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, 1998
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 9, 1999 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"). 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
1,181 record 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 sets of 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 Corporation (the "Managing Shareholder"), a Delaware corporation, is the
Managing Shareholder of the Trust.
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 of the 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 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.
As described below at Item 1(c)(6)(iii) - Business - Narrative Description
of Business - Regulatory Matters - the 1940 Act, 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,
as described there.
Unlike three prior investment programs that the Managing Shareholder has
sponsored in the independent power industry, the Trust consolidates its
more than 50% owned 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. In 1997, as
described below, capital improvements were completed. 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
Company 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 1998 totalled $530,000, down
from $964,000 for 1997. The decrease reflected higher 1998 expenditures for
regularly scheduled engine overhauls and preventative maintenance.
(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, 1998 was $877,000.
The California Pumping Project has been operating since 1992 and uses 43
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. The California Pumping Project will provide power
equivalent to approximately 2.4 megawatts.
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, which 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 partnership was credited with all income relating to
the projects from July 1, 1996 to the closing date and the seller was credited
with interest on the purchase price at annual rates of 6% to 8.5% during that
period.
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.
The Trust's net equity in the income of the Maine Hydro Projects for 1998
was $658,000, up from $522,000 in 1997.
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 1998, the
operator was paid a total of $429,000 for operating and incentive fees, the same
as for 1997.
(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 original members of Indeck Maine have transferred their equity
interest, which is subject to the preferred membership interest, to Indeck
Energy Services, Inc. ("Indeck"). In connection with the transaction, Indeck
Maine distributed $9,143,000 of the purchase price to its original members. The
preferred membership interest entitles the Trust and Ridgewood Power V to
receive all net cash flow from operations each year until they receive a 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, the original Indeck Maine members had the
right to designate a majority of the managers of Indeck Maine and thus had
management control, although approval of the Trust and Ridgewood Power V jointly
was required for many significant decisions. The operating agreement, however,
provided that 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. The other Indeck Maine members had the
right regain control if Indeck Maine satisfies the cumulative preferred return
requirement within the next five calendar quarters. Under that arrangement,
until March 1999 Indeck Operations, Inc., an affiliate of the original Indeck
Maine members and 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 Maine affiliates. The management agreement could be terminated on
notice if the Trust and Ridgewood Power V obtain the right to designate a
majority of the managers of Indeck Maine.
The Trust, Ridgewood 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. 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 Indeck Maine projects operated for five months in 1997 selling
electricity to participants in the New England Power Pool or to Bangor
Hydro-Electric Company on monthly contracts. The contracts were not renewed in
1998 and the projects were shut down in January 1998. Later in January 1998,
during a severe ice storm, local officials requested an emergency restart of the
projects. A dispute ensued between Bangor Hydro-Electric Company and the Indeck
Maine projects, caused by the high costs of restarting the plants on an
emergency basis. Bangor Hydro-Electric Company accused the projects of
price-gouging in the emergency. Indeck Maine responded that Bangor
Hydro-Electric was distorting the facts to divert attention from other matters
and that it would sell the emergency energy at cost. The matter was informally
reviewed by the Maine Attorney General's office, which advised Indeck Maine at
the conclusion of its review that it had no current intention to take action.
The Trust does not anticipate any material adverse effect from the dispute.
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 $2,667,000 per year for both projects in 1998. A portion of this
cost (approximately $1,430,000) was defrayed during 1998 through the sale of the
projects' "installed capability" to participants in the New England Power Pool.
Beginning in April 1998, ISO-New England, Inc. (the "ISO"), an independent,
non-profit organization in which Indeck Maine and substantially all generators
and distribution utilities in New England are members, began an auction process
as part of the deregulation of the New England electricity market. See (4)
- --Trends in the Electric Utility and Independent Power Industries, for an
explanation of the deregulatory process. The first commodity to be auctioned is
"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.
Beginning April 1, 1998 each distribution utility that is a member of the ISO
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 have sold installed capability throughout 1998
under short-term contracts and thus earned revenues without generating material
amounts of electric power. In April 1999, it is planned that the ISO will add
additional commodities to the auction process, such as operating capability (the
amount of power that can be delivered by generating plants that are operating or
can be placed in operation on short notice) and energy (the actual energy
delivered by operating plants). The Trust is negotiating with several potential
customers for sales of operating capability as well as installed capability.
There can be no assurance, however, that it will be able to do so successfully
or that the revenues it earns in 1999 will be comparable to those earned in
1998. In that regard, prices for installed capability have tended to decline
from the area of $3 per kilowatt per month to $1.50 to $1.75 per kilowatt per
month in February 1999, which may reflect seasonal variations in demand for
capability but which may also reflect maturation of the market and the
availability of additional supplies of capability.
