarterly basis in March, June, September and
December. During 1999 the rate of distributions was decreased from 7% per year
to 4% per year because of adverse financial results described below at Item 7,
Management's Discussion and Analysis. The Trust's ability to make future
distributions to Investors and their timing will depend on the net cash flow of
the Trust and retention of reasonable reserves as determined by the Trust to
cover its anticipated expenses.
The Trust has made distributions at the rates of 7.1% in 1998 and 3.9% in
1999 and does not anticipate that distributions during 2000 will be at a
substantially higher rate. This is because distributions from the Maine Hydro
Projects during 1998 reflected higher than average water flows, which may not
recur, because the Maine Biomass Projects may continue to incur losses until at
least 2001 and because the Santee River Project is not anticipated to begin
operation before summer 2000 and may not show operating profits for some
additional time after that. Further, if adverse events were to occur, the Trust
may be required to reduce distributions from existing levels.
Occasionally, distributions may include funds derived from the release of
cash from operating or debt service reserves. For purposes of generally accepted
accounting principles, amounts of distributions in excess of accounting income
may be considered to be capital in nature. Investors should be aware that the
Trust is organized to return net cash flow rather than accounting income to
Investors.
Item 6. Selected Financial Data.
The following data is qualified in its entirety by the financial statements
presented elsewhere in this Annual Report on Form 10-K.
<TABLE>
<CAPTION>
Supplemental Information As of and for the
Schedule Period from Commencement
Selected Financial of Share Offering
Data As of and for the Years Ended (February 6, 1995)
December 31, through
1999 1998 1997 1996 December 31, 1995
(Restated)
Total Fund Information:
<S> <C> <C> <C> <C> <C>
Net sales $ 7,179,229 $6,905,883 $6,810,911 $4,087,722 $0
Net income (loss) (743,977) (602,901) 402,777 72,769 (56,133)
Net assets (shareholders'
equity) 28,381,288 31,003,923 35,023,361 38,746,599 13,502,131
Investments in Project
development entities,
power generation
equipment and deve-
lopmental costs 26,942,903 29,259,917 26,048,431 20,467,908 0
Investment in electric
power sales contract
(net of amortization) 6,280,090 6,835,959 7,391,828 7,947,697 0
Total assets 39,455,324 43,060,184 47,964,823 52,453,335 3,890,163
Long-term obligations 3,479,460 4,196,455 4,848,067 5,440,260 0
Per Share of Trust
Interest:
Revenues 15,828 15,258 15,059 $9,121 $0
Net income (loss) (1,560) (1,262) (845) 153 (963)
Net asset value 59,768 65,025 73,455 81,264 83,295
Distributions to Investors 3,900 7,096 6,894 3,517 0
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Introduction
The following discussion and analysis should be read in conjunction
with the Trust's financial statements and the notes thereto presented below.
Dollar amounts in this discussion are generally rounded to the nearest $1,000.
The consolidated financial statements include the accounts of the Trust
and the limited partnerships owning the Providence and California Pumping
Projects. The Trust uses the equity method of accounting for its investments in
the Maine Hydro Projects, the Maine Biomass Projects and the Santee River Rubber
Project, which are owned 50% or less by the Trust.
Outlook
The U.S. electricity markets are being restructured and there is a
trend away from regulated electricity systems towards deregulated, competitive
market structures. The States that the Trust's Projects operate in have passed
or are considering new legislation that would permit utility customers to choose
their electricity supplier in a competitive electricity market. The Providence
and Maine Hydro Projects are "Qualified Facilities" as defined under the Public
Utility Regulatory Policies Act of 1978 and currently sell their electric output
to utilities under long-term contracts. The Providence contract expires in 2020
and eleven of the Maine Hydro contracts expire in 2008 and the remaining three
expire in 2007, 2014 and 2017. During the term of the contracts, the utilities
may or may not attempt to buy out the contracts prior to expiration. At the end
of the contracts, the Projects will become merchant plants and may be able to
sell the electric output at then current market prices. There can be no
assurance that future market prices will sufficient to allow the Trust's
Projects to operate profitably.
The Providence Project generates electricity from methane gas produced
at the Central Landfill in Johnston, Rhode Island. Gas reserves are estimated to
be in excess of the amount needed to generate the 12 Megawatt maximum under the
Power Contract with New England Power Company. The price paid for the gas is a
percentage (15% to 18%) of net revenue from power sales. Accordingly, the
Providence Project is not affected by fuel cost price changes. The quality of
the gas may vary from time to time. Poor quality gas may cause operating
problems, down time and unplanned maintenance at the generating facility.
The Maine Hydro Projects have a limited ability to store water.
Accordingly, the amount of revenue from electricity generation from these
Projects is directly related to river water flows, which have fluctuated as much
as 30% from the average over the past ten years. It is not possible to
accurately predict revenues from the Maine Hydro Projects.
The Maine Biomass Projects sold electricity under short-term contracts
during the months of July, August, October, November and December 1997. The
Projects are currently shutdown and will not be operated (except for required
tests) unless sales arrangements are obtained which would provide sufficient
revenue to cover the Projects fixed and variable costs. Under current
legislation, the electricity market in the State of Maine will be deregulated on
March 1, 2000. Currently, the cost of biomass fuel and transportation costs are
too high to allow the Maine Biomass Projects to compete on price alone. If fuel
can be purchased at reasonable prices in the year 2001 and beyond, the Maine
Biomass Projects might be among the low cost producers of environmentally
friendly electricity in Maine and might be able to operate profitably in a
competitive market environment or in a set-aside market for renewable power. In
the meantime, the Trust intends to keep the Projects in an idle mode until
market conditions become more favorable, and will seek short-term contracts to
sell energy and installed capacity.
All power generation projects currently owned by the Trust produce
electricity from renewable energy sources, such as landfill gas, hydropower and
biomass ("green power"). In the State of Maine, as a condition of licensing,
competitive generation providers and power marketers will have to demonstrate
that at least 30% of their generation portfolio is green power sources. Other
States in the New England Power Pool have or are expected to have similar green
power licensing requirements, although the percentage of green power generation
may differ from State to State. These green power licensing requirements should
have a beneficial effect on the future profitability of the Maine Biomass
Projects. Although the Providence and Maine Hydro Projects also produce green
power, their output is committed under long-term Power Contracts at fixed
prices.
The Santee River Rubber Project, which is currently in the construction
phase, will process waste tires and is expected to generate high quality crumb
rubber. Assuming that the plant functions as specified and that the price
received for the crumb rubber from customers is as forecast, the Project should
begin operations in the third quarter of 2000.
The California Pumping Project owns irrigation well pumps in Ventura
County, California, which supply water to farmers. The demand for water pumped
by the project varies inversely with rainfall in the area.
Additional trends affecting the independent power industry generally
are described at Item 1 - Business.
Results of Operations
The year ended December 31, 1999 compared to the year ended December 31, 1998.
In 1999, the Trust had a net loss of $744,000 as compared to a net loss of
$602,000 in 1998. The 1999 and 1998 net losses include the following results
from projects:
Project 1999 1998
----------- -----------
Providence Project ............. (1) $ 310,000 $ 535,000
Maine Hydro Projects ........... (2) 849,000 658,000
Maine Biomass Projects ......... (2) (1,007,000) (694,000)
Santee River Rubber ............ (2) 49,000 182,000
California Pumping Project ..... (1) (155,000) (131,000)
(1) Earnings, net of minority interest.
(2) Equity interest in income (loss) of the project.
Although revenues generated by the Providence Project in 1999 were similar
to those of 1998, the decrease in income from the project reflects increased
costs of engine maintenance resulting from the unanticipated outages of two
engines.
The increase in income from the Maine Hydro Projects reflects higher
revenues in 1999 compared to 1998. The improved revenues reflected
higher-than-average rainfall and snowfall, which increased water flow through
the hydroelectric dams.
The increase in the loss from the shutdown Maine Biomass Projects from 1998
to 1999 reflects the cost of periodically operating the plant more frequently in
1999 compared to 1998. As discussed at Item 1(c)(3)(ii) above, the projects are
in dispute with the ISO over the payment of certain revenues related to the
plants' operation in 1999. The disputed payments were not recorded as income by
the projects pending resolution of the disputes.
The Trust income from the Santee River Rubber project in 1999 was lower
than in 1998 reflecting the Trust's share of the cost of marketing and
administration as the plant is constructed.
The loss from the California Pumping Project in 1999 was greater than
the prior year's due to increased fuel prices, which more than offset the
improvement in revenues caused by the absence of the extraordinary rainfall that
occurred in the first half of 1998 and the absence of the 1998 cost of
terminating the operating agreement with the third party manager.
The Trust-level expenses in 1999 and 1998 include management fees of
$467,000 and $1,051,000, respectively. The decrease is a result of the Managing
Shareholder's decision to waive 50% of the fee in 1999. To date, the Managing
Shareholder has continued to waive 50% of the fee but it may end that waiver in
its sole discretion at any time. Due diligence expenses related to unsuccessful
potential investments of $205,000 in 1998 did not recur due to the Trust's
completion of the investment of its available funds in 1998. Other Trust-level
expenses in 1999 and 1998 were comparable.
The year ended December 31, 1998 compared to the year ended December 31, 1997.
In 1998, the Trust had a net loss of $602,000 as compared to a net loss of
$403,000 in 1997. The 1998 and 1997 net losses include the following results
from projects:
Project 1998 1997
- -------------------------------------- --------- ---------
Providence Project ................ (1) $ 535,000 $ 964,000
Maine Hydro Projects .............. (2) 658,000 522,000
Maine Biomass Projects ............ (2) (694,000) (680,000)
Santee River Rubber ............... (2) 182,000 --
California Pumping Project ........ (1) (131,000) 18,000
(1) Earnings, net of minority interest.
(2) Equity interest in income (loss) of the project.
Although revenues generated by the Providence Project in 1998 were
similar to those of 1997, the decrease in income from the project reflects an
increase in the costs of periodic engine maintenance.
The increase in income from the Maine Hydro Projects reflects higher revenues in
1998 compared to 1997. The improved revenues reflected higher-than-average
rainfall and snowfall, which increased water flow through the hydroelectric
dams.
The loss from the shutdown Maine Biomass Projects in 1998 was similar to the
loss incurred in 1997. However, the 1998 loss reflects twelve months of
operations compared to six months in 1997. The lower loss per month in 1998
reflects a reduction in expenses as well as the sale of installed capability.
Income from the Santee River Rubber project reflects the Trust's share of
interest income earned before the project entered the construction phase.
Demand for energy from the California Pumping Project suffered from the
extraordinary rainfall that occurred in the first half of 1998.
The Trust-level expenses in 1998 and 1997 include management fees of $1,051,000
and $1,155,000, respectively. The decrease is a result of the decrease in the
net assets of the Trust. Due diligence expenses related to unsuccessful
potential investments declined from $669,000 in 1998 to $205,000 in 1998 as a
result of the Trust's completing the investment of its available funds in 1998.
Other Trust level expenses in 1998 and 1997 were comparable.
Liquidity and Capital Resources
In 1999 and 1998 the Trust's operating activities generated $974,000 and
$478,0000 of cash, respectively. The higher level of cash from operations in
1999 primarily reflects decreases in working capital required at the Providence
Project.
In 1999, the Trust's investing activities generated $908,000 of cash compared to
a use of cash of $4,950,000 in 1998. The improvement was primarily a result of a
$4,348,000 reduction in investments in projects and a $979,000 reduction in
capital expenditures from the 1998 levels.
Cash used in financing activities decreased from $4,594,000 in 1998 to
$3,010,000 in 1999 primarily due to a reduction of the distribution rate to
shareholders from 6% per year in 1998 to 4% in 1999.
During 1997, the Trust and Fleet Bank, N.A. (the "Bank") entered into a
revolving line of credit agreement, whereby the Bank provides a three year
committed line of credit facility of $1,150,000. Outstanding borrowings bear
interest at the Bank's prime rate or, at the Trust's choice, at LIBOR plus 2.5%.
The credit agreement requires the Trust to maintain a ratio of total debt to
tangible net worth of no more than 1 to 1 and a minimum debt service coverage
ratio of 2 to 1. The credit facility was obtained in order to allow the Trust to
operate using a minimum amount of cash, maximize the amount invested in Projects
and maximize cash distributions to shareholders. There were no borrowings under
the line of credit in 1999 or 1998. In January 2000, the Trust borrowed $400,000
under the line of credit to meet its working capital requirements.
Obligations of the Trust are generally limited to payment of Project operating
expenses, repayment of borrowings under the line of credit, payment of a
management fee to the Managing Shareholder, payments for certain accounting and
legal services to third persons and distributions to shareholders of available
operating cash flow generated by the Trust's investments. The Trust's policy is
to distribute as much cash as it deems prudent to shareholders. Accordingly, the
Trust has not found it necessary to retain a material amount of working capital.
The amount of working capital retained is further reduced by the availability of
the line of credit facility.
The Trust anticipates that during 2000 its cash flow from operations, unexpended
offering proceeds and line of credit facility will be adequate to fund its
obligations.
Year 2000 Remediation
The Managing Shareholder and its affiliates began year 2000 review and
planning in early 1997. After initial remediation was completed, a more
intensive review discovered additional issues and the Managing Shareholder began
a formal remediation program in late 1997. All remediation and testing were
completed by October 31, 1999 and no material malfunctions have been discovered
through the date of this filing.
The accounting, network and financial packages for the Ridgewood companies
are basically off-the-shelf packages that were remediated, where necessary, by
obtaining patches or updated versions. The Managing Shareholder estimates that
the Trust's allocable portion of the cost of upgrades that were accelerated
because of the Year 2000 problem is less than $1,000.
The Managing Shareholder has two major systems affecting the Trust that
rely on custom-written software, the subscription/investor relations and
investor distribution systems, which maintain individual investor records and
effect disbursement of distributions to Investors. These were remediated in
1999, including the elements of those systems used to generate internal sales
reports and other internal reports. Although these were not designated
mission-critical, they were also successfully remediated by October 31, 1999.
Some subsystems are being remediated using the "sliding window" technique, in
which two digit years less than a threshold number are assumed to be in the
2000's and higher two digit numbers are assumed to be in the 1900's. Although
this will allow compliance for several years beyond the year 2000, eventually
those systems will have to be rewritten again or replaced. The Managing
Shareholder expects that the ordinary course of system upgrading will eventually
cure this problem.
The Trust's share of the incremental cost for Year 2000 remediation of this
custom written software and related items for 1998 and prior years was
approximately $12,250 and was approximately $11,500 for 1999.
Each of the Trust's electric generating facilities was reviewed in 1999 by
RPMCo personnel to determine if its electronic control systems contained
software affected by the Year 2000 problem or contain embedded components that
contain Year 2000 flaws. The Trust owns small electric generating facilities
that rely on mechanical and analog systems that were not vulnerable to Year 2000
problems. The facilities use personal computers running packaged software for
routine recordkeeping and data logging, which have been upgraded as described
above. To date the Trust has discovered no systems having a material impact on
output, environmental compliance, recordkeeping or any other material impact
that have Year 2000 concerns. The Maine Biomass Projects contained certain
embedded chips that were replaced before December 31, 1999 at a nominal cost.
The Trust's share of the estimated costs of the review and of any minor upgrades
or rehabilitation was less than $25,000.
The Managing Shareholder and its affiliates do not significantly rely on
computer input from suppliers and customers and thus are not directly affected
by other companies' Year 2000 compliance. No material adverse effects from
customers' or suppliers' Year 2000 problems have occurred.
Based on its internal evaluations and the risks and contexts identified by
the Commission in its rules and interpretations, the Trust believes that Year
2000 issues relating to its assets and remediation program will not have a
material effect on its facilities, financial position or operations, and that
the costs of addressing the Year 2000 issues will not have a material effect on
its future consolidated operating results, financial condition or cash flows.
However, this belief is based upon current information, and there can be no
assurance that unanticipated problems will not occur or be discovered that would
result in material adverse effects on the Trust.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Qualitative Information About Market Risk.
The Trust's investments in financial instruments are short-term investments
of working capital or excess cash. Those short-term investments are limited by
its Declaration of Trust to investments in United States government and agency
securities or to obligations of banks having at least $5 billion in assets.
Because the Trust invests only in short-term instruments for cash management,
its exposure to interest rate changes is low. The Trust has limited exposure to
trade accounts receivable and believes that their carrying amounts approximate
fair value.
The Trust's primary market risk exposure is limited interest rate risk
caused by fluctuations in short-term interest rates. The Trust does not
anticipate any changes in its primary market risk exposure or how it intends to
manage it. The Trust does not trade in market risk sensitive instruments.
Quantitative Information About Market Risk
This table provides information about the Trust's financial instruments
that are defined by the Securities and Exchange Commission as market risk
sensitive instruments. These include only short-term U.S. government and agency
securities and bank obligations. The table includes principal cash flows and
related weighted average interest rates by contractual maturity dates.
December 31, 1999
Expected Maturity Date
2000
(U.S. $)
Bank Deposits and Certificates
of Deposit $ 893,383
Average interest rate 5.6%
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Balance Sheets at December 31, 1999 and 1998 F-3
Statement of Operations for Years Ended
December 31, 1999, 1998 and 1997 F-4
Statement of Changes in Shareholders' Equity for
Years Ended December 31, 1999, 1998 and 1997 F-5
Statement of Cash Flows for
Years Ended December 31, 1999, 1998 and 1997 F-6
Notes to Financial Statements F-7 to F-17
Financial Statements for Maine Hydro Projects
Financial Statements for Maine Biomass Projects
All schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
The financial statements are presented in accordance with generally
accepted accounting principles for operating companies, using consolidation and
equity method accounting principles. This differs from the basis used by the
three prior independent power programs sponsored by the Managing Shareholder,
which present the Trust's investments in Projects on the estimated fair value
method rather than the consolidation and equity accounting method. Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
Neither the Trust nor the Managing Shareholder has had an independent
accountant resign or decline to continue providing services since their
respective inceptions and neither has dismissed an independent accountant during
that period. During that period of time no new independent accountant has been
engaged by the Trust or the Managing Shareholder, and the Managing Shareholder's
current accountants, PricewaterhouseCoopers LLP, have been engaged by the Trust.
PART III
Item 10. Directors and Executive Officers of the Registrant.
(a) General.
As Managing Shareholder of the Trust, Ridgewood Power LLC has direct and
exclusive discretion in management and control of the affairs of the Trust
(subject to the general supervision and review of the Independent Trustees and
the Managing Shareholder acting together as the Board of the Trust). The
Managing Shareholder will be entitled to resign as Managing Shareholder of the
Trust only (i) with cause (which cause does not include the fact or
determination that continued service would be unprofitable to the Managing
Shareholder) or (ii) without cause with the consent of a majority in interest of
the Investors. It may be removed from its capacity as Managing Shareholder as
provided in the Declaration.
Ridgewood Holding, which was incorporated in April 1992, is the Corporate
Trustee of the Trust.
(b) Managing Shareholder.
Ridgewood Power Corporation was incorporated in February 1991 as a Delaware
corporation for the primary purpose of acting as a managing shareholder of
business trusts and as a managing general partner of limited partnerships which
are organized to participate in the development, construction and ownership of
Independent Power Projects. It organized the Trust and acted as managing
shareholder until April 1999. On or about April 21, 1999 it was merged into the
current Managing Shareholder, Ridgewood Power LLC. Ridgewood Power LLC was
organized in early April 1999 and has no business other than acting as the
successor to Ridgewood Power Corporation.
Robert E. Swanson has been the President, sole director and
sole stockholder of Ridgewood Power Corporation since its inception in February
1991 and is now the controlling member, sole manager and President of the
Managing Shareholder. All of the equity in the Managing Shareholder is or will
be owned by Mr. Swanson or by family trusts. Mr. Swanson has the power on behalf
of those trusts to vote or dispose of the membership equity interests owned by
them.
The Managing Shareholder has also organized Ridgewood Electric Power Trust
I ("Ridgewood Power I"), Ridgewood Electric Power Trust II ("Ridgewood Power
II"), Ridgewood Electric Power Trust III ("Ridgewood Power III"), Ridgewood
Electric Power Trust V ("Ridgewood Power V") and The Ridgewood Power Growth Fund
(the "Growth Fund") as Delaware business trusts to participate in the
independent power industry. Ridgewood Power LLC is now also their managing
shareholder. The business objectives of these five trusts are similar to those
of the Trust.
A number of other companies are affiliates of Mr. Swanson and Ridgewood
Power. Each of these also was organized as a corporation that was wholly-owned
by Mr. Swanson. In April 1999, most of them were merged into limited liability
companies with similar names and Mr. Swanson became the sole manager and
controlling owner of each limited liability company. For convenience, the
remainder of this Memorandum will discuss each limited liability company and its
corporate predecessor as a single entity.
The Managing Shareholder is an affiliate of Ridgewood Energy
Corporation("Ridgewood Energy"), which has organized and operated 48 limited
partnership funds and one business trust over the last 17 years (of which 25
have terminated) and which had total capital contributions in excess of $190
million. The programs operated by Ridgewood Energy have invested in oil and
natural gas drilling and completion and other related activities. Other
affiliates of the Managing Shareholder include Ridgewood Securities LLC
("Ridgewood Securities"), an NASD member which has been the placement agent for
the private placement offerings of the six trusts sponsored by the Managing
Shareholder and the funds sponsored by Ridgewood Energy; Ridgewood Capital
Management LLC ("Ridgewood Capital"), which assists in offerings made by the
Managing Shareholder and which is the sponsor of four privately offered venture
capital funds (the Ridgewood Capital Venture Partners and Ridgewood Capital
Venture Partners II funds); Ridgewood Power VI LLC ("Power VI"), which is a
managing shareholder of the Growth Fund, and RPMCo. Each of these companies is
controlled by Robert E. Swanson, who is their sole director or manager.
Set forth below is certain information concerning Mr. Swanson and other
executive officers of the Managing Shareholder.
Robert E. Swanson, age 53, has also served as President of the Trust since
its inception in November 1992 and as President of RPMCo, Ridgewood Power I,
Ridgewood Power II, Ridgewood Power III, Ridgewood Power V and the Growth Fund,
since their respective inceptions. Mr. Swanson has been President and registered
principal of Ridgewood Securities and became the Chairman of the Board of
Ridgewood Capital on its organization in 1998. He also is Chairman of the Board
of the Ridgewood Capital Venture Partners I and II venture capital funds. In
addition, he has been President and sole or controlling owner of Ridgewood
Energy since its inception in October 1982. Prior to forming Ridgewood Energy in
1982, Mr. Swanson was a tax partner at the former New York and Los Angeles law
firm of Fulop & Hardee and an officer in the Trust and Investment Division of
Morgan Guaranty Trust Company. His specialty is in personal tax and financial
planning, including income, estate and gift tax. Mr. Swanson is a member of the
New York State and New Jersey bars, the Association of the Bar of the City of
New York and the New York State Bar Association. He is a graduate of Amherst
College and Fordham University Law School.
Robert L. Gold, age 41, has served as Executive Vice President of the
Managing Shareholder, RPMCo, Ridgewood Power I, the Trust, Ridgewood Power II,
Ridgewood Power III, Ridgewood Power V and the Growth Fund since their
respective inceptions, with primary responsibility for marketing and
acquisitions. He has been President of Ridgewood Capital since its organization
in 1998. As such, he is President of the Ridgewood Capital Venture Partners I
and II funds. He has served as Vice President and General Counsel of Ridgewood
Securities Corporation since he joined the firm in December 1987. Mr. Gold has
also served as Executive Vice President of Ridgewood Energy since October 1990.
He served as Vice President of Ridgewood Energy from December 1987 through
September 1990. For the two years prior to joining Ridgewood Energy and
Ridgewood Securities Corporation, Mr. Gold was a corporate attorney in the law
firm of Cleary, Gottlieb, Steen & Hamilton in New York City where his experience
included mortgage finance, mergers and acquisitions, public offerings, tender
offers, and other business legal matters. Mr. Gold is a member of the New York
State bar. He is a graduate of Colgate University and New York University School
of Law.
Thomas R. Brown, age 45, joined the Managing Shareholder in November 1994
as Senior Vice President and holds the same position with the Trust, RPMCo and
each of the other trusts sponsored by the Managing Shareholder. He became Chief
Operating Officer of the Managing Shareholder, RPMCo and the Ridgewood Power I
through V trusts in October 1996, and is the Chief Operating Officer of the
Growth Fund. He is also Senior Vice President of Ridgewood Capital and of the
two venture capital funds it manages. Mr. Brown has over 20 years' experience in
the development and operation of power and industrial projects. From 1992 until
joining the Managing Shareholder he was employed by Tampella Services, Inc., an
affiliate of Tampella, Inc., one of the world's largest manufacturers of boilers
and related equipment for the power industry. Mr. Brown was Project Manager for
Tampella's Piney Creek project, a $100 million bituminous waste coal fired
circulating fluidized bed power plant. Between 1990 and 1992 Mr. Brown was
Deputy Project Manager at Inter-Power of Pennsylvania, where he successfully
developed a 106 megawatt coal fired facility. Between 1982 and 1990 Mr. Brown
was employed by Pennsylvania Electric Company, an integrated utility, as a
Senior Thermal Performance Engineer. Prior to that, Mr. Brown was an Engineer
with Bethlehem Steel Corporation. He has an Bachelor of Science degree in
Mechanical Engineering from Pennsylvania State University and an MBA in Finance
from the University of Pennsylvania. Mr. Brown satisfied all requirements to
earn the Professional Engineer designation in 1985.
Martin V. Quinn, age 53, assumed the duties of Chief Financial Officer of
the Managing Shareholder, the Trust, the prior four trusts organized by the
Managing Shareholder and RPMCo in November 1996 under a consulting arrangement.
He became a full-time officer of the Managing Shareholder and RPMCo in April
1997 and is now also Chief Financial Officer of the Growth Fund. He is also the
Chief Financial Officer of Ridgewood Capital and of the Ridgewood Capital
Venture Partners I and II funds.
Mr. Quinn has 32 years of experience in financial management and corporate
mergers and acquisitions, gained with major, publicly-traded companies and an
international accounting firm. He formerly served as Vice President of Finance
and Chief Financial Officer of NORSTAR Energy, an energy services company, from
February 1994 until June 1996. From 1991 to March 1993, Mr. Quinn was employed
by Brown-Forman Corporation, a diversified consumer products company and
distiller, where he was Vice President-Corporate Development. From 1981 to 1991,
Mr. Quinn held various officer-level positions with NERCO, Inc., a mining and
natural resource company, including Vice President- Controller and Chief
Accounting Officer for his last six years and Vice President-Corporate
Development. Mr. Quinn's professional qualifications include his certified
public accountant qualification in New York State, membership in the American
Institute of Certified Public Accountants, six years of experience with the
international accounting firm of PricewaterhouseCoopers LLC, and a Bachelor of
Science degree in Accounting and Finance from the University of Scranton (1969).
Mary Lou Olin, age 47, has served as Vice President of the Managing
Shareholder, RPMCo, Ridgewood Capital, the Trust, Ridgewood Power I, Ridgewood
Power II, Ridgewood Power III, Ridgewood Power V and the Growth Fund since their
respective inceptions. She has also served as Vice President of Ridgewood Energy
since October 1984, when she joined the firm. Her primary areas of
responsibility are investor relations, communications and administration. Prior
to her employment at Ridgewood Energy, Ms. Olin was a Regional Administrator at
McGraw-Hill Training Systems where she was employed for two years. Prior to
that, she was employed by RCA Corporation. Ms. Olin has a Bachelor of Arts
degree from Queens College.
(c) Management Agreement.
The Trust has entered into a Management Agreement with the Managing
Shareholder detailing how the Managing Shareholder will render management,
administrative and investment advisory services to the Trust. Specifically, the
Managing Shareholder will perform (or arrange for the performance of) the
management and administrative services required for the operation of the Trust.
Among other services, it will administer the accounts and handle relations with
the Investors, provide the Trust with office space, equipment and facilities and
other services necessary for its operation and conduct the Trust's relations
with custodians, depositories, accountants, attorneys, brokers and dealers,
corporate fiduciaries, insurers, banks and others, as required. The Managing
Shareholder will also be responsible for making investment and divestment
decisions, subject to the provisions of the Declaration.
The Managing Shareholder will be obligated to pay the compensation of the
personnel and all administrative and service expenses necessary to perform the
foregoing obligations. The Trust will pay all other expenses of the Trust,
including transaction expenses, valuation costs, expenses of preparing and
printing periodic reports for Investors and the Commission, postage for Trust
mailings, Commission fees, interest, taxes, legal, accounting and consulting
fees, litigation expenses and other expenses properly payable by the Trust. The
Trust will reimburse the Managing Shareholder for all such Trust expenses paid
by it.
As compensation for the Managing Shareholder's performance under the
Management Agreement, the Trust is obligated to pay the Managing Shareholder an
annual management fee described below at Item 13 -- Certain Relationships and
Related Transactions.
The Board of the Trust (including both initial Independent Trustees) have
approved the initial Management Agreement and its renewals. Each Investor
consented to the terms and conditions of the initial Management Agreement by
subscribing to acquire Investor Shares in the Trust. The Management Agreement
will remain in effect until January 4, 2001 and year to year thereafter as long
as it is approved at least annually by (i) either the Board of the Trust or a
majority in interest of the Investors and (ii) a majority of the Independent
Trustees. The agreement is subject to termination at any time on 60 days' prior
notice by the Board, a majority in interest of the Investors or the Managing
Shareholder. The agreement is subject to amendment by the parties with the
approval of (i) either the Board or a majority in interest of the Investors and
(ii) a majority of the Independent Trustees.
(d) Executive Officers of the Trust.
Pursuant to the Declaration, the Managing Shareholder has appointed
officers of the Trust to act on behalf of the Trust and sign documents on behalf
of the Trust as authorized by the Managing Shareholder. Mr. Swanson has been
named the President of the Trust and the other executive officers of the Trust
are identical to those of the Managing Shareholder. The officers have the duties
and powers usually applicable to similar officers of a Delaware business
corporation in carrying out Trust business. Officers act under the supervision
and control of the Managing Shareholder, which is entitled to remove any officer
at any time. Unless otherwise specified by the Managing Shareholder, the
President of the Trust has full power to act on behalf of the Trust. The
Managing Shareholder expects that most actions taken in the name of the Trust
will be taken by Mr. Swanson and the other principal officers in their
capacities as officers of the Trust under the direction of the Managing
Shareholder rather than as officers of the Managing Shareholder.