Indeck Maine funded the approximately $1.2 million difference between the
Maine Biomass projects' revenues and operating expenses by borrowing. The Trust
provided 25% of the loans ($375,000 in 1998), Ridgewood Power V also provided an
equal 25% and the remaining 50% was provided by the Indeck, all on the same
terms. Indeck Maine issued demand promissory notes bearing interest at 5% per
year to evidence the indebtedness.
The Trust believes that as utilities sell off generating assets, as state
regulators require purchase of "renewable power" as described further at (4)(ii)
- - Trends in the Electric Utility and Independent Power Industries - Maine
Biomass and "Merchant Power Plants" - Renewable Power and as the market in New
England for generation becomes more competitive, the Maine Biomass projects will
be able to sell their future output profitably. However, there can be no
assurance that they can do so consistently and earn a satisfactory return in the
rapidly deregulating electricity industry. See generally (4) - Trends in the
Electric Utility and Independent Power Industries for further discussion of the
opportunities and problems related to the deregulated industry.
Neither Indeck Maine, its original members, Indeck nor Indeck Operations,
Inc. is 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. The sales price and the
terms of the acquisition were determined in arm's length negotiations between
the Managing Shareholder of the Trust and representatives of the original Indeck
Maine members. The source of the Trust's funds was proceeds of its private
placement offering of Investor Shares.
(v) Santee River Rubber Company
The Trust and Ridgewood Power V have purchased preferred membership
interests in Santee River Rubber Company, LLC, a newly-organized 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 Ridgewood Power V purchased the interest through a limited liability
company owned one-third by the Trust and two-thirds by Ridgewood 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 Ridgewood Power V provided the remaining
$8,980,000 of the price.
Until the Facility begins operations, Santee River will pay the Trust
and Ridgewood Power V a fixed distribution of 12% per year on $11,500,000 of the
total they contributed. After operations begin, the preferred membership
interest entitles the Trust and Ridgewood 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 Ridgewood 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 Ridgewood Power V
and (b)the other owner of Santee River. All amounts and tax items the Trust and
Ridgewood Power V receive from Santee River are shared one-third by the Trust
and two-thirds by Ridgewood Power V, with neither having any preference over the
other. The Trust and Ridgewood 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
Ridgewood 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 Ridgewood 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 has been designed to receive and process waste tires and
other waste rubber products and produce fine crumb rubber of various sizes. The
processing system will include 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. The
Company 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.
The Facility will be constructed on an approximately 30-acre site (the "Site")
in Berkeley County, South Carolina owned by the Company. The Site is mortgaged
as security for the bonds issued for the Facility.
The Facility will be 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 initial reports indicate that the
pilot facility is meeting or exceeding 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 a portion 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 will provide 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
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. The sales price and the terms of the
acquisition were determined in arm's length negotiations between the Managing
Shareholder of the Trust and representatives of EPS. The source of the Trust's
funds was proceeds of its private placement offering of Investor Shares.
The Trust has substantially completed its investment program.
(3) Project Operation.
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.
Although the Maine Biomass Projects are Qualifying Facilities, they do not
have long-term Power Contracts and will be selling their capacity and output
competitively.
The Trust's decisions to purchase Projects in New England have been 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 forced shutdown of
four large nuclear power plants 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.
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:
<TABLE>
<CAPTION>
Calendar year
1998 1997 1996
<S> <C> <C> <C>
New England Electric System 91.0% 90.0% 90.7% (Providence Project)
</TABLE>
Distributions of net cash flow from the Maine Hydro Projects, whose
financial statements are not consolidated with those of the Trust, are
considered to be revenues from investments rather than operating revenues. The
Trust accounts for these investments on the equity method and distributions to
the Trust reduce the carrying value of the investments. Similarly, the financial
statements of the Maine Biomass Projects are not consolidated with those of the
Trust and their revenues accordingly 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.
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.
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 are pending. Indeck Maine has also entered negotiations with Bangor
Hydro and the New England Power Pool for a package of special facilities
agreements that would remove most of the tariff disadvantages. Those
negotiations are near conclusion but any settlement will require approval by
both FERC and the Maine Public Utility Commission.
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. As described above, 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 spot power prices are
significantly higher during those periods.
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.
The Providence and Maine Hydro Projects owned by the Trust 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.
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.
The California Pumping Project's engines burn natural gas. Hydrocarbon
fuels, such as natural gas, coal and fuel oil, 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, oil and, to a lesser extent, coal have
fluctuated significantly over the last few years. Such fluctuations may directly
inhibit the development of Projects because of the anticipated effects on
Project profitability and may deter lenders to Projects or result in higher
costs of financing.
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.
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.
(4) Trends in the Electric Utility and Independent Power Industries
(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
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). The most important changes occurring in the electric power industry
are the efforts of FERC to compel utilities and power pools to provide
nationwide access to transmission facilities to all wholesale power generators.
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.
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.
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 have grown 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.
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. Finally,
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. 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.
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 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. Unless there is a shortage of renewable capacity these state
requirements may still not raise the price for renewable power high enough to
make those Projects profitable.