(e) The Trustees.
The 1940 Act requires the Independent Trustees to be individuals who are
not "interested persons" of the Trust as defined under the 1940 Act (generally,
persons who are not affiliated with the Trust or with affiliates of the Trust).
There must always be at least two Independent Trustees; a larger number may be
specified by the Board from time to time. Each Independent Trustee has an
indefinite term. Vacancies in the authorized number of Independent Trustees will
be filled by vote of the remaining Board members so long as there is at least
one Independent Trustee; otherwise, the Managing Shareholder must call a special
meeting of Investors to elect Independent Trustees. Vacancies must be filled
within 90 days. An Independent Trustee may resign effective on the designation
of a successor and may be removed for cause by at least two-thirds of the
remaining Board members or with or without cause by action of the holders of at
least two-thirds of Shares held by Investors. Under the Declaration, the
Independent Trustees are authorized to act only where their consent is required
under the 1940 Act and to exercise a general power to review and oversee the
Managing Shareholder's other actions. They are under a fiduciary duty similar to
that of corporation directors to act in the Trust's best interest and are
entitled to compel action by the Managing Shareholder to carry out that duty, if
necessary, but ordinarily they have no duty to manage or direct the management
of the Trust outside their enumerated responsibilities.
The Independent Trustees of the Trust are John C. Belknap, Dr. Richard D.
Propper and Seymour Robin. They also serve as independent trustees for Power I
and as independent panel members of the Growth Fund. Both are independent power
programs sponsored by Ridgewood Power. Independent panel members must approve
transactions between their program and the Managing Shareholder or companies
affiliated with the Managing Shareholder, but have no other responsibilities.
Set forth below is certain information concerning these individuals, who are not
otherwise affiliated with the Trust, the Managing Shareholder or their
directors, officers or agents.
John C. Belknap, age 53, has been chief financial officer of three national
retail chains and their parent companies. He currently is an independent
financial consultant associated with Dr. Propper. From July 1997 to August
1999, he was Executive Vice President and Chief Financial Officer of Richfood
Holdings, Inc., a Virginia-based food manufacturer. From December 1995 to June
1997 Mr. Belknap was Executive Vice President and Chief Financial Officer of
OfficeMax, Inc., a national chain of office supply stores. From February 1994 to
February 1995, Mr. Belknap was Executive Vice President and Chief Financial
Officer of Zale Corporation, a 1,200 store jewelry retail chain. From January
1990 to January 1994 and from February 1995 to December 1995, Mr. Belknap was an
independent financial consultant. From January 1989 through May 1993 he aso
served as a director of and consultant to Finlay Enterprises, Inc., an operator
of leased fine jewelry departments in major department stores nationwide. Prior
to 1989, Mr. Belknap served as Chief Financial Officer of Seligman & Latz, Kay
Corporation and its subsidiary, Kay Jewelers, Inc.
From January 1990 until February 1994, Mr. Belknap consulted in a variety
of strategic corporate transactions, including mergers and acquisitions,
divestitures and refinancing. One such transaction involved the recapitalization
and change of control of Finlay in May 1993. From 1979 to 1985, Mr. Belknap
served as Chief Financial Officer of Kay Corporation ("Kay"), the parent of Kay
Jewelers, Inc. ("KJI"), a national chain of jewelry stores and leased jewelry
departments in major department stores. He served as Chief Financial Officer of
KJI from 1974 to 1979 and as its Assistant Controller from 1973 to 1974. Between
1970 and 1973, Mr. Belknap was a senior auditor at Arthur Young & Company (now
Ernst & Young), a national accounting firm. Mr. Belknap earned BA and MBA
degrees from Cornell University.
Dr. Richard D. Propper, age 49, graduated from McGill University in 1969
and received his medical degree from Stanford University in 1972. He completed
his internship and residency in Pediatrics in 1974, and then attended Harvard
University for post doctoral training in hematology/oncology. Upon the
completion of such training, he joined the staff of the Harvard Medical School
where he served as an assistant professor until 1983. In 1983, Dr. Propper left
academic medicine to found Montgomery Medical Ventures, one of the largest
medical technology venture capital firms in the United States. He served as
managing general partner of Montgomery Medical Ventures until 1993.
Dr. Propper is currently a consultant to a variety of companies for medical
matters, including international opportunities in medicine. In June 1996 Dr.
Propper agreed to an order of the Commission that required him to make filings
under Sections 13(d) and (g) and 16 of the 1934 Act and that imposed a civil
penalty of $15,000. In entering into that agreement, Dr. Propper did not admit
or deny any of the alleged failures to file recited in that order. Dr. Propper
is also an acquisition consultant for Ridgewood Capital Venture Partners, LLC
and Ridgewood Institutional Venture Partners, LLC, the first two venture capital
funds sponsored by Ridgewood Capital. He receives a fixed consulting fee from
those funds and contingent compensation from Ridgewood Capital.
Seymour (Si) Robin, age 72, has been the Executive Vice President and
CEO of Sensor Systems, Inc., an antenna manufacturing company located in
Chatsworth, California. He has held this position since 1972. From 1949 to 1953,
he owned and operated United Manufacturing Company, which specialized in
aircraft and missile antennas. From 1953 to 1957, he managed Bendix Antenna
Division, which specialized in aircraft and space antennas and avionics. In
1957, he started SRA Antenna Company as a manufacturer and technical consultant
to worldwide manufacturers or commercial and military aircraft and space
vehicles. He remained at SRA Antenna Company until 1971, at which time he became
Executive Vice President and CEO of Sensor Systems, Inc.
Mr. Robin holds degrees in mechanical and electrical engineering from
Montreal Technical Institute and U.C.L.A. He is an FAA-certified pilot
(multi-engine, instrument, land and sea ratings) since 1966. He has received the
AMC Airline Voltaire Award for the Most Outstanding Contribution to Airline
Avionics in the Past 50 Years. He also owns significant interests in commercial
and residential real estate in the southwest U.S. Mr. Robin was elected as an
Independent Trustee by the two other Independent Trustees and Mr. Swanson in
January 2000.
The Independent Trustess also serves as Independent Trustees of Trust I and
of the Growth Fund.
The Corporate Trustee of the Trust is Ridgewood Holding. Legal title to
Trust property is now and in the future will be in the name of the Trust, if
possible, or Ridgewood Holding as trustee. Ridgewood Holding is also a trustee
of Power I, Power II, Power III, Power V and the Growth Fund and of an oil and
gas business trust sponsored by Ridgewood and is expected to be a trustee of
other similar entities that may be organized by the Managing Shareholder and
Ridgewood Energy. The President, sole director and sole stockholder of Ridgewood
Holding is Robert E. Swanson; its other executive officers are identical to
those of the Managing Shareholder. The principal office of Ridgewood Holding is
at 1105 North Market Street, Suite 1300, Wilmington, Delaware 19899.
The Trustees are not liable to persons other than Shareholders for the
obligations of the Trust.
The Trust has relied and will continue to rely on the Managing Shareholder
and engineering, legal, investment banking and other professional consultants
(as needed) and to monitor and report to the Trust concerning the operations of
Projects in which it invests, to review proposals for additional development or
financing, and to represent the Trust's interests. The Trust will rely on such
persons to review proposals to sell its interests in Projects in the future.
(f) Section 16(a) Beneficial Ownership Reporting Compliance
All individuals subject to the requirements of Section 16(a) have complied
with those reporting requirements during 1999.
(g) RPMCo.
As discussed above at Item 1 - Business, RPMCo assumed day-to-day
management responsibility for the Providence Project in 1996 and has done so for
the California Pumping Projects in October 1998 and for the Maine Biomass
Projects in March 1999. Like the Managing Shareholder, RPMCo is wholly owned by
Robert E. Swanson. It entered into an "Operation Agreement" with the Trust's
subsidiary that owns the Project under which RPMCo, under the supervision of the
Managing Shareholder, will provide the management, purchasing, engineering,
planning and administrative services for the Providence Project. RPMCo will
charge the Trust at its cost for these services and for the Trust's allocable
amount of certain overhead items. RPMCo shares space and facilities with the
Managing Shareholder and its affiliates. To the extent that common expenses can
be reasonably allocated to RPMCo, the Managing Shareholder may, but is not
required to, charge RPMCo at cost for the allocated amounts and such allocated
amounts will be borne by the Trust and other programs. Common expenses that are
not so allocated will be borne by the Managing Shareholder.
Initially, the Managing Shareholder does not anticipate charging RPMCo for
the full amount of rent, utility supplies and office expenses allocable to
RPMCo. As a result, both initially and on an ongoing basis the Managing
Shareholder believes that RPMCo's charges for its services to the Trust are
likely to be materially less than its economic costs and the costs of engaging
comparable third persons as managers. RPMCo will not receive any compensation in
excess of its costs.
Allocations of costs will be made either on the basis of identifiable
direct costs, time records or in proportion to each program's investments in
Projects managed by RPMCo; and allocations will be made in a manner consistent
with generally accepted accounting principles.
RPMCo will not provide any services related to the administration of the
Trust, such as investment, accounting, tax, investor communication or regulatory
services, nor will it participate in identifying, acquiring or disposing of
Projects. RPMCo will not have the power to act in the Trust's name or to bind
the Trust, which will be exercised by the Managing Shareholder or the Trust's
officers.
The Operation Agreement does not have a fixed term and is terminable by
RPMCo, by the Managing Shareholder or by vote of a majority in interest of
Investors, on 60 days' prior notice. The Operation Agreement may be amended by
agreement of the Managing Shareholder and RPMCo; however, no amendment that
materially increases the obligations of the Trust or that materially decreases
the obligations of RPMCo shall become effective until at least 45 days after
notice of the amendment, together with the text thereof, has been given to all
Investors.
The executive officers of RPMCo are Mr. Swanson (President), Mr. Gold
(Executive Vice President), Mr. Brown (Senior Vice President and Chief Operating
Officer), Mr. Quinn (Senior Vice President and Chief Financial Officer) and Ms.
Olin (Vice President). Douglas V. Liebschner, Vice President - Operations, is a
key employee.
Douglas V. Liebschner, age 52, joined RPMCo in June 1996 as Vice President
of Operations. He has over 27 years of experience in the operation and
maintenance of power plants. From 1992 until joining RPMCo, he was employed by
Tampella Services, Inc., an affiliate of Tampella, Inc., one of the world's
largest manufacturers of boilers and related equipment for the power industry.
Mr. Liebschner was Operations Supervisor for Tampella's Piney Creek project, a
$100 million bituminous waste coal fired circulating fluidized bed ("CFB") power
plant. Between 1989 and 1992, he supervised operations of a waste to energy
plant in Poughkeepsie, N.Y. and an anthracite-waste-coal-burning CFB in
Frackville, Pa. From 1969 to 1989, Mr. Liebschner served in the U.S. Navy,
retiring with the rank of Lieutenant Commander. While in the Navy, he served
mainly in billets dealing with the operation, maintenance and repair of ship
propulsion plants, twice serving as Chief Engineer on board U.S. Navy combatant
ships. He has a Bachelor of Science degree from the U.S. Naval Academy,
Annapolis, Md.
Item 11. Executive Compensation.
Through 1995, the executive officers of the Trust and the Managing
Shareholder were compensated by Ridgewood Energy. The Trust was not charged for
their compensation; the Managing Shareholder remitted a portion of the fees paid
to it by the Trust to reimburse Ridgewood Energy for employment costs incurred
on Ridgewood Power's business. In 1996 and future years, the Managing
Shareholder compensates its officers without additional payments by the Trust
and will be reimbursed by Ridgewood Energy for costs related to Ridgewood
Energy's business. The Trust will reimburse RPMCo at cost for services provided
by RPMCo's employees; no such reimbursement per employee exceeded $60,000 in
1998 or 1999. Information as to the fees payable to the Managing Shareholder and
certain affiliates is contained at Item 13 - Certain Relationships and Related
Transactions.
As compensation for services rendered to the Trust, pursuant to the
Declaration, each Independent Trustee is entitled to be paid by the Trust the
sum of $5,000 annually and to be reimbursed for all reasonable out-of-pocket
expenses relating to attendance at Board meetings or otherwise performing his
duties to the Trust. Accordingly in January 1995 and following years the Trust
paid each Independent Trustee $5,000 for his services. The Board of the Trust is
entitled to review the compensation payable to the Independent Trustees annually
and increase or decrease it as the Board sees reasonable. The Trust is not
entitled to pay the Independent Trustees compensation for consulting services
rendered to the Trust outside the scope of their duties to the Trust without
prior Board approval.
Ridgewood Holding, the Corporate Trustee of the Trust, is not entitled to
compensation for serving in such capacity, but is entitled to be reimbursed for
Trust expenses incurred by it which are properly reimbursable under the
Declaration.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The Managing Shareholder purchased for cash one full Investor Share. By
virtue of its purchase of Investor Shares, the Managing Shareholder is entitled
to the same ratable interest in the Trust as all other purchasers of Investor
Shares. No other Trustees or executive officers of the Trust acquired Investor
Shares in the Trust's offering. No person beneficially owns 5% or more of the
Investor Shares.
The Managing Shareholder was issued one Management Share in the Trust
representing the beneficial interests and management rights of the Managing
Shareholder in its capacity as the Managing Shareholder (excluding its interest
in the Trust attributable to Investor Shares it acquired in the offering). The
management rights of the Managing Shareholder are described in further detail
above at Item 1 - Business and below in Item 10. Directors and Executive
Officers of the Registrant. Its beneficial interest in cash distributions of the
Trust and its allocable share of the Trust's net profits and net losses and
other items attributable to the Management Share are described in further detail
below at Item 13 -- Certain Relationships and Related Transactions.
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable
reserves which the Trust deems necessary to cover anticipated Trust expenses, is
to be distributed to the Investors and the Managing Shareholder (collectively,
the "Shareholders"), from time to time as the Trust deems appropriate. Prior to
Payout (the point at which Investors have received cumulative distributions
equal to the amount of their capital contributions), each year all distributions
from the Trust, other than distributions of the revenues from dispositions of
Trust Property, are to be allocated 99% to the Investors and 1% to the Managing
Shareholder until Investors have been distributed during the year an amount
equal to 14% of their total capital contributions (a "14% Priority
Distribution"), and thereafter all remaining distributions from the Trust during
the year, other than distributions of the revenues from dispositions of Trust
Property, are to be allocated 80% to Investors and 20% to the Managing
Shareholder. Revenues from dispositions of Trust Property are to be distributed
99% to Investors and 1% to the Managing Shareholder until Payout. In all cases,
after Payout, Investors are to be allocated 80% of all distributions and the
Managing Shareholder 20%.
For any fiscal period, the Trust's net profits, if any, other than those
derived from dispositions of Trust Property, are allocated 99% to the Investors
and 1% to the Managing Shareholder until the profits so allocated offset (1) the
aggregate 14% Priority Distribution to all Investors and (2) any net losses from
prior periods that had been allocated to the Shareholders. Any remaining net
profits, other than those derived from dispositions of Trust Property, are
allocated 80% to the Investors and 20% to the Managing Shareholder. If the Trust
realizes net losses for the period, the losses are allocated 80% to the
Investors and 20% to the Managing Shareholder until the losses so allocated
offset any net profits from prior periods allocated to the Shareholders. Any
remaining net losses are allocated 99% to the Investors and 1% to the Managing
Shareholder. Revenues from dispositions of Trust Property are allocated in the
same manner as distributions from such dispositions. Amounts allocated to the
Investors are apportioned among them in proportion to their capital
contributions.
On liquidation of the Trust, the remaining assets of the Trust after
discharge of its obligations, including any loans owed by the Trust to the
Shareholders, will be distributed, first, 99% to the Investors and the remaining
1% to the Managing Shareholder, until Payout, and any remainder will be
distributed to the Shareholders in proportion to their capital accounts.
The Trust paid fees to the Managing Shareholder and its affiliates as follows:
Fee Paid to 1999 1998 1997 1996
management Managing
fee Shareholder 467,268 $1,050,700 $1,154,758 $888,209
Cost reimbursements* RPMCo 404,055 401,290 467,881 337,228
Investment fee Managing
Shareholder 0 0 0 627,561
Placement agent fee Ridgewood
and sales commis- Securities
sions Corporation 0 0 0 315,493
Organizational, Managing
distribution and Shareholder
offering fee 0 0 0 1,892,959
* These include all payroll, parts, routine maintenance and other expenses
(except for royalties for landfill gas but including an allocation of RPMCo
overhead) of the Providence Project.
The investment fee equaled 2% of the proceeds of the offering of Investor
Shares and was payable for the Managing Shareholder's services in investigating
and evaluating investment opportunities and effecting investment transactions.
The placement agent fee (1% of the offering proceeds) and sales commissions were
also paid from proceeds of the offering, as was the organizational, distribution
and offering fee (5% of offering proceeds) for legal, accounting, consulting,
filing, printing, distribution, selling, closing and organization costs of the
offering.
The management fee, payable monthly under the Management Agreement at the
annual rate of 3% of the Trust's net asset value, began on the date the first
Project was acquired and compensates the Managing Shareholder for certain
management, administrative and advisory services for the Trust. In addition to
the foregoing, the Trust reimbursed the Managing Shareholder at cost for
expenses and fees of unaffiliated persons engaged by the Managing Shareholder
for Trust business and for payroll and other costs of operation of the
Providence and California Pumping Projects. Beginning in 1996, these
reimbursements were paid to RPMCo. The reimbursements to RPMCo, which do not
exceed its actual costs and allocable overhead, are described at Item 10(g) -
Directors and Executive Officers of the Registrant -- RPMCo.
Other information in response to this item is reported in response to Item
11. Executive Compensation, which information is incorporated by reference into
this Item 13.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Financial Statements.
See the Index to Financial Statements in Item 8 hereof.
(b) Reports on Form 8-K.
No Form 8-K was filed with the Commission by the Registrant during the
quarter ending December 31, 1999.
(c) Exhibits
3A. Certificate of Trust of the Registrant is incorporated by reference to
Exhibit 3A of Registrant's Registration Statement filed with the Commission on
February 15, 1994.
3B. Declaration of Trust of the Registrant is incorporated by reference to
Exhibit 3B of Registrant's Registration Statement filed with the Commission on
February 19, 1994.
3C. Amendment No. 1 to Declaration of Trust is incorporated by reference to
Exhibit 3C of Registrant's Annual Report on Form 10-K for the year ended
December 31, 1996.
10A. Asset Acquisition Agreement by and among Northeast Landfill Power
Joint Venture, Northeast Landfill Power Company, Johnson Natural Power
Corporation and Ridgewood Providence Power Partners, L.P. , is incorporated by
reference to Exhibit 2 of the Registrant's Current Report on Form 8-K filed with
the Commission on May 2, 1996.
10B. Agreement of Merger, dated as of July 1, 1996, by and among
Consolidated Hydro Maine, Inc., CHI Universal, Inc., Consolidated Hydro, Inc.,
Ridgewood Maine Power Partners, L.P. and Ridgewood Maine Hydro Corporation.
Incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on
Form 8-K filed with the Commission on January 8, 1997.
10C. Letter, dated November 15, 1996, amending Agreement of Merger.
Incorporated by reference to Exhibit 2.2 of Amendment No. 1 to the Registrant's
Current Report on Form 8-K filed with the Commission on January 9, 1997
10D. Letter, dated December 3, 1996, amending Agreement of Merger.
Incorporated by reference to Exhibit 2.3 of the Registrant's Current Report on
Form 8-K filed with the Commission on January 8, 1997.
10E. Operation, Maintenance and Administration Agreement, dated November
__, 1996, by and among Ridgewood Maine Hydro Partners, L.P., CHI Operations,
Inc. and Consolidated Hydro, Inc. Incorporated by reference to Exhibit 10 of the
Registrant's Current Report on Form 8-K filed with the Commission on January 8,
1997.
10F. Management Agreement, dated as of __________, 1996, between the
Registrant and Ridgewood Power Corporation. Incorporated by reference to Exhibit
10F of the Registrant's Annual Report on Form 10-K for the year ended December
31, 1996.
10G. Operation Agreement, dated as of April 16, 1996, among the Registrant,
Ridgewood Providence Corporation and Ridgewood Power Management Corporation.
Incorporated by reference to Exhibit 10G of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1996
10H. Agreement to Purchase Membership Interests, dated as of June 11, 1997,
by and between Ridgewood Maine, L.L.C. and Indeck Maine Energy, L.L.C.
Incorporated by reference to Exhibit 2.A. of Amendment No. 1 to Registrant's
Current Report on Form 8-K dated July 1, 1997.
10I. Amended and Restated Operating Agreement ofIndeck Maine Energy,
L.L.C., dated as of June 11, 1997. Incorporated by reference to Exhibit 2.B. of
Amendment No. 1 to Registrant's Current Report on Form 8-K dated July 1, 1997.
The Registrant agrees to furnish supplementally a copy of any omitted exhibit or
schedule to agreements filed as exhibits to the Commission upon request.
21. Subsidiaries of the Registrant Page
24. Powers of Attorney Page
27. Financial Data Schedule Page
99. Listing of Statutory Provisions that the Trust Agrees to Comply with.
Incorporated by reference to Exhibit 99 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1996.
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.
Signature Title Date
RIDGEWOOD ELECTRIC POWER TRUST IV (Registrant)
By:/s/ Robert E. Swanson President and Chief April 14, 2000
Robert E. Swanson Executive Officer
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 and on the dates indicated.
By:/s/ Robert E. Swanson President and Chief April 14, 2000
Robert E. Swanson Executive Officer
By:/s/ Martin V. Quinn Senior Vice President and
Martin V. Quinn Chief Financial Officer April 14, 2000
By:/s/ Christopher Naunton Director of Accounting April 14, 2000
Christopher Naunton
RIDGEWOOD POWER LLC Managing Shareholder April 14, 2000
By:/s/ Robert E. Swanson President
Robert E. Swanson
/s/ Robert E. Swanson * Independent Trustee April 14, 2000
John C. Belknap
/s/ Robert E. Swanson * Independent Trustee April 14, 2000
Richard D. Propper
/s/ Robert E. Swanson* Independent Trustee April 14, 2000
Seymour Robin
As attorney-in-fact for the Independent Trustee
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Financial Statements
December 31, 1999, 1998 and 1997
<PAGE>
Report of Independent Accountants
To the Shareholders and Trustees of
Ridgewood Electric Power Trust IV:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in shareholders' equity and of
cash flows present fairly, in all material respects, the financial position of
Ridgewood Electric Power Trust IV (the "Trust") and its subsidiaries at December
31, 1999 and 1998, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1999, in conformity
with accounting principles generally accepted in the United States. These
financial statements are the responsibility of the Trust'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 standards generally accepted in the United States, 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.
PricewaterhouseCoopers LLP
New York, NY
March 24, 2000
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Balance Sheet
- --------------------------------------------------------------------------------
December 31,
----------------------------
1999 1998
------------ ------------
Assets:
Cash and cash equivalents .................... $ 893,383 $ 2,021,168
Accounts receivable, trade ................... 613,002 617,973
Due from affiliates .......................... 442,432 377,710
Other assets ................................. 60,863 57,975
------------ ------------
Total current assets ..................... 2,009,680 3,074,826
Investments:
Maine Hydro Projects ......................... 5,663,505 6,217,289
Maine Biomass Projects ....................... 5,825,271 6,306,818
Santee River Rubber .......................... 4,090,601 4,501,357
Electric power equipment held for resale ..... 250,000 455,182
Plant and equipment .......................... 16,789,544 16,359,211
Accumulated depreciation ..................... (2,957,855) (2,073,744)
------------ ------------
13,831,689 14,285,467
------------ ------------
Electric power sales contract ................ 8,338,040 8,338,040
Accumulated amortization ..................... (2,057,950) (1,502,081)
------------ ------------
6,280,090 6,835,959
------------ ------------
Spare parts inventory ........................ 838,142 746,178
Debt reserve fund ............................ 666,346 637,108
------------ ------------
Total assets ............................. $ 39,455,324 $ 43,060,184
------------ ------------
Liabilities and Shareholders' Equity:
Liabilities:
Current maturities of long-term debt ......... $ 716,995 $ 651,613
Accounts payable and accrued expenses ........ 611,750 563,685
Due to affiliates ............................ 341,018 441,614
------------ ------------
Total current liabilities ................ 1,669,763 1,656,912
Long-term debt, less current portion ......... 3,479,460 4,196,455
Minority interest in the Providence Project .. 5,924,813 6,202,894
Commitments and contingencies
Shareholders' Equity:
Shareholders' equity (476.8875 investor
shares issued and outstanding) .............. 28,502,542 31,098,950
Managing shareholder's accumulated deficit
(1 management share issued and outstanding) . (121,254) (95,027)
------------
------------
Total shareholders' equity ............... 28,381,288 31,003,923
------------ ------------
Total liabilities and shareholders' equity $ 39,455,324 $ 43,060,184
------------ ------------
See accompanying notes to the consolidated financial statements.
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Statement of
Operations
- --------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
Net sales ....................... $ 7,179,229 $ 6,905,883 $ 6,810,911
Sublease income ................. 369,000 369,000 369,000
----------- ----------- -----------
Total revenue .......... 7,548,229 7,274,883 7,179,911
Cost of sales, including
depreciation and amortization
of $1,439,980, $1,560,801 and
$1,267,572 in 1999, 1998 and
1997 ........................... 6,347,905 5,638,396 4,879,962
----------- ----------- -----------
Gross profit .................... 1,200,324 1,636,487 2,299,949
General and administrative
expenses ....................... 709,722 709,715 537,371
Management fee paid to
the managing shareholder 467,268 1,050,700 1,154,758
Write down equipment held in
storage ........................ 205,182 -- --
Project due diligence costs ..... -- 204,579 668,554
----------- ----------- -----------
Total other operating expenses . 1,382,172 1,964,994 2,360,683
----------- ----------- -----------
Loss from operations ............ (181,848) (328,507) (60,734)
----------- ----------- -----------
Other income (expense):
Interest income ................ 83,350 374,585 926,641
Interest expense ............... (437,238) (496,658) (572,660)
Other income ................... 71,840 -- --
Loss from Maine Biomass
Projects ...................... (1,006,797) (694,321) (680,109)
Income from Maine Hydro
Projects ...................... 849,456 657,989 521,710
Income from Santee River Rubber 49,244 181,675 --
----------- ----------- -----------
Other income (expense), net .. (390,145) 23,270 195,582
----------- ----------- -----------
(Loss) income before minority
interest ...................... (571,993) (305,237) 134,848
Minority interest in the earnings
of the Providence Project ...... (171,984) (296,854) (537,625)
----------- ----------- -----------
Net loss ........................ $ (743,977) $ (602,091) $ (402,777)
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Statement of Changes In Shareholders' Equity
For the Years Ended December 31, 1999, 1998 and 1997
- --------------------------------------------------------------------------------
Managing
Shareholders Shareholder Total
------------ ------------ ------------
Shareholders' equity, January
1, 1997 ..................... $ 38,764,199 $ (17,600) $ 38,746,599
Cash distributions ........... (3,287,256) (33,205) (3,320,461)
Net loss for the year ........ (398,749) (4,028) (402,777)
------------ ------------ ------------
Shareholders' equity, December
31, 1997 .................... 35,078,194 (54,833) 35,023,361
Cash distributions ........... (3,383,174) (34,173) (3,417,347)
Net loss for the year ........ (596,070) (6,021) (602,091)
------------ ------------ ------------
Shareholders' equity, December
31, 1998 .................... 31,098,950 (95,027) 31,003,923
Cash distributions ........... (1,859,871) (18,787) (1,878,658)
Net loss for the year ........ (736,537) (7,440) (743,977)
------------ ------------ ------------
Shareholders' equity, December
31, 1999 .................... $ 28,502,542 $ (121,254) $ 28,381,288
------------ ------------ ------------
See accompanying notes to the consolidated financial statements.
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Statement of Cash Flows
- --------------------------------------------------------------------------------
Year Ended December 31,
--------------------------------------------
1999 1998 1997
------------ ------------ ------------
Cash flows from operating
activities:
Net loss ..................... $ (743,977) $ (602,091) $ (402,777)
------------ ------------ ------------
Adjustments to reconcile
net loss to net cash flows
from operating activities:
Depreciation and
amortization ............... 1,439,980 1,560,801 1,267,572
Minority interest in earnings
of the Providence Project .. 171,984 296,854 537,625
Write down equipment held
in storage ................. 205,182 -- --
Income from unconsolidated
Maine Hydro Projects ....... (849,456) (657,989) (521,710)
Loss from unconsolidated
Maine Biomass Projects ..... 1,006,797 694,321 680,109
Income from unconsolidated
Santee River Rubber ........ (49,244) (181,675) --
Changes in assets and
liabilities:
Decrease in maintenance
reserve fund ............... -- -- 394,070
Decrease (increase) in
accounts receivable, trade . 4,971 (58,209) 505,417
Increase in spare parts
inventory .................. (91,964) (362,368) --
Increase (decrease) in
accounts payable and
accrued expenses ........... 48,065 179,152 (363,426)
(Decrease) increase in due
to/from affiliates, net ... (165,318) (429,813) 401,660
Other- net .................. (2,888) 39,478 157,081
------------ ------------ ------------
Total adjustments ........... 1,718,109 1,080,552 3,058,398
------------ ------------ ------------
Net cash provided by
operating activities ....... 974,132 478,461 2,655,621
------------ ------------ ------------
Cash flows from investing
activities:
Investment in Maine Hydro
Projects ................... -- -- (265,953)
Investment in Maine Biomass
Projects ................... (525,250) (383,277) (7,297,971)
Investment in Santee River
Rubber ..................... -- (4,489,819) --
Distributions from Maine
Hydro Projects ............. 1,403,240 1,135,526 1,006,257
Distributions from Santee
River Rubber ............... 460,000 170,137 --
Capital expenditures ........ (430,333) (1,409,476) (3,060,284)
Deferred due diligence costs -- 27,159 218,669
------------ ------------ ------------
Net cash provided by (used
in) investing activities ... 907,657 (4,949,750) (9,399,282)
------------ ------------ ------------
Cash flows from financing
activities:
Cash distributions to
shareholders ............... (1,878,658) (3,417,347) (3,320,461)
Payments to reduce long-term
debt ....................... (651,613) (592,192) (538,191)
Increase in debt reserve
fund ....................... (29,238) (31,909) (29,758)
Distributions to minority
interest ................... (450,065) (552,376) (967,477)
------------ ------------ ------------
Net cash used in financing
activities ................. (3,009,574) (4,593,824) (4,855,887)
------------ ------------ ------------
Net decrease in cash and
cash equivalents ............ (1,127,785) (9,065,113) (11,599,548)
Cash and cash equivalents,
beginning of year ........... 2,021,168 11,086,281 22,685,829
------------ ------------ ------------
Cash and cash equivalents,
end of year ................. $ 893,383 $ 2,021,168 $ 11,086,281
------------ ------------ ------------
See accompanying notes to the consolidated financial statements.