Initial Effects of Trends
With these conditions in mind, many observers see two 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
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.
Finally, there have been industry-wide moves toward consolidation of
participants and divestiture of Projects. 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. This consolidation tends to create additional
competitive pressures in the electric power industry; however, this trend may
also encourage the divestiture of smaller Projects or Projects that are deemed
less central to the operations of large, consolidated businesses.
(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, may be 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 September 1998 the Environmental Protection Agency ("EPA") brought
administrative proceedings against the Providence Project for violations of
training, recordkeeping and signage requirements. The alleged violations and the
proceedings are described at Item 3 - Legal Proceedings, below.
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 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 required 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.
In 1998, the Trust's Projects became subject to the reporting
requirements of the Emergency Planning and Community Right-to-Know Act that
require the Projects to prepare toxic release 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 requirementwill 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 Ridgewood 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 Ridgewood 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 or 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 inform 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 Ridgewood Power V.
** Joint venture owned by Indeck, the Trust and Ridgewood Power V.
*** Joint venture owned by EPS, the Trust and Ridgewood 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. RPPP answered
and the matter has been referred to an alternative dispute resolution procedure
within the EPA. In the course of discussions with the EPA and through the
alternative dispute resolution procedure, EPA has offered to reduce the penalty
to $88,750. Further, EPA is discussing with RPPP a proposal to offset a portion
of the penalty by crediting RPPP with certain environmental audit and
remediation expenditures, over and above those required by law, that the Trust
and other Ridgewood Power Trusts may agree to make. RPPP expects to resolve this
matter in the second quarter of 1999 and does not anticipate that it will have
to make further material capital expenditures to remedy the items identified by
the EPA or that this proceeding will have a material adverse impact on it. The
Trust does not anticipate that it will be liable or will have to fund the costs
of this proceeding. Costs of defense and settlement will be paid by the Project.
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.
No monetary relief was requested and the complaints are pending before FERC. If
settlement negotiations involving Bangor Hydro and the New England Power Pool
are successful, the Trust anticipates that these complaints would be withdrawn.
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 1998.
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, IV 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 1,181 record holders of
Investor Shares.
(c) Dividends
The Trust made distributions as follows in 1997 and 1998:
Year ended December 31,
1997 1998
Total distributions to Investors $3,287,256 $3,383,175
Distributions per Investor Share 6,894 7,096
Distributions to Managing Shareholder $33,205 $ 34,173
Distributions are made on a monthly basis. 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 6.9% in 1997 and 7.1% in
1998 and does not anticipate that distributions during 1999 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 the onset of full deregulation in 2000 and because construction of the
Santee River Project will not be completed before late 1999 and thus income from
the Project is not anticipated to increase. 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
1998 1997 1996 December 31, 1995
(Restated)
Total Fund Information:
<S> <C> <C> <C> <C>
Net sales $6,905,883 $6,810,911 $4,087,722 $0
Net income (loss) (602,901) 402,777 72,769 (156,133)
Net assets (shareholders'
equity) 31,003,923 35,023,361 38,746,599 13,502,131
Investments in Project
development entities,
power generation
equipment and deve-
lopmental costs 29,259,917 26,048,431 20,467,908 0
Investment in electric
power sales contract
(net of amortization) 6,835,959 7,391,828 7,947,697 0
Total assets 43,060,184 47,964,823 52,453,335 13,890,163
Long-term obligations 4,196,455 4,848,067 5,440,260 0
Per Share of Trust
Interest:
Revenues 15,258 15,059 $9,121 $0
Net income (loss) (1,262) (845) 153 (963)
Net asset value 65,025 73,455 81,264 83,295
Distributions to Investors 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. Assuming biomass fuel can be purchased at reasonable prices in
the year 2000 and beyond, the Maine Biomass Projects may be among the low cost
producers of environmentally friendly electricity in Maine and should be able to
operate profitably in a competitive market environment. 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,
installed capacity and operable 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 profitable operations in late 1999 or early 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, 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) 224,000 ---
California Pumping Project (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 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, which provides
irrigation pumping to Southern California farmers, suffered from the
extraordinary rainfall that occurred in the first half of 1998. 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 $94,000 to the third
party manager to terminate the operating agreement, further reducing revenues
from the project.
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.
The year ended December 31, 1997 compared to the year ended December 31, 1996.
In 1997, the Trust had a net loss of $403,000 as compared to net income of
$73,000 in 1996. The 1998 net loss and 1997 net income include the following
results from projects:
Project 1997 1996
Providence Project (1) $ 964,000 $520,000
Maine Hydro Projects (2) 522,000 99,000
Maine Biomass Projects (2) (680,000) ---
California Pumping Project 18,000 26,000
(1) Earnings, net of minority interest.
(2) Equity interest in income (loss) of the project.