<PAGE>
Ridgewood Electric Power Trust IV
Notes to the Consolidated Financial Statements
- --------------------------------------------------------------------------------
1. Organization and Purpose
Nature of Business
Ridgewood Electric Power Trust IV (the "Trust") was formed as a Delaware
business trust in September 1994, by Ridgewood Energy Holding Corporation acting
as the Corporate Trustee. The managing shareholder of the Trust is Ridgewood
Power LLC (formerly Ridgewood Power Corporation). The Trust began offering
shares on February 6, 1995 and discontinued its offering of shares in March
1996. The Trust had no operations prior to the commencement of the share
offering.
The Trust has been organized to invest in independent power generation and other
capital facilities and in the development of these facilities. These independent
power generation facilities will include cogeneration facilities, which produce
both electricity and heat energy and other power plants that use various fuel
sources (except nuclear). The power plants will sell electricity and, in some
cases, heat energy to utilities and industrial users under long-term contracts.
Business Development Company Election
The Trust initially made an election to be treated as a Business Development
Company ("BDC") under the Investment Company Act of 1940 ("the 1940 Act"). On
January 24, 1995, the Trust notified the Securities Exchange Commission of such
election and registered its shares under the Securities Exchange Act of 1934
("the 1934 Act"). On March 24, 1995, the election and registration became
effective.
On September 9, 1996, through a proxy solicitation, the Trust requested investor
consent to end the BDC status. As of October 2, 1996, more than 50% of the
investor shares consented to the elimination of the BDC status. Accordingly, the
Trust is no longer an investment company under the 1940 Act.
2. Summary of Significant Accounting Policies
Principles of consolidation and accounting for investment in power generation
projects The consolidated financial statements include the accounts of the Trust
and affiliates owned more than 50%. All material intercompany transactions have
been eliminated.
The Trust uses the equity method of accounting for its investments in affiliates
which are 50% or less owned because the Trust has the ability to exercise
significant influence over the operating and financial policies of the
affiliates but does not control the affiliate. The Trust's share of the earnings
of the affiliates is included in the consolidated results of operations.
Use of estimates
The preparation of consolidated 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 the estimates.
Cash and cash equivalents
The Trust considers all highly liquid investments with maturities when purchased
of three months or less to be cash and cash equivalents. Cash and cash
equivalents consist of commercial paper and funds deposited in bank accounts.
Plant and equipment
Plant and equipment, consisting principally of electrical generating equipment,
is stated at cost. Renewals and betterments that increase the useful lives of
the assets are capitalized. Repair and maintenance expenditures that increase
the efficiency of the assets are expensed as incurred. The Trust periodically
assesses the recoverability of plant and equipment, and other long-term assets,
based on their estimated future cash flows.
Depreciation is recorded using the straight-line method over the useful lives of
the assets, which are 10 to 20 years. During 1999, 1998 and 1997, the Trust
recorded depreciation expense of $884,111, $1,004,932 and $711,703,
respectively.
Intangible asset
A portion of the purchase price of the Providence Project was assigned to the
Electric Power Sales Contract and is being amortized over the life of the asset
(15 years) on a straight-line basis. During 1999, 1998 and 1997, the Trust
recorded amortization expense of $555,869.
Electric power equipment held for resale
The Trust owns certain used electric power equipment that is stated at cost,
which approximates estimated net realizable value.
Revenue recognition
Power generation revenue is recognized based on power delivered at rates
stipulated in the power sales contract. Interest and dividend income is recorded
when earned.
Income taxes
No provision is made for income taxes in the accompanying financial statements
as the income or losses of the Trust are passed through and included in the tax
returns of the individual shareholders of the Trust.
Offering costs
Costs associated with offering Trust shares (selling commissions, distribution
and offering costs) are reflected as a reduction of the shareholders' capital
contributions.
Due diligence costs relating to potential power projects
Costs relating to the due diligence performed on potential project investments
are initially deferred, until such time as the Trust determines whether or not
it will make an investment in the project. Costs relating to completed projects
are capitalized and costs relating to rejected projects are expensed at the time
of rejection.
These costs consist of payments for consultants and other unaffiliated parties
performing financial, engineering, legal and other due diligence procedures and
negotiations. It also includes travel and other out-of-pocket costs incurred by
employees of the managing shareholder and affiliates investigating potential
project investments.
Reclassification
Certain items in previously issued financial statements have been reclassified
for comparative purposes.
3. Investments
The Trust has the following investments:
Investment at December 31,
-----------------------------------
Project Name Accounting Method 1999 1998
- -------------------------- ------------- ----------- -----------
Providence Project ....... Consolidation $10,671,302 $11,181,794
California Pumping Project Consolidation 442,224 597,478
Electric Power Equipment . Consolidation 250,000 455,182
Maine Hydro Projects ..... Equity Method 5,663,505 6,217,289
Maine Biomass Projects ... Equity Method 5,825,271 6,306,817
Santee River Rubber ...... Equity Method 4,090,601 4,501,357
----------- -----------
$26,942,903 $29,259,917
----------- -----------
Providence Project
In 1996, the Trust, through a subsidiary, Ridgewood Providence Power Partners,
L.P., purchased substantially all of the net assets of Northeastern Landfill
Power Joint Venture. The assets acquired include a 12.3 megawatt capacity
electrical generating station, located at the Central Landfill in Johnston,
Rhode Island (the "Providence Project"). In 1997, the capacity was increased to
13.8 megawatts. The Providence Project includes nine reciprocating electric
generator engines, which are fueled by methane gas produced and collected from
the landfill. The electricity generated is sold to New England Power Corporation
under a long-term contract. The purchase price was $15,533,021 in cash,
including transaction costs and repayment of $3,000,000 of principal on the
senior secured non-recourse notes payable. In addition, Providence Power assumed
the obligation to repay the remaining principal outstanding of $6,310,404 on the
senior secured non-recourse notes payable.
The Trust owns 64.3% of the Providence Project and the remaining 35.7% is owned
by Ridgewood Electric Power Trust III ("Trust III"). Ridgewood Power Corporation
is the managing partner of the Trust and Trust III.
The acquisition of the Providence Project was accounted for as a purchase and
the results of operations of the Providence Project have been included in the
Trust's Consolidated Financial Statements since the acquisition date. The
purchase price was allocated to the net assets acquired, based on their
respective fair values. Of the purchase price, $8,338,040 was allocated to the
Electric Power Sales Contract and is being amortized over 15 years.
California Pumping Project
In 1995, the Trust acquired a package of natural gas and diesel fueled engines
which drive deep irrigation well pumps in Ventura County, California from an
affiliated trust. The engines' shaft horsepower-hours are sold to the operator
at a discount from the equivalent kilowatt hours of electricity. Prior to
September 30, 1998, the project was operated by a third party manager and the
Trust received a distribution of $0.02 per equivalent kilowatt up to 3,000
running hours per year and $0.01 per equivalent kilowatt for each additional
running hour per year. The operator paid for fuel, maintenance, repair and
replacement. The initial acquisition included 11 engines with a rated capacity
of 1.2 megawatts. On October 1, 1998, the Trust terminated the operating
agreement with the third party manager and Ridgewood Power Management
Corporation, an affiliate of the managing shareholder, began operating the
project. The project paid $94,160 to the third party manager to terminate the
operating agreement At December 31, 1999 and 1998, the Trust's total investment
in the California Pumping Project was $442,224 and $597,478, respectively.
Electric Power Equipment Held for Resale
The Trust purchased, from an affiliated entity, various used electric power
generation equipment to be held for resale or, in the event a buyer is not
found, for use in potential power generation projects. The equipment is held in
storage. At December 31, 1998, the cost of such equipment was $455,182. In 1999,
the Trust wrote down the equipment to its estimated fair value of $250,000 and
recorded a charge against earnings of $205,182.
Maine Hydro Projects
In 1996, Ridgewood Maine Hydro Partners, L.P. ("Ridgewood Hydro L.P.") was
formed as a Delaware limited partnership and acquired 14 hydroelectric projects,
located in Maine (the "Maine Hydro Projects"), from a subsidiary of Consolidated
Hydro, Inc. The assets acquired include a total of 11.3 megawatts of electrical
generating capacity. The electricity generated is sold to Central Maine Power
Company and Bangor Hydro Company under long-term contracts. The purchase price
was $13,628,395 cash, including transaction costs. In addition, Ridgewood Hydro
L.P. assumed a long-term lease obligation of $1,004,679.
The Trust owns a 50% limited partnership interest in Ridgewood Hydro L.P. and
50% of the outstanding common stock of Ridgewood Maine Hydro Corporation, which
is the sole general partner of Ridgewood Hydro L.P. The remaining 50% is owned
by Ridgewood Electric Power Trust V ("Trust V"). Ridgewood Power LLC is the
managing partner of the Trust and Trust V.
The Trust's 50% investment in the Maine Hydro Projects is accounted for under
the equity method of accounting. The Trust's equity in the earnings of the Maine
Hydro Projects has been included in the financial statements since acquisition.
The Maine Hydro Projects are operated by a subsidiary of CHI Energy, Inc.
(formerly Consolidated Hydro, Inc.), under an Operation, Maintenance and
Administrative Agreement. The annual operator's fee is $307,500, adjusted for
inflation, plus an annual incentive fee equal to 50% of the net cash flow in
excess of a target amount. The Maine Hydro Projects recorded $323,003, $429,714
and $429,430 of expense under this arrangement during the periods ended December
31, 1999, 1998 and 1997, respectively. The agreement has a five-year term,
expiring on June 30, 2001, and can be renewed for two additional five-year terms
by mutual consent.
Summarized financial information for the Maine Hydro Projects is as follows:
Balance Sheet Information
December 31, 1999 December 31, 1998
----------- -----------
Current assets .............. $ 1,573,177 $ 1,346,077
Electric power sales contract 10,105,173 11,165,469
Other non-current assets .... 1,270,396 1,057,892
----------- -----------
Total assets ................ $12,948,746 $13,569,438
----------- -----------
Current liabilities ......... $ 1,621,737 $ 438,443
Non-current liabilities ..... -- 696,418
Partners' equity ............ 11,327,009 12,434,577
----------- -----------
Total liabilities and equity $12,948,746 $13,569,438
----------- -----------
Statement of Operations Information
For the Year Ended December 31,
----------------------------------------
1999 1998 1997
----------- ----------- -----------
Revenue ................. $ 4,756,189 $ 4,511,361 $ 4,113,065
Total expenses .......... 3,002,245 3,217,846 2,952,589
Interest income (expense) (55,033) 22,464 (117,056)
----------- ----------- -----------
Net income .............. $ 1,698,911 $ 1,315,979 $ 1,043,420
----------- ----------- -----------
The Maine Hydro Projects qualify as small power production facilities under the
Public Utility Regulatory Policies Act ("PURPA"). PURPA requires that each
electric utility company operating at the location of a small power production
facility, as defined, purchase the electricity generated by such facility at a
specified or negotiated price. The Maine Hydro Projects sell substantially all
of their electrical output to two public utility companies, Central Maine Power
Company ("CMP") and Bangor Hydro-Electric Company ("BHC"), under long-term power
purchase agreements. Eleven of the twelve power purchase agreements with CMP
expire in December 2008 and are renewable for an additional five-year period.
The twelfth power purchase agreement with CMP expires in December 2007 with CMP
having the option to extend the contract for three more five-year periods. The
two power purchase agreements with BHC expire December 2014 and February 2017.
Maine Biomass Projects
On July 1, 1997, through a subsidiary, the Trust purchased a preferred
membership interest in Indeck Maine Energy, L.L.C. ("Maine Biomass Projects"),
which owns two electric power generating stations fueled by waste wood. The
aggregate purchase price was $7,297,971 and includes transaction costs of
$297,971. Each project has 24.5 megawatts of electrical generating capacity. The
Penobscot project is located in West Enfield, Maine and the Eastport project is
located in Jonesboro, Maine. The Maine Biomass Projects had a power sales
contract with the New England Power Pool, which expired on August 31, 1997. The
facilities were shut down in September 1997 and were reactivated in November
1997 to sell capacity and energy to BHC on a month-to-month basis. The
facilities were again shut down in January 1998. The facilities currently sell
installed capacity and are periodically restarted for testing or for the sale of
energy during peak periods of demand. The cost of maintaining the idled
facilities in good condition is approximately $100,000 per month.
The preferred membership interest entitles the Trust to receive an 18%
cumulative annual return on its $7,000,000 capital contribution to the Maine
Biomass Projects from the operating net cash flow from the projects. Trust V
also purchased an identical preferred membership interest in Indeck Maine. After
payments in full to the preferred membership interests, up to $2,520,000 of any
remaining operating net cash flow during the year is paid to the other Maine
Biomass Project members. Any remaining operating net cash flow is payable 25% to
the Trust and Trust V and 75% to the other Maine Biomass Project members.
In 1999 and 1998, the Trust loaned $525,250 and 375,000, respectively, to the
Maine Biomass Projects. The loan is in the form of demand notes that bear
interest at 5% per annum. Trust V made identical loans to the Maine Biomass
Projects. The other Maine Biomass Project members also loaned $1,050,500 and
$750,000 to the Maine Biomass Projects with the same terms in 1999 and 1998,
respectively
The Trust's investment in the Maine Biomass Projects is accounted for under the
equity method of accounting. The Trust's equity in the loss of the Maine Biomass
Projects has been included in the financial statements since July 1, 1997.
The Penobscot and Eastport projects were operated by Indeck Operations, Inc., an
affiliate of the members of Indeck Maine. The annual operator's fee is $300,000,
of which $200,000 is payable contingent upon the Trusts receiving their
cumulative annual return. The management agreement had a term of one year and
automatically continued for successive one year terms, unless canceled by either
the Maine Biomass Projects or Indeck Operations, Inc. The Maine Biomass Projects
exercised their right to terminate the contract on March 1, 1999 because certain
preferred membership interest payments have not been made. Under an Operating
Agreement with the Trust, Ridgewood Power Management LLC ("Ridgewood
Management"), formerly Ridgewood Power Management Corporation), an entity
related to the managing shareholder through common ownership, began providing
management, purchasing, engineering, planning and administrative services to the
Maine Biomass Projects. Ridgewood Management charges the projects at its cost
for these services and for the allocable amount of certain overhead items.
Allocations of costs are on the basis of identifiable direct costs, time records
or in proportion to amounts invested in projects.