Earnings from the Providence Project increased because 1997 included a full
year of operations compared to eight and one half months in 1996. The increase
in income from the Maine Hydro Projects reflects that the Trust purchased the
projects in December 1996. The Maine Biomass Projects were purchased in July
1997 and the loss primarily reflects the costs of maintaining these shut down
facilities. Income from the California Pumping Project declined slightly
reflecting a minor decrease in demand for irrigation in its area.
The 1997 Trust-level expenses include a full year of management fees of
$1,155,000, which were higher than the $888,000 recorded in the last three
quarters of 1996. Investment fees of $628,000 in 1996 related to contributions
received during the offering period of the Trust which ceased in March 1996. Due
diligence costs of projects that were ultimately rejected increased from $62,000
in 1996 to $669,000 in 1997. Other expenses in 1997 and 1996 were consistent.
Liquidity and Capital Resources
In 1998 and 1997, the Trust's operating activities generated $526,000 and
$2,656,000 of cash, respectively. The higher level of cash from operations in
1997 primarily reflects decreases in working capital at the Providence Project.
The Trust used $4,594,000 and $4,855,000 of cash in its financing activities in
1998 and 1997, respectively. This use of cash was primarily for distributions to
shareholders and, to a lesser extent, for the Providence Project to pay down
debt and make payments to the project's minority owner.
In 1998 and 1997, cash used in investing activities was $4,997,000 and
$9,399,000, respectively. In 1998 the Trust invested $4,490,000 in the Santee
River. In 1997, the Trust invested $7,298,000 in the Maine Biomass Project. In
1998 and 1997, capital expenditures amounted to $1,451,000 and $3,060,000, most
of which related to the engine and facility upgrades at the Providence Project.
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 1998 or 1997.
Following the completion of its investment program, obligations of the
Trust are generally limited to payment of Project operating expenses, 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 is 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 1999 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. The Managing Shareholder has assessed
problems, has a written plan for remediation and is implementing the plan.
The accounting, network and financial packages for the Ridgewood companies
are basically off-the-shelf packages that will be remediated, where necessary,
by obtaining patches or updated versions. The Managing Shareholder expects that
updating will be complete before the end of April 1999 with ample time for
implementation, testing and custom changes to some modifications made by
Ridgewood to those programs. To a large extent, these software packages would
have been upgraded within a three to five year time frame, even absent the Year
2000 problem. 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 identified 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. In late 1998, the
Managing Shareholder's outside computer consultant reviewed the remediation
completed for those systems and advised the Managing Shareholder that material
additional work was required for these systems to work efficiently after 1999.
The Managing Shareholder accordingly employed a new specialist for Year 2000
remediation of those systems and other software and for information systems
support generally. Changes to the distribution system and testing of that system
were completed by the end of the first quarter of 1999, on schedule. The plan
also targets completion by the end of the second quarter of 1999 of minor
changes to the elements of the subscription/investor relations system that will
allow it to handle individual investors' records, and of all testing of those
modifications. Elements of that system used to generate internal sales reports
and other internal reports (but which do not affect investors' records) will
require major remediation. Remediation of the internal report generating
programs is expected to be completed by the end of the third quarter of 1999
with testing and any additional modifications to be completed no later than the
end of 1999.
The Managing Shareholder is confident that all software systems necessary
to maintain investor records will be remediated and tested well before the end
of 1999. If the systems used to generate internal reports from the
subscription/investor relations system are not remediated by the end of 1999,
the Managing Shareholder is developing a contingency plan to use the existing
systems together with manual entry of data and checking of results until
remediation is complete. The Managing Shareholder has done this in the past when
system problems have occurred and it thus believes that there will be no
material or noticeable effect on the accuracy of its records or generation of
internal reports, although it may experience delays in generating internal
reports of a few days.
Some systems 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 is estimated
at $12,250 and is estimated to be approximately $11,500 for 1999.
Each of the Trust's electric generating facilities is being reviewed during
the first quarter of 1999 by an outside consultant to determine if its
electronic control systems contain software affected by the Year 2000 problem or
contain embedded components that contain Year 2000 flaws. Many of the Trust's
facilities are small electric generating facilities that rely on mechanical and
analog systems that are generally not subject 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.
The Trust's two largest generating plants, the Maine Biomass Projects
(total capacity net to the Trust 26 megawatts), have been managed by Indeck
Operations, Inc., an affiliate of Indeck Energy Systems, Inc., until March 1,
1999. The Trust took over management responsibility as of that date. Those
plants have not operated since fall 1997 and currently are shut down with an
anticipated startup date of April 2000. The manager of the plants informed the
Trust in December 1998 that the plants contained electronic control systems with
embedded components containing Year 2000 flaws. The manufacturer of the control
systems has been contacted and custom-made replacement components have been
ordered, which are expected to be obtained and installed by the end of June
1999. If these components are not remediated, the Trust has been advised that
the plants would be inoperable from January 1, 2000. Because the Trust does not
anticipate that the plants would be in operation until April 2000, the year 2000
problems would not result in a shutdown in January 2000.
Although the plants are not operating, they do currently sell "installed
capability" (a theoretical measurement of the reserve generating capacity of the
plants) to members of the New England Power Pool. Installed capability sales
require that the plants be operated at capacity for 24 hours in February or
March of each year as a test. A year 2000 failure that continued beyond February
or March 2000 might also disqualify the Trust from selling "installed
capability" (the theoretical reserve capacity of the plants) after February or
March 2000.
Based on discussions with Indeck Operations, Inc., the Trust believes that
the embedded components will be replaced and testing completed well before
January 2000 and that the possibility that the plants will be unable to operate
is remote. The Trust is also investigating whether, in the unlikely event the
embedded components cannot be replaced and tested in time, the plants can be
operated with manual or analog systems. The Trust's share of the anticipated
costs of remediation is estimated at less than $50,000. Except as described
above, the Trust has discovered no systems at its operating facilities that, if
they were not Year 2000 compliant, would have a material adverse impact on
output, environmental compliance, recordkeeping or any other material aspect of
operations.
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. However, if customers' payment systems
or suppliers' systems were adversely affected by year 2000 problems, the Trust
could be affected. For example, if the utilities that purchase the Trust's
electricity output were unable to accept electricity because of system
malfunctions or transmission failures caused by Year 2000 non-compliance by them
or other persons, the Trust would lose revenues that could not be recouped at a
later date. Similarly, if utility payment systems were to malfunction, the
Trust's revenues might be delayed. Based on published reports, the Trust
believes that it is now very unlikely that utilities will fail to accept
electricity for more than a very short time because of malfunctions caused by
the Year 2000 problem. Although the Trust also believes that utility payment
problems are unlikely and, if they occur, will not exceed a month or two, there
can be no assurance that payments to the Trust will not be interrupted. The
Trust has established a line of credit, described above at "Liquidity and
Capital Resources," to cover this contingency and others. The Trust's
non-utility customers are being contacted during the first and second quarters
of 1999. The Trust anticipates that the customers will advise it that they do
not anticipate that their own Year 2000 problems, if any, will interfere with
taking or paying for the Trust's outputs of electricity, but that they will
decline to give any assurance that they will be able to do so.
The Trust's plants are fueled by renewable sources of energy such as water
at hydroelectric dams, landfill gas and wood waste. The Managing Shareholder
does not believe that availability of these energy sources will be significantly
affected by the Year 2000 problem. The Santee River plant's raw materials, after
it opens (which is expected to be in mid-2000 at the earliest) are used tires
and liquid nitrogen. The availability of these materials is not expected to be
significantly affected by Year 2000 problems. Availability of other supplies
such as spare parts and consumables may be affected by Year 2000 problems; the
Trust purchases these items from many different sources, no single one or group
of which could have a material effect on the Trust if it or they were not Year
2000 compliant.
Because the Trust and the Managing Shareholder are extremely small relative
to the size of their material customers and suppliers and are paid or supplied
using the same systems as larger companies, requests for written assurances of
compliance from those customers or suppliers are not cost-effective. Instead,
the Managing Shareholder is monitoring industry trends and compliance and is
working to assure the Trust's continued operations. Similarly, as described
above, in most cases there are no cost-effective contingency measures that can
be taken against the major risks to the Trust that utilities will fail to take
or fail to pay for the Trust's electricity output as the result of Year 2000
problems. The Trust believes that in the event that any embedded components or
other systems are found to have Year 2000 problems at its power plants it will
be able to remediate them promptly and before the end of 1999. It is preparing
contingency plans to operate the plants with manual or analog control systems if
Year 2000 problems cannot be remediated. Because the Maine Hydro plants are
small and use simple technologies (small hydroelectric turbines) that are not
dependent on date-sensitive electronics, the Trust believes that it is unlikely
that the Maine Hydro Plants would be unable to operate because of Year 2000
problems.
Based on its internal evaluations and the risks and contexts identified by
the Commission in its rules and interpretations, the Trust believes that except
with regard to the Providence and Maine Biomass Plants 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.
The Trust is unable to predict reliably what, if anything, will happen
after December 31, 1999 with regard to Year 2000 problems caused by the
inability of other businesses and government agencies to complete Year 2000
remediation. The Trust knows of no specific problems identified by customers or
suppliers that would have a material adverse effect on the Trust.
The reasonable worst case scenario anticipated by the Trust is that its
electric generating facilities will be able to operate on and after January 1,
2000 but that there may be some short-term inability of their customers to pay
promptly. In that event, the Trust's revenues could be materially reduced for a
temporary period and it might have to draw upon its credit line to fund
operating expenses until the utility makes up any payment arrears. The Trust
believes that the Providence and Maine Biomass facilities will be capable of
operation after January 1, 2000. For purposes of a worst case scenario it will
assume, until the survey of embedded components is completed or remediation is
completed, that the Providence facility would not be able to operate after
January 1, 2000 and that the Maine Biomass facilities would not be able to
complete their spring 2000 testing because there might be embedded components
that are not Year 2000 compliant and the components could not be replaced in
time. The Providence and Maine Biomass facilities provided approximately 95% of
the Trust's net revenues in 1998.