From June thorough December 1999, the facilities periodically operated on
dispatch from ISO-New England, Inc. (the "ISO") and also submitted offers to the
ISO to run at high prices during power emergencies. The facilities have claimed
the ISO owes them approximately $14 million for the electricity products they
provided in those periods and the ISO has claimed that no material revenues at
all are due to the projects. The facilities have not recorded any of the
disputed revenues in their financial statements and it is too early to estimate
the outcome of the dispute.
Summarized financial information for the Maine Biomass Projects is as follows:
Balance Sheet Information
December 31, 1999 December 31, 1998
----------- -----------
Current assets: ............ $ 1,103,266 $ 668,228
Non-current assets ......... 3,154,813 3,339,584
----------- -----------
Total assets ............... $ 4,258,079 $ 4,007,812
----------- -----------
Current liabilities: ....... $ 4,394,990 $ 1,952,062
Members' equity ............ (136,911) 2,055,750
----------- -----------
Total liabilities and equity $ 4,258,079 $ 4,007,812
----------- -----------
Statement of Operations Information
For the period from inception
For the Year Ended For the Year Ended (April 1, 1997) to December
December 31, 1999 December 31, 1998 31, 1997
----------- ----------- -----------
Revenue ...... $ 1,391,039 $ 1,430,296 $ 2,991,793
Total expenses 3,583,700 2,847,896 4,376,458
----------- ----------- -----------
Net loss ..... $(2,192,661) $(1,417,600) $(1,384,665)
----------- ----------- -----------
Santee River Rubber
In August 1998, the Trust and an affiliate, Trust V, purchased preferred
membership interests in Santee River Rubber Company, LLC, a newly organized
South Carolina limited liability company ("Santee River Rubber"). Santee River
Rubber is building a waste tire and rubber processing facility located near
Charleston, South Carolina. The facility is expected to begin full scale
operations in July 2000. The Trust and Trust V purchased the interests through a
limited liability company owned one-third by the Trust and two-thirds by Trust
V. The Trust's share of the purchase price was $4,489,819 and Trust V's share of
the purchase price was $8,979,639.
Until January 2000 or until the facility begins operations, which ever occurs
first, Santee River Rubber will pay the Trust and Trust V interest at 12% per
year on $11,000,000 of their investment. After operations begin, the Trusts are
entitled to receive all cash flow after payment of debt and other obligations
until the Trusts receive a cumulative 20% return on their total investment.
Thereafter, the Trusts receive 25% of any remaining cash flow available for
distribution. All cash distributions and tax allocations received from Santee
River Rubber are shared one-third by the Trust and two-thirds by Trust V.
The Trusts have the right to designate two of the five members of Santee River
Rubber and have the further right to remove a third member and designate a
successor in the event of certain defaults under Santee River Rubber's operating
agreement. The remaining equity interest is owned by a wholly-owned subsidiary
of Environmental Processing Systems, Inc. of New York, a company not affiliated
with the Trust.
At the same time as the Trusts purchased their membership interests, Santee
River Rubber borrowed $16,000,000 through tax exempt revenue bonds and another
$16,000,000 through taxable convertible bonds. It also obtained $4,500,000 of
subordinated financing from the general contractor of the facility.
The project has been designed to receive and process waste tires and other waste
rubber products and produce fine crumb rubber of various sizes. The processing
will include both ambient and cryogenic processing equipment using liquid
nitrogen. Santee River Rubber anticipates that the final product will be fine
crumb rubber that can be used to manufacture new tires or to replace virgin
rubber in many applications.
Santee River Rubber has entered into long-term agreements for the supply of its
requirements for waste tires, electricity and liquid nitrogen. Santee River
Rubber has entered into short-term (ranging from one to three years) crumb
rubber sales contracts for a portion of the facility's output. The agreements
are contingent upon successful testing of the facility's output.
The Trust's investment in Santee River Rubber is accounted for under the equity
method of accounting. The Trust's equity in the loss of Santee River Rubber has
been included in the financial statements since August 19, 1998.
Summarized financial information for Santee River Rubber is as follows:
Balance Sheet Information
December 31, 1999 December 31, 1998
----------- -----------
Current assets ............. $ 1,910,190 $24,403,190
Construction in progress ... 32,899,358 15,392,656
Other non-current assets ... 4,685,995 4,761,119
----------- -----------
Total assets ............... $39,495,543 $44,556,965
----------- -----------
Liabilities ................ $34,576,964 $34,885,357
Members' equity ............ 4,918,579 9,671,608
----------- -----------
Total liabilities and equity $39,495,543 $44,556,965
----------- -----------
Statement of Operations Information
For the Period August
For the year ended December 19, 1998 to December
31, 1999 31, 1998
----------- -----------
Revenue .......... $ 7,975 $ --
Operating expenses 3,547,208 2,085,911
----------- -----------
Net loss ......... $(3,539,233) $(2,085,911)
----------- -----------
4. Long-Term Debt
Following is a summary of long-term debt at December 31, 1999:
Senior secured non-recourse notes payable $ 4,196,455
Less - Current maturity (716,995)
-----------------
Total long-term debt $3,479,460
-----------------
The senior secured non-recourse notes are due in monthly installments of
$90,738, including interest at 9.6%. Final payment is due on October 15, 2004.
The notes also provide for additional interest equal to 5% of the annual net
cash flow of the Providence Project, as defined. No additional interest was due
for the years ended December 31, 1999, 1998 and 1997. The notes are secured by a
leasehold mortgage on Providence Power's landfill lease agreements and
substantially all of the assets of Providence Power. In addition to the required
monthly payments, mandatory prepayments may be required if certain events occur.
The loan agreement also provides for a cash funded debt service reserve and
maintenance reserve. At December 31, 1999 and 1998, the cash balance in these
reserve accounts was $666,346 and $637,108, respectively. Additions and
reductions to these reserve accounts are defined in the loan agreement. As of
January 31, 1997, Providence Power's obligations to maintain a cash balance in
the maintenance reserve account terminated and the cash balance in the reserve
account ($394,070) was released to Providence Power. The loan agreement contains
various covenants, including the maintenance of a specified debt service ratio.
Scheduled repayments of long-term debt principal for the next five years are as
follows:
Year Ended
December 31, Repayment
2000 $ 716,995
2001 788,937
2002 868,098
2003 955,202
2004 867,223
During the fourth quarter of 1997, the Trust and its principal bank executed a
revolving line of credit agreement, whereby the bank will provide a three year
committed line of credit facility of $1,150,000 for borrowings or letters of
credit. Outstanding borrowings bear interest at the bank's prime rate or, at the
Trust's choice, at LIBOR plus 2.5%. The credit agreement will require the Trust
to maintain a ratio of total debt to tangible net worth of no more than 1 to 1
and a minimum debt service coverage ratio of 2 to 1. The Maine Hydro projects
have an outstanding standby letter of credit totaling $99,250 which is covered
by the line of credit facility. At December 31, 1999 and 1998, there were no
borrowings outstanding under the credit facility. In January 2000, the Trust
borrowed $500,000 under the line of credit facility.
5. Fair Value of Financial Instruments
At December 31, 1999 and 1998, the carrying value of the Trust's cash, accounts
receivable, debt service reserve fund and accounts payable approximates their
fair value. The fair value of the long-term debt, calculated using current rates
for loans with similar maturities, also approximates its carrying value.
6. Electric Power Sales Contracts
Providence Power is committed to sell all of the electricity it produces to New
England Power Corporation ("NEP") for prices as specified in the Power Purchase
Agreement. The prices are adjusted annually for changes in the Consumer Price
Index, as defined. The NEP agreement expires in the year 2020 and can be
terminated by either party under certain conditions in 2010. At the time of the
acquisition of the Providence Project, Providence Power was required under the
NEP agreement to maintain in an escrow account cash to secure payment to NEP in
the event of default. At April 16, 1996, the required escrow balance amounted to
$1,065,989. In October 1996, the required escrow balance decreased to zero and
the cash held in escrow was released to Providence Power. For the years ended
December 31, 1999, 1998 and 1997, sales revenue under the NEP Power Purchase
Agreement amounted to $6,751,802, $6,617,549 and $6,458,648, respectively.
7. Landfill Lease and Sublease
Providence Power leases the Central Landfill, located in Johnston, Rhode Island
from Rhode Island Solid Waste Management Corporation ("RISWMC"). The lease
expires in 2020 and can be extended for an additional 10 years. This operating
lease requires Providence Power to pay a royalty equal to 15% of net revenues,
as defined, for the first 15 years of the lease. For subsequent years, the
royalty is 15% of net revenues for each month in which the average daily
kilowatt hour production is less than 180,000 and 18% of net revenues for each
month in which the average daily kilowatt hour production exceeds 180,000. For
the years ended December 31, 1999, 1998 and 1997 royalty expense relating to the
RISWMC lease amounted to $996,399, 986,224 and 951,767, respectively.
Providence Power subleases the Central Landfill to Central Gas Limited
Partnership ("Gasco"). Gasco operates and maintains the landfill gas collection
system and supplies landfill gas to the Providence Project. The sublease
agreement is effective through December 31, 2010 and provides for the following:
Sublease Income - Gasco is to pay Providence Power an annual amount equal to the
product of $30,000 times the assumed output capacity of each engine generator
set in megawatts installed and operating by the joint venture. Income recorded
under the sublease amounted to $369,000 for the years ended December 31, 1999,
1998 and 1997.
Fuel Expense - Providence Power agreed to purchase all the landfill gas produced
by Gasco and pay on a monthly basis $.01183 per kilowatt hour for the first
4,000,000 kilowatt hours, $.005 per kilowatt hour for kilowatt hours in excess
of 4,000,000 and $.05 per million BTU's of excess landfill gas. The price is
adjusted annually for changes in the Consumer Price Index, as defined. Purchases
from Gasco for the years ended December 31, 1999, 1998 and 1997 amounted to
$907,950, $900,529 and $863,536, respectively.
8. Transactions With Managing Shareholder and Affiliates
The Trust pays to the managing shareholder a distribution and offering fee up to
6% of each capital contribution made to the Trust. This fee is intended to cover
legal, accounting, consulting, filing, printing, distribution, selling and
closing costs for the offering of the Trust. These fees were recorded as a
reduction in the shareholders' capital contribution.
The Trust also pays to the managing shareholder an investment fee up to 2% of
each capital contribution made to the Trust. The fee is payable to the managing
shareholder for its services in investigating and evaluating investment
opportunities and effecting transactions for investing the capital of the Trust.
The Trust entered into a management agreement with the managing shareholder
under which the managing shareholder renders certain management, administrative
and advisory services and provides office space and other facilities to the
Trust. As compensation to the managing shareholder, the Trust pays the managing
shareholder an annual management fee equal to 3% of the net asset value of the
Trust payable monthly upon the closing of the Trust. For the years ended
December 31, 1999, 1998 and 1997, the Trust paid an annual management fees to
the managing shareholder of $467,268, $1,050,700 and $1,154,758, respectively.
In 1999, the managing shareholder waived 50% of the management fees to which it
was entitled.
The Trust reimburses the managing shareholder and affiliates for expenses and
fees of unaffiliated persons engaged by the managing shareholder for fund
business. The managing shareholder or affiliates originally paid all project due
diligence costs, accounting and legal fees and other expenses shown in the
statement of operation and were reimbursed by the Trust.
Under the Declaration of Trust, the managing shareholder is entitled to receive
each year 1% of all distributions made by the Trust (other than those derived
from the disposition of Trust property) until the shareholders have been
distributed a cumulative amount equal to 14% per annum of their equity
contribution. Thereafter, the managing shareholder is entitled to receive 20% of
the distributions for the remainder of the year. The managing shareholder is
entitled to receive 1% of the proceeds from dispositions of Trust properties
until the shareholders have received cumulative distributions equal to their
original investment ("Payout"). After Payout, the managing shareholder is
entitled to receive 20% of all remaining distributions of the Trust.
Income is allocated to the managing shareholder until the cumulative profits
equal cumulative distributions to the managing shareholder. Then, income is
allocated to the investors, first among holders of Preferred Participation
Rights until such allocations equal distributions from those Preferred
Participation Rights, and then among Investors in proportion to their ownership
of investor shares. If the Trust has net losses for a fiscal period, the losses
are allocated 99% to the Investors and 1% to the managing shareholder.
Where permitted, in the event the managing shareholder or an affiliate performs
brokering services in respect of an investment acquisition or disposition
opportunity for the Trust, the managing shareholder or such affiliate may charge
the Trust a brokerage fee. Such fee may not exceed 2% of the gross proceeds of
any such acquisition or disposition. No such fees have been incurred through
December 31, 1999.
The corporate trustee of the Trust, Ridgewood Energy Holding Corporation, an
affiliate of the managing shareholder through common ownership, received no
compensation from the Fund.
Amounts due to and from affiliates are non-interest bearing and are usually
settled within thirty days. Such amounts arise from the delay between when
expenses are paid by the Trust or affiliates and when reimbursement occurs.
The managing shareholder purchased one investor share of the Trust for $83,000
in 1995. Through the offering period of the Trust, commissions and placement
fees of $172,674 were earned by Ridgewood Securities Corporation, an affiliate
of the managing shareholder.
Under an Operating Agreement with the Trust, Ridgewood Power Management LLC
(formerly Ridgewood Power Management Corporation, "Ridgewood Management"), an
entity related to the managing shareholder through common ownership, provides
management, purchasing, engineering, planning and administrative services to the
Trust's power generation projects. Ridgewood Management charges the projects at
its cost for these services and for the allocable amount of certain overhead
items. Allocations of costs are on the basis of identifiable direct costs, time
records or in proportion to amounts invested in projects managed by Ridgewood
Management. During the years ended December 31, 1999, 1998 and 1997, Ridgewood
Management charged Providence Power $404,055, $401,290 and $467,881,
respectively. During the year ended December 31, 1999 and 1998, Ridgewood
Management charged Pump Services $69,262 and $23,466, respectively. During the
year ended December 31, 1999, Ridgewood Management charged the Maine Biomass
projects $197,825. During the periods ended December 31, 1999 1998 and 1997,
Ridgewood Management did not charge any amounts to the Maine Hydro projects or
Santee River Rubber project.
9. Preferred Participation Rights
Preferred Participation Rights were given to each shareholder whose subscription
was fully completed and paid for and accepted prior to September 30, 1995. Each
Preferred Participation Right entitled the holder to an aggregate distribution
priority of $1,000. The number of Preferred Participation Rights earned per
investor share was equal to the number of whole or partial months from the date
of the acceptance of the subscription to December 31, 1995. A total of 972.733
Preferred Participation Rights were issued.
During 1996, cash distributions were first allocated 99% to the holders of
Preferred Participation Rights and 1% to the managing shareholder until
shareholders received distributions equal to $1,000 for each Right earned.
10. Management Share
The Trust granted the managing shareholder a single Management Share
representing the managing shareholder's management rights and rights to
distributions of cash flow.
11. Administrative Proceeding at the Providence Project
In September 1998, the Region I office of the U.S. Environmental Protection
Agency ("EPA") filed an administrative proceeding against Providence Power
seeking to recover civil penalties of up to $190,000 for alleged violations of
operational recordkeeping and training requirements at the Providence Project.
In June 1999, Providence Power settled the administrative proceeding for
approximately $86,000 which is recorded in cost of sales in the consolidated
statement of operations.