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, 1998
Expected Maturity Date
1999
(U.S. $)
Bank Deposits and Certificates
of Deposit $ 2,414,916
Average interest rate 5.225%
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Balance Sheets at December 31, 1998 and 1997 F-3
Statement of Operations for Years Ended
December 31, 1998, 1997 and 1996 F-4
Statement of Changes in Shareholders' Equity for
Years Ended December 31, 1998, 1997 and 1996 F-5
Statement of Cash Flows for
Years Ended December 31, 1998, 1997 and 1996 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.
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 Corporation 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 is its managing
shareholder.
Robert E. Swanson has been the President, sole director and sole stockholder
of Ridgewood Power Corporation since its inception in February 1991.
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 Corporation is 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 is organized as a corporation that is wholly-owned
by Mr. Swanson.
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 Corporation
("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
Corporation ("Ridgewood Capital"), organized in 1998, which assists in offerings
made by the Managing Shareholder and which is the sponsor of two privately
offered venture capital funds (Ridgewood Capital Venture Partners, LLC and
Ridgewood Institutional Venture Partners, LLC) and Ridgewood Power VI
Corporation ("Power VI Corp."), which is a managing shareholder of the Growth
Fund, and RPMCo.
Set forth below is certain information concerning Mr. Swanson and other
executive officers of the Managing Shareholder.
Robert E. Swanson, age 52, 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 Ridgewood Capital Venture Partners, LLC and Ridgewood Institutional Venture
Partners, LLC. 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 40, 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 Ridgewood Capital Venture Partners, LLC and
Ridgewood Institutional Venture Partners, LLC. 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 44, 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 51, 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 Ridgewood Capital Venture
Partners, LLC and Ridgewood Institutional Venture Partners, LLC.
Mr. Quinn has 30 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 Price Waterhouse, and a Bachelor of Science
degree in Accounting and Finance from the University of Scranton (1969).
Mary Lou Olin, age 46, 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, 2000 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 and Dr. Richard
D. Propper. Mr. Belknap and Dr.Propper also serve as independent trustees for
Ridgewood Power I and the Growth Fund. 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 52, has been chief financial officer of three national
retail chains and their parent companies. Since July 1997, he has been 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., an
office products superstore chain. From February 1994 to February 1995, Mr.
Belknap was Executive Vice President and Chief Financial Officer of Zale
Corporation, a retail jewelry store 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 also served as a director of
and consultant to Finlay Enterprises, Inc., an operator of leased fine jewelry
departments in major department stores nationwide.
Dr. Richard D. Propper, age 48, 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 two venture capital funds
sponsored by Ridgewood Capital. He receives a fixed consulting fee from those
funds and contingent compensation from Ridgewood Capital.
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 Ridgewood Power I, Ridgewood Power II, Ridgewood Power III 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 1998.
(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 51, 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
1997 or 1998. 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 did not make any distributions in 1995 to the Managing
Shareholder (which is a member of the Board of the Trust) or any other person
and made distributions in 1996 as stated at Item 5 - Market for Registrant's
Common Equity and Related Stockholder Matters. The Trust paid fees to the
Managing Shareholder and its affiliates as follows:
Fee Paid to 1998 1997 1996
Management
fee Managing
Shareholder $1,050,700 $1,154,758 $888,209
Cost reimbursements* RPMCo 401,290 467,881 337,228
Investment fee Managing
Shareholder 0 0 627,561
Placement agent fee Ridgewood
and sales commis- Securities
sions Corporation 0 0 315,493
Organizational, Managing
distribution and Shareholder
offering fee 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, 1998.
(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 of Indeck 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, 1999
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, 1999
Robert E. Swanson Executive Officer
By:/s/ Martin V. Quinn Senior Vice President and
Martin V. Quinn Chief Financial Officer April 14, 1999
By:/s/ Kathleen P. McSherry Controller April 14, 1999
Kathleen P. McSherry
RIDGEWOOD POWER CORPORATION Managing Shareholder
By:/s/ Robert E. Swanson President April 14, 1999
Robert E. Swanson
/s/ Robert E. Swanson * Independent Trustee April 14, 1999
John C. Belknap
/s/ Robert E. Swanson * Independent Trustee April 14, 1999
Richard D. Propper
As attorney-in-fact for the Independent Trustee
<PAGE>
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Financial Statements
December 31, 1998, 1997 and 1996
-F1-
<PAGE>
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10036
[Letterhead of PricewaterhouseCoopers LLP]
Report of Independent Accountants
March 23, 1999
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") at December 31, 1998 and
1997, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. 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 generally accepted auditing
standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
-F2-
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Balance Sheet
- --------------------------------------------------------------------------------
December 31,
----------------------------
1998 1997
------------ ------------
Assets:
Cash and cash equivalents .................. $ 2,021,168 $ 11,086,281
Accounts receivable, trade ................. 617,973 559,764
Due from affiliates ........................ 377,710 164,536
Other assets ............................... 57,975 97,453
------------ ------------
Total current assets ................ 3,074,826 11,908,034
Investments:
Maine Hydro Projects ....................... 6,217,289 6,694,826
Maine Biomass Projects ..................... 6,306,818 6,617,862
Santee River Rubber ........................ 4,501,357 --
Electric power equipment held for resale ... 455,182 455,182
Deferred due diligence costs ............... -- 27,159
Plant and equipment ........................ 16,359,211 14,949,735
Accumulated depreciation ................... (2,073,744) (1,068,812)
------------ ------------
14,285,467 13,880,923
------------ ------------
Electric power sales contract .............. 8,338,040 8,338,040
Accumulated amortization ................... (1,502,081) (946,212)
------------ ------------
6,835,959 7,391,828
------------ ------------
Spare parts inventory ...................... 746,178 383,810
Debt reserve fund .......................... 637,108 605,199
------------ ------------
Total assets ....................... $ 43,060,184 $ 47,964,823
------------ ------------
Liabilities and Shareholders' Equity:
Liabilties:
Current maturities of long-term debt ....... $ 651,613 $ 592,193
Accounts payable and accrued expenses ...... 563,685 384,533
Due to affiliates .......................... 441,614 658,253
------------ ------------
Total current liabilities ......... 1,656,912 1,634,979
Long-term debt, less current portion ....... 4,196,455 4,848,067
Minority interest in the Providence Project 6,202,894 6,458,416
Commitments and contingencies
Shareholders' Equity:
Shareholders' equity (476.8
shares issued and outstanding) ........... 31,098,950 35,078,194
Managing shareholder's accumulated deficit . (95,027) (54,833)
------------ ------------
Total shareholders' equity ........ 31,003,923 35,023,361
------------ ------------
Total liabilities and shareholders'
equity .......................... $ 43,060,184 $ 47,964,823
------------ ------------
See accompanying notes to the consolidated financial statements.
-F3-
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Statement of Operations
- --------------------------------------------------------------------------------
Year Ended December 31,
------------------------------------------
1998 1997 1996
----------- ----------- -----------
Net sales ......................... $ 6,905,883 $ 6,810,911 $ 4,087,722
Sublease income ................... 369,000 369,000 261,375
----------- ----------- -----------
Total revenue ............ 7,274,883 7,179,911 4,349,097
----------- ----------- -----------
Cost of sales, including
depreciation and amortization
of $1,560,801, $1,267,572 and
$747,452 in 1998, 1997 and 1996 . 5,638,396 4,879,962 2,991,835
----------- ----------- -----------
Gross profit ...................... 1,636,487 2,299,949 1,357,262
General and administrative
expenses ........................ 696,734 505,116 372,415
Management fee .................... 1,050,700 1,154,758 888,209
Investment fee .................... -- -- 627,561
Project due diligence costs ....... 204,579 668,554 63,052
Other expenses .................... 12,981 32,255 43,160
----------- ----------- -----------
Total other operating expenses .. 1,964,994 2,360,683 1,994,397
----------- ----------- -----------
Loss from operations .............. (328,507) (60,734) (637,135)
----------- ----------- -----------
Other income (expense):
Interest income ................. 374,585 926,641 1,294,037
Interest expense ................ (496,658) (572,660) (394,665)
Loss from Maine Biomass Projects (694,321) (680,109) --
Income from Maine Hydro Projects 657,989 521,710 99,224
Income from Santee River Rubber . 181,675 -- --
----------- ----------- -----------
Other income, net ... 23,270 195,582 998,596
----------- ----------- -----------
(Loss) income before minority
interest ........................ (305,237) 134,848 361,461
Minority interest in the earnings
of the Providence Project ....... (296,854) (537,625) (288,692)
----------- ----------- -----------
Net (loss) income ................. $ (602,091) $ (402,777) $ 72,769
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
-F4-
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Statement of Changes In Shareholders' Equity
For the Years Ended December 31, 1998, 1997 and 1996
- --------------------------------------------------------------------------------
Managing
Shareholders Shareholder Total
------------ ------------ ------------
Shareholders' equity,
January 1, 1996 (162.1
shares) ................ $ 13,503,692 $ (1,561) $ 13,502,131
Capital contributions, net
(314.7 shares) ......... 26,848,394 -- 26,848,394
Cash distributions ....... (1,659,928) (16,767) (1,676,695)
Net income for the year .. 72,041 728 72,769
------------ ------------ ------------
Shareholders' equity,
December 31, 1996 (476.8
shares) ................ 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 (476.8
shares) ................ 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 (476.8
shares) ................ $ 31,098,950 $ (95,027) $ 31,003,923
------------ ------------ ------------
See accompanying notes to the consolidated financial statements.