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Financial Statements
December 31, 1999, 1998 and 1997
<PAGE>
Report of Independent Accountants
To the Partners of
Ridgewood Maine Hydro Partners, L.P.:
In our opinion, the accompanying balance sheets and the related statements of
operations, changes in partners' equity and of cash flows present fairly, in all
material respects, the financial position of Ridgewood Maine Hydro Partners,
L.P. (the "Partnership") at December 31, 1999 and 1998, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States. These financial statements are the responsibility of the
Partnership's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States, 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.
PricewaterhouseCoopers LLP
New York, NY
March 24, 2000
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Balance Sheet
- ------------------------------------------------------------------------------
December 31,
---------------------------
1999 1998
------------ -----------
Assets:
Cash and cash equivalents .................... $ 408,835 $ 607,119
Accounts receivable, trade ................... 1,021,480 574,022
Due from affiliates .......................... -- 87,369
Prepaid and other current assets ............. 142,862 77,567
------------ ------------
Total current assets .................... 1,573,177 1,346,077
Property, plant and equipment ................ 1,349,024 1,089,248
Accumulated depreciation ..................... (78,628) (31,356)
------------ ------------
Property, plant and equipment, net ...... 1,270,396 1,057,892
------------ ------------
Electric power sales contracts ............... 13,311,374 13,311,374
Accumulated amortization ..................... (3,206,201) (2,145,905)
------------ ------------
Electric power sales contracts, net ..... 10,105,173 11,165,469
------------ ------------
Total assets ............................ $ 12,948,746 $ 13,569,438
------------ ------------
Liabilities and Partners' Equity:
Liabilities:
Accounts payable and accrued expenses ........ $ 38,285 $ 197,799
Due to affiliates ............................ 799,905 --
Current portion of long-term lease obligations 783,547 240,644
------------ ------------
Total current liabilities ............... 1,621,737 438,443
Non-current portion of long-term
lease obligations .......................... -- 696,418
------------ ------------
Commitments and contingencies
Partners' equity:
General partner .............................. 103,548 114,624
Limited partners ............................. 11,223,461 12,319,953
------------ ------------
Total partners' equity .................. 11,327,009 12,434,577
------------ ------------
Total liabilities and partners' equity .. $ 12,948,746 $ 13,569,438
------------ ------------
See accompanying notes to the financial statements.
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Statement of Operations
- -------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
Net sales ...................... $ 4,756,189 $ 4,511,361 $ 4,113,065
----------- ----------- -----------
Operating expenses:
Depreciation and amortization 1,107,568 1,089,969 1,062,838
Labor ....................... 565,015 592,812 549,289
Insurance ................... 177,333 194,458 246,665
Property taxes .............. 252,611 267,046 258,953
Contract management ......... 323,003 429,714 429,430
Other expenses .............. 576,715 643,847 405,414
----------- ----------- -----------
3,002,245 3,217,846 2,952,589
----------- ----------- -----------
Income from operations ......... 1,753,944 1,293,515 1,160,476
----------- ----------- -----------
Other income (expense):
Interest income ................ 42,852 153,983 30,812
Interest expense ............... (112,885) (131,519) (147,868)
Other income ................... 15,000 -- --
----------- ----------- -----------
Other income (expense), net (55,033) 22,464 (117,056)
----------- ----------- -----------
Net income ..................... $ 1,698,911 $ 1,315,979 $ 1,043,420
----------- ----------- -----------
See accompanying notes to the financial statements.
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Statement of Changes in Partners' Equity
For the Years Ended December 31, 1999, 1998 and 1997
- --------------------------------------------------------------------------------
Limited General
Partners Partner Total
------------ ------------ ------------
Partners' equity, January
1, 1997 ................. $ 13,692,976 $ 133,866 $ 13,826,842
Additional contributions . 531,906 -- 531,906
Cash distributions ....... (1,992,391) (20,125) (2,012,516)
Net income for the year .. 1,032,986 10,434 1,043,420
------------ ------------ ------------
Partners' equity, December
31, 1997 ................ 13,265,477 124,175 13,389,652
Cash distributions ....... (2,248,343) (22,711) (2,271,054)
Net income for the year .. 1,302,819 13,160 1,315,979
------------ ------------ ------------
Partners' equity, December
31, 1998 ................ 12,319,953 114,624 12,434,577
Cash distributions ....... (2,778,414) (28,065) (2,806,479)
Net income for the year .. 1,681,922 16,989 1,698,911
------------ ------------ ------------
Partners' equity, December
31, 1999 ................ $ 11,223,461 $ 103,548 $ 11,327,009
------------ ------------ ------------
See accompanying notes to the financial statements.
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Statement of Cash Flows
- --------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
Cash flows from operating
activities:
Net income ........................ $ 1,698,911 $ 1,315,979 $ 1,043,420
----------- ----------- -----------
Adjustments to reconcile net income
to net cash flows from operating
activities:
Depreciation and amortization .... 1,107,568 1,089,969 1,062,838
Changes in assets and liabilities:
(Increase) decrease in accounts
receivable ..................... (447,458) (105,371) 529,205
(Increase) decrease in prepaid
and other current assets ....... (65,295) 11,832 (41,716)
Decrease (increase) in due
to/from affiliates, net ........ 887,274 16,281 (303,259)
(Decrease) increase in accounts
payable and accrued expenses ... (159,514) 40,782 (505,122)
----------- ----------- -----------
Total adjustments ................. 1,322,575 1,053,493 741,946
----------- ----------- -----------
Net cash provided by operating
activities ....................... 3,021,486 2,369,472 1,785,366
----------- ----------- -----------
Cash flows from investing
activities:
Payments to purchase Maine
Hydro Projects ................... -- -- (323,217)
Capital expenditures .............. (259,776) (752,613) (336,635)
----------- ----------- -----------
Net cash used in investing
activities ....................... (259,776) (752,613) (659,852)
----------- ----------- -----------
Cash flows from financing
activities:
Cash contributed by partners ...... -- -- 531,906
Cash distributions to partners .... (2,806,479) (2,271,054) (2,012,516)
Return of deposits ............... -- 800,000 --
Payments to reduce long-term
lease obligations ................ (153,515) (134,894) (118,532)
----------- ----------- -----------
Net cash used in financing
activities ....................... (2,959,994) (1,605,948) (1,599,142)
----------- ----------- -----------
Net (decrease) increase in cash
and cash equivalents ............. (198,284) 10,911 (473,628)
Cash and cash equivalents,
beginning of year ................ 607,119 596,208 1,069,836
----------- ----------- -----------
Cash and cash equivalents, end
of year .......................... $ 408,835 $ 607,119 $ 596,208
----------- ----------- -----------
See accompanying notes to the financial statements.
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Notes to Financial Statements
- --------------------------------------------------------------------------------
1. Organization and Business Activity
On September 5, 1996, Ridgewood Maine Hydro Partners, L.P. was formed as a
Delaware limited partnership (the "Partnership"). Ridgewood Maine Hydro
Corporation, a Delaware Corporation ("RMHCorp"), is the sole general partner of
the Partnership and is owned equally by Ridgewood Electric Power Trust IV
("Trust IV") and Ridgewood Electric Power Trust V ("Trust V"), both Delaware
business trusts (collectively, the "Trusts"). The Trusts are equal limited
partners in the Partnership.
On December 23, 1996, in a merger transaction, the Partnership acquired 14
hydroelectric projects located in Maine (the "Maine Hydro Projects") from a
subsidiary of Consolidated Hydro, Inc. The assets acquired include a total of
11.3 megawatts of electrical generating capacity. The electricity generated is
sold to Central Maine Power Company and Bangor Hydro Company under long-term
contracts.
2. Summary of Significant Accounting Policies
Use of 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 the estimates.
Cash and cash equivalents
The Partnership considers all highly liquid investments with maturities when
purchased of three months or less as cash and cash equivalents.
Revenue recognition
Power generation revenue is recognized based on power delivered at rates
stipulated in the power sales contracts. Interest income is recorded when
earned.
Plant and equipment
Machinery and equipment, consisting principally of electrical generating
equipment, is stated at cost. Renewals and betterments that increase the useful
lives of the assets are capitalized. Repair and maintenance expenditures that
increase the efficiency of the assets are expensed as incurred.
Depreciation is recorded using the straight-line method over the useful lives of
the assets, which vary from 3 to 20 years. During the year ended December 31,
1999, 1998 and 1997, the Partnership recorded depreciation expense of $47,272,
$29,673 and $1,683, respectively.
Intangible asset
A portion of the purchase price of the Maine Hydro Projects was assigned to the
Electric Power Sales Contracts and is being amortized over the duration of the
contract (11 to 21 years) on a straight-line basis. Management periodically
reviews intangibles for potential impairment. During the periods ended December
31, 1999, 1998 and 1997, the Partnership recorded amortization expense of
$1,060,296, $1,060,296 and $1,061,155, respectively.
Income taxes
No provision is made for income taxes in the accompanying financial statements
as the income or loss of the Partnership is passed through and included in the
tax returns of the individual partners.
Reclassification
Certain items in previously issued financial statements have been reclassified
for comparative purposes.
3. Obligation Under Capital Lease
The Partnership assumed a hydroelectric facility leased pursuant to a long-term
lease agreement dated July 16, 1979, and as amended (the "Agreement"). Upon
proper notice, the Partnership has the right to purchase all the equipment
covered in the Agreement at Fair Market Value (as defined) or elect to extend
the terms of the Agreement for up to three five-year periods at a rental equal
to Fair Rental Value (as defined). In addition, the Partnership also has the
right to terminate the Agreement and purchase the hydroelectric facility upon
proper notice and payment of a scheduled close-out amount, which reduces to
$750,000 at April 30, 2000. This lease is accounted for as a capital lease, and
accordingly, the estimated lease obligation of $783,547 has been recorded in the
accompanying balance sheet.
4. Lease Commitments
The Partnership leases the sites of two of its hydroelectric projects under
operating leases expiring in June 2078. Total monthly payments in 1999 were the
greater of $1,236 or a percentage of the revenue from the hydroelectric project.
At December 31, 1999, the future minimum rental payments required under these
leases are as follows:
2000 $ 14,832
2001 14,832
2002 14,832
2003 14,832
2004 14,832
Thereafter 1,090,152
------------------
$ 1,164,312
------------------
5. Power Generation Contracts
The Partnership operates facilities which qualify as small power production
facilities under the Public Utility Regulatory Policies Act ("PURPA"). PURPA
requires that each electric utility company, operating at the location of a
small power production facility, as defined, purchase the electricity generated
by such facility at a specified or negotiated price. The Partnership sells
substantially all of its electrical output to two public utility companies,
Central Maine Power Company ("CMP") and Bangor Hydro-Electric Company ("BHC"),
pursuant to long-term power purchase agreements. Eleven of the twelve power
purchase agreements with CMP expire in December 2008 and are renewable for an
additional five year period. The twelfth power purchase agreement with CMP
expires in December 2007 with CMP having the option to extend the contract three
more five-year periods. The two power purchase agreements with BHC expire
December 2014 and February 2017. The Partnership is required to maintain a
standby letter of credit totaling $99,250 under the long-term power purchase
agreement.
6. Fair Value of Financial Instruments
At December 31, 1999 and 1998, the carrying value of the Partnership's cash,
accounts receivable and accounts payable approximates their fair value. The fair
value of the long-term capital lease obligations, calculated using current rates
for loans with similar maturities, also approximates its carrying value.
7. Management Agreement
The Maine Hydro Projects are operated by a subsidiary of CHI Energy, Inc.
(formerly Consolidated Hydro, Inc.), under an Operation, Maintenance and
Administrative Agreement. The annual operator's fee is $326,142 adjusted for
inflation, plus an annual incentive fee equal to 50% of the net cash flow in
excess of a target amount. The maximum incentive fee payable in a year is
$112,500. The Partnership recorded $323,003, $429,714 and $429,430 of expense
under this arrangement during the periods ended December 31, 1999, 1998 and
1997, respectively. The agreement has a five-year term expiring on June 30, 2001
and can be renewed for two additional five-year terms by mutual consent.
<PAGE>
Indeck Maine Energy, L.L.C.
Financial Statements
December 31, 1999, 1998 and 1997
<PAGE>
Report of Independent Accountants
To the Members of
Indeck Maine Energy, L.L.C.:
In our opinion, the accompanying balance sheets and the related statements of
operations, changes in members' (deficit) equity and of cash flows present
fairly, in all material respects, the financial position of Indeck Maine
Energy, L.L.C. (the "Company") at December 31, 1999 and 1998, and the results
of its operations and its cash flows for each of the two years in the period
ended December 31, 1999 and the period April 1, 1997 (inception) through
December 31, 1997, in conformity with accounting principles generally
accepted in the United States. 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 standards
generally accepted in the United States, 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.
As discussed in Note 4 to the financial statements, the Company has
temporarily suspended operations and is dependent on the continuing financial
support of the Members.
PricewaterhouseCoopers LLP
New York, NY
March 24, 2000
<PAGE>
Indeck Maine Energy, L.L.C.
Balance Sheet
- --------------------------------------------------------------------------------
December 31,
--------------------------
1999 1998
----------- -----------
Assets:
Cash and cash equivalents ................ $ 656,442 $ 93,748
Accounts receivable ...................... 274,362 185,808
Inventories .............................. 145,198 278,704
Prepaid expenses ......................... 27,264 109,968
----------- -----------
Total current assets .................. 1,103,266 668,228
----------- -----------
Plant and equipment:
Land .................................. 158,000 158,000
Power generation facilities ........... 3,203,217 3,203,217
Equipment and other ................... 56,646 56,646
----------- -----------
3,417,863 3,417,863
Accumulated depreciation .............. (435,869) (264,380)
----------- -----------
2,981,994 3,153,483
----------- -----------
Intangible assets ........................ 206,577 206,577
Accumulated amortization ................. (33,758) (20,476)
----------- -----------
172,819 186,101
----------- -----------
Total assets ........................ $ 4,258,079 $ 4,007,812
----------- -----------
Liabilities and Members' (Deficit) Equity:
Liabilities:
Accounts payable and accrued expenses .... $ 426,001 $ 327,062
Due to affiliates ........................ 267,989 --
Management fee payable ................... 100,000 125,000
Notes payable to Members ................. 3,601,000 1,500,000
----------- -----------
Total current liabilities ........... 4,394,990 1,952,062
Commitments and contingencies
Total Members' (deficit) equity .......... (136,911) 2,055,750
----------- -----------
Total liabilities and members'
(deficit) equity ................... $ 4,258,079 $ 4,007,812
----------- -----------
See accompanying notes to the financial statement
<PAGE>
Indeck Maine Energy, L.L.C.
Statement of Operations
- --------------------------------------------------------------------------------
For the
period from
inception
For the For the April 1,
year ended year ended 1997) to
December December December
31, 1999 31, 1998 31, 1997
----------- ----------- -----------
Revenues .................. $ 1,391,039 $ 1,430,296 $ 2,991,793
Operating expenses ........ 3,478,842 2,800,185 4,399,670
----------- ----------- -----------
Loss from operations ... (2,087,803) (1,369,889) (1,407,877)
Other (expense) income, net (104,858) (47,711) 23,212
----------- ----------- -----------
Net loss ............... $(2,192,661) $(1,417,600) $(1,384,665)
----------- ----------- -----------
See accompanying notes to the financial statements.
<PAGE>
Indeck Maine Energy, L.L.C.
Statement of Changes in Members' (Deficit) Equity
For the Years Ended December 31, 1999 and 1998 and the period from inception
(April 1, 1997) to December 31, 1997
- --------------------------------------------------------------------------------
Indeck Energy Ridgewood
Services, Inc. Maine, LLC Total
----------- ----------- -----------
Initial contributions ............ $ 1,000 $ 4,857,015 $ 4,858,015
Net loss ......................... -- (1,384,665) (1,384,665)
----------- ----------- -----------
Members' equity, December 31, 1997 1,000 3,472,350 3,473,350
Net loss ......................... -- (1,417,600) (1,417,600)
----------- ----------- -----------
Members' equity, December 31, 1998 1,000 2,054,750 2,055,750
Net loss ......................... (1,000) (2,191,661) (2,192,661)
----------- ----------- -----------
Members' equity (deficit),
December 31, 1999 ............... $ -- $ (136,911) $ (136,911)
----------- ----------- -----------
See accompanying notes to the financial statements.
<PAGE>
Indeck Maine Energy, L.L.C.
Statement of Cash Flows
- --------------------------------------------------------------------------------
For the
period from
inception
For the For the April 1,
year ended year ended 1997) to
December December December
31, 1999 31, 1998 31, 1997
----------- ----------- -----------
Cash flows from operating
activities
Net loss ...................... $(2,192,661) $(1,417,600) $(1,384,665)
----------- ----------- -----------
Adjustments to reconcile net
loss to net cash flows
used in operating activities
Depreciation and amortization 184,771 184,771 100,085
Changes in assets and
liabilities:
(Increase) decrease in
accounts receivable ......... (88,554) 205,704 (391,512)
Decrease (increase) in
inventories ................. 133,506 71,955 (350,659)
Decrease (increase) in
prepaid expenses ............ 82,704 (91,424) (18,544)
Increase (decrease) in
accounts payable and accrued
expenses .................... 98,939 (560,621) 887,683
Increase in due to affiliates 267,989 -- --
(Decrease) increase in
management fee payable ...... (25,000) 100,000 25,000
----------- ----------- -----------
Total adjustments ............ 654,355 (89,615) 252,053
----------- ----------- -----------
Net cash used in operating
activities .................... (1,538,306) (1,507,215) (1,132,612)
----------- ----------- -----------
Cash flows from investing
activities
Capital expenditures ........... -- -- (604,757)
Acquisition of intangible assets -- -- (19,683)
----------- ----------- -----------
Net cash used in investing
activities .................... -- -- (624,440)
----------- ----------- -----------
Cash flows from financing
activities
Capital contributions .......... -- -- 4,858,015
Payment of note payable -
affiliate ..................... -- -- (3,300,000)
Issuance of notes payable ...... 2,101,000 1,500,000 300,000
----------- ----------- -----------
Net cash provided by financing
activities .................... 2,101,000 1,500,000 1,858,015
----------- ----------- -----------
Net increase (decrease) in cash
and cash equivalents .......... 562,694 (7,215) 100,963
Cash and cash equivalents,
beginning of period ........... 93,748 100,963 --
----------- ----------- -----------
Cash and cash equivalents,
end of period ................. $ 656,442 $ 93,748 $ 100,963
----------- ----------- -----------
Non-cash activities: On April 1, 1997, land, power generation facilities,
equipment and intangible assets were acquired from Indeck Power Overseas
Limited, a related entity, for $3,000,000 through the issuance of a note
payable.
See accompanying notes to the financial statements.
<PAGE>
Indeck Maine Energy, L.L.C.
Notes to Financial Statements
- --------------------------------------------------------------------------------
1. Description of Business
Indeck Maine Energy, L.L.C. (the "Company") is a limited liability company
formed on April 1, 1997 for the purpose of acquiring, operating and managing two
wood-fired electric generation facilities (the "Facilities"). The Facilities
commenced operations on June 10, 1997. On June 11, 1997, Ridgewood Maine, LLC
("Ridgewood") contributed $4,857,015 for a membership interest.
a. Ridgewood's Priority Return from Operations: Ridgewood's Priority Return
From Operations is an amount equal to 18% per annum of $14 million,
increased by the amount of any additional contribution made by Ridgewood
and reduced by the amount of distributions to Ridgewood of Net Cash Flow
From Capital Events, as defined.
b. Allocation of Profits and Losses: In accordance with the Operating
Agreement, profits and losses, as defined, are allocated as follows:
First, profits shall be allocated to each Member, other than Ridgewood, until
the cumulative amount of profits allocated is equal to the amount of
distributions made or to be made to each Member pursuant to the distributions
provisions of the Operating Agreement.
Second, all remaining profits and losses shall be allocated to Ridgewood. Also,
all depreciation shall be allocated to Ridgewood.
Losses and depreciation allocated to Members in accordance with the Operating
Agreement may not exceed the amount that would cause such members to have an
Adjusted Capital account Deficit, as defined, at the end of such year. All
losses and depreciation in excess of this limitation shall be allocated to the
remaining Members who will not be subject to this limitation, in proportion to
and to the extent of their positive Capital Account Balances, as defined.
Also, if in any fiscal year a Member unexpectedly receives an adjustment,
allocation or distribution as described in the Operating Agreement, and such
allocation or distribution causes or increases an Adjusted Capital Account
Deficit for such fiscal year, such Member shall be allocated items of income and
gain in an amount and manner sufficient to eliminate such Adjusted Capital
Account Deficit as quickly as possible.
c. Distributions of Net Cash Flows From Operations: For each Fiscal year, the
Company shall distribute Net Cash Flow From Operations, as defined, to the
Members as follows:
First, the Company shall distribute to Ridgewood 100% of Net Cash Flow From
Operations until Ridgewood has received the full amount of any unpaid portion of
Ridgewood's Priority Return From Operations, as defined, for any preceding
fiscal year,
Second, the Company shall distribute to Ridgewood 100% of Net Cash Flow From
Operations until Ridgewood has received Ridgewood's Priority Return From
Operations for the current fiscal year.
Third, the Company shall distribute 100% of Net Cash Flow From Operations to the
Members, other than Ridgewood, in accordance with the respective interests of
such Members until such Members have collectively received an amount equal to
the amount distributed to Ridgewood during the current fiscal year.
Fourth, the Company shall thereafter distribute any remaining balance of Net
Cash Flow From Operations 25% to Ridgewood and 75% to the remaining Members, in
accordance with the respective interest of such Members, until such time as
Ridgewood has received aggregate distributions equal to Ridgewood's Initial
Capital Contribution, as defined. At such time, the distribution percentages
shall be amended to 50% Ridgewood and 50% to the remaining Members.
d. Distributions of Net Cash Flow From Capital Events: The Company shall
distribute Net Cash Flow From Capital Events, as defined, 50% to Ridgewood
and 50% to the remaining Members, in accordance with the respective
interests of such Members.
2. Summary of Significant Accounting Policies
Use of 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 the estimates.
Cash and cash equivalents
The Company considers all highly liquid investments with maturities when
purchased of three months or less as cash and cash equivalents.
Revenue recognition
Revenue is recognized when the power is transmitted or the service is provided.
Interest income is recorded when earned.
Inventories
Inventories, consisting of wood and propane, are stated at cost, with cost being
determined on the first-in, first-out method.
Plant and equipment
Machinery and equipment, consisting principally of electrical generating
equipment, is stated at cost. Renewals and betterments that increase the useful
lives of the assets are capitalized. Repair and maintenance expenditures are
expensed as incurred.
Depreciation is recorded using the straight-line method over the estimated
useful life of the assets, ranging from 5 to 20 years. During the years ended
December 31, 1999 and 1998 and the period from inception (April 1, 1997) to
December 31, 1997, the Company recorded depreciation expense of $171,489,
$171,489 and $92,891, respectively.
Intangible assets
Intangible assets are amortized over 20 years on a straight-line basis. During
the years ended December 31, 1999 and 1998 and the period from inception (April
1, 1997) to December 31, 1997, the Company recorded amortization expense of
$13,282, $13,282 and $7,194.
Significant Customers
During 1999, the Company's three largest customers accounted for 41%, 22% and
19% of total revenues. Other customers individually accounted for less than 10%
of total revenues.
Income taxes
No provision is made for income taxes in the accompanying financial statements
as the income or loss of the Company is passed through and included in the tax
returns of the partners.
3. Notes Payable
Notes payable consist of the following at December 31, 1999:
Note payable to Indeck Energy Services,
Inc. (a Member), due on demand with
interest at 5% ........................ $1,800,500
Note payable to Ridgewood Maine, LLC
(a Member), due on demand with interest
at 5% ................................. 1,800,500
----------
$3,601,000
----------
4. Operating Status
Both projects have temporarily suspended operations; one in December 1997 and
the other in January 1998. It is management's intent not to operate these
facilities, except during periods of peak demand, until profitable power sales
contracts can be negotiated. Management is currently negotiating contracts with
various utility companies and expects to commence operations in late 2000 or
2001. Based on forecasts related to these contracts, management believes that
the Company will be able to recover the carrying value of its long-lived assets
and meet its financial obligations. The Members intend to continue providing the
necessary financial support to the Company for the foreseeable future and to not
demand payment, within the next twelve months, of the notes payable discussed in
Note 3.
5. Related Party transactions
The Company is required to pay certain Members a fee for management services of
$50,000 in 1997 and $100,000 per year thereafter. Additional management fees of
up to $200,000 per year may be payable contingent upon achieving Ridgewood's
Priority Return from Operations, as defined. No contingent management fee has
been accrued as of December 31, 1999 or 1998.
The Company incurred expenses of approximately $770,000 and $1,189,000 for the
year ended December 31, 1998 and for the period from inception (April 1, 1997)
through December 31, 1997, respectively, from Indeck Operations, Inc. and Indeck
Energy Services, Inc., companies affiliated through common ownership, for the
operation, maintenance and administration of the Company's facilities. At
December 31, 1998, approximately $57,000 of these charges were in accounts
payable.
Under an Operating Agreement with the Trusts, Ridgewood Power Management LLC
(formerly Ridgewood Power Management Corporation, "Ridgewood Management"), an
entity related to the managing shareholder of the Trusts through common
ownership, provides management, purchasing, engineering, planning and
administrative services to the Company. Ridgewood Management charges the Company
at its cost for these services and for the allocable amount of certain overhead
items. Allocations of costs are on the basis of identifiable direct costs, time
records or in proportion to amounts invested in projects managed by Ridgewood
Management. During the year ended December 31, 1999, Ridgewood Management
charged the Company $197,825 for overhead items allocated based on time records
and in proportion to the amount invested in projects managed. Ridgewood
Management also charged the Company for all of the remaining direct operating
and non-operating expenses incurred during the periods
6. Dispute with ISO
From June through December 1999, the Facilities periodically operated on
dispatch from ISO-New England, Inc. (the "ISO") and also submitted offers to the
ISO to run at high prices during power emergencies. The Facilities have claimed
the ISO owes them approximately $14 million for the electricity products they
provided in those periods and the ISO has claimed that no material revenues at
all are due to the projects. The Company has not recorded any of the disputed
revenues in the financial statements and it is too early to estimate the outcome
of the dispute.
Exhibit 21 - Subsidiaries of the Registrant
Subsidiary corporations serving as general partners or managers of limited
liability entities are listed with those entities.
Name of Subsidiary Type of entity Jurisdiction
of organization
Ridgewood/Providence Power Partners, L.P. limited partnership Delaware
Ridgewood/Providence Corporation corporation Delaware
Ridgewood/Maine Hydro Partners, L.P. limited partnership Delaware*
Ridgewood Maine Hydro Corporation corporation Delaware*
Ridgewood Pump Services Partners IV, L.P. limited partnership Delaware
Ridgewood Pump Services IV Corporation corporation Delaware
Ridgewood Maine, L.L.C. limited liability co. Delaware*
*50% owned by Registrant and 50% owned by Ridgewood Power V.
EXHIBIT 24 -- POWERS OF ATTORNEY
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, John Belknap,
appoints Robert E. Swanson and Martin V. Quinn, and each of them, as his true
and lawful attorneys-in-fact with full power to act and do all things necessary,
advisable or appropriate, in their discretion, to execute on his behalf as an
Independent Trustee of Ridgewood Electric Power Trust I and of Ridgewood
Electric Power Trust IV, the Annual Reports on Form 10-K for the year ended
December 31, 1999 for each of the above-named trusts, and all amendments or
documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 18th day of March, 2000, at Fort Lauderdale, Florida.
/s/John Belknap
John Belknap
<PAGE>
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, Richard
Propper, M.D., appoints Robert E. Swanson and Martin V. Quinn, and each of them,
as his true and lawful attorneys-in-fact with full power to act and do all
things necessary, advisable or appropriate, in their discretion, to execute on
his behalf as an Independent Trustee of Ridgewood Electric Power Trust I and of
Ridgewood Electric Power Trust IV, the Annual Reports on Form 10-K for the year
ended December 31, 1999 for each of the above-named trusts, and all amendments
or documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 18th day of March, 2000, at Fort Lauderdale, Florida.
/s/Richard Propper, M.D.
Richard Propper, M.D.
<PAGE>
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, Seymour Robin,
appoints Robert E. Swanson and Martin V. Quinn, and each of them, as his true
and lawful attorneys-in-fact with full power to act and do all things necessary,
advisable or appropriate, in their discretion, to execute on his behalf as an
Independent Trustee of Ridgewood Electric Power Trust I and of Ridgewood
Electric Power Trust IV, the Annual Reports on Form 10-K for the year ended
December 31, 1999 for each of the above-named trusts, and all amendments or
documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 18th day of March, 2000, at Fort Lauderdale, Florida.
/s/Seymour Robin
Seymour Robin
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Registrant's audited financial statements for the year ended December 31, 1999
and is qualified in its entirety by reference to those financial statements.
</LEGEND>
<CIK> 0000930364
<NAME> RIDGEWOOD ELECTRIC POWER TRUST IV
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 893,383
<SECURITIES> 15,829,177<F1>
<RECEIVABLES> 613,002
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,009,680
<PP&E> 16,789,544
<DEPRECIATION> 2,957,855
<TOTAL-ASSETS> 39,455,324
<CURRENT-LIABILITIES> 1,669,763<F2>
<BONDS> 3,479,460
<COMMON> 0
0
0
<OTHER-SE> 28,381,288<F3>
<TOTAL-LIABILITY-AND-EQUITY> 39,455,324
<SALES> 7,179,229
<TOTAL-REVENUES> 7,548,229
<CGS> 6,347,905
<TOTAL-COSTS> 1,382,172
<OTHER-EXPENSES> 390,145
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 437,238
<INCOME-PRETAX> (743,977)
<INCOME-TAX> 0
<INCOME-CONTINUING> (743,977)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (743,977)
<EPS-BASIC> 1,560
<EPS-DILUTED> 1,560
<FN>
<F1>Investments in power project partnerships.
<F2>Includes $341,018 due to affiliates.
<F3>Represents Investor Shares of beneficial interest
in Trust with capital accounts of $28,502,542 less
managing shareholder's accumulated deficit of $121,254.
</FN>
</TABLE>