-F5-
<PAGE>
Ridgewood Electric Power Trust IV
Consolidated Statement of Cash Flows
- --------------------------------------------------------------------------------
Year Ended December 31,
--------------------------------------------
1998 1997 1996
------------ ------------ ------------
Cash flows from operating
activities:
Net (loss) income ............. $ (602,091) $ (402,777) $ 72,769
------------ ------------ ------------
Adjustments to reconcile net
(loss)income to net cash flows
from operating activities:
Depreciation and amortization . 1,560,801 1,267,572 747,452
Amortization of prepaid and
accrued royalties- net ...... -- -- 777,886
Minority interest in earnings
of the Providence Project .... 296,854 537,625 288,692
Income from unconsolidated
Maine Hydro Projects ........ (657,989) (521,710) (99,224)
Loss from unconsolidated Maine
Biomass Projects ............ 694,321 680,109 --
Income from unconsolidated
Santee River Rubber ......... (181,675) -- --
Changes in assets and
liabilities, net of effects
of investment:
Decrease (increase) in
maintenance reserve fund ... -- 394,070 (14,164)
(Increase) decrease in
accounts receivable, trade . (58,209) 505,417 (418,433)
Increase in spare parts
inventory .................. (362,368) -- --
Decrease in customer escrow
fund ....................... -- -- 1,119,115
Increase (decrease) in
accounts payable and
accrued expenses ........... 179,152 (363,426) 450,418
(Decrease) increase in due
to/from affiliates, net ... (429,813) 401,660 (261,562)
Other- net .................. 39,478 157,081 26,093
------------ ------------ ------------
Total adjustments .......... 1,080,552 3,058,398 2,616,273
------------ ------------ ------------
Net cash provided by
operating activities ........ 478,461 2,655,621 2,689,042
------------ ------------ ------------
Cash flows from investing
activities:
Investment in the Providence
Project, net of cash acquired -- -- (8,287,184)
Investment in Maine Hydro
Projects ..................... -- (265,953) (6,814,197)
Investment in Maine Biomass
Projects ..................... (383,277) (7,297,971) --
Investment in Santee River
Rubber ....................... (4,489,819) -- --
Distributions from Maine
Hydro Projects ............... 1,135,526 1,006,257 --
Distributions from Santee
River Rubber ................. 170,137 -- --
Capital expenditures .......... (1,409,476) (3,060,284) (1,928,332)
Deferred due diligence costs .. 27,159 218,669 (222,393)
------------ ------------ ------------
Net cash used in investing
activities .................. (4,949,750) (9,399,282) (17,252,106)
------------ ------------ ------------
Cash flows from financing
activities:
Proceeds from shareholders'
contributions ................ -- -- 31,495,223
Selling commissions and
offering costs paid .......... -- -- (4,646,829)
Cash distributions to
shareholders ................. (3,417,347) (3,320,461) (1,676,695)
Payments to reduce long-term
debt ......................... (592,192) (538,191) (331,953)
Increase in debt reserve fund . (31,909) (29,758) (58,677)
Distributions to minority
interest ..................... (552,376) (967,477) (530,639)
------------ ------------ ------------
Net cash (used in) provided by
financing activities ........ (4,593,824) (4,855,887) 24,250,430
------------ ------------ ------------
Net (decrease) increase in cash
and cash equivalents .......... (9,065,113) (11,599,548) 9,687,366
Cash and cash equivalents,
beginning of year ............. 11,086,281 22,685,829 12,998,463
------------ ------------ ------------
Cash and cash equivalents, end
of year ....................... $ 2,021,168 $ 11,086,281 $ 22,685,829
------------ ------------ ------------
See accompanying notes to the consolidated financial statements.
-F6-
<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 Corporation. The Trust began offering
shares on February 6, 1995 and discontinued its offering of shares in
March 1996.
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 investors 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% owned because the Trust has the ability to
exercise significant influence over the operating and financial
policies of the affiliate 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.
-F7-
<PAGE>
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.
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 1998, 1997 and
1996, the Trust recorded depreciation expense of $1,004,932, $711,703
and $357,109, 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 1998,
1997 and 1996, the Trust recorded amortization expense of $555,869,
$555,869 and $390,343, respectively.
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.
-F8-
<PAGE>
3. Investments
The Trust has the following investments:
Investment at December 31,
Accounting -------------------------
Project Name Method 1998 1997
-------------------------- ------------- ----------- -----------
Providence Project ....... Consolidation $11,181,794 $11,632,385
California Pumping Project Consolidation 597,478 648,176
Electric Power Equipment . Consolidation 455,182 455,182
Maine Hydro Projects ..... Equity Method 6,217,289 6,694,826
Maine Biomass Projects ... Equity Method 6,306,817 6,617,862
Santee River Rubber ...... Equity Method 4,501,357 --
----------- -----------
$29,259,917 $26,048,431
----------- -----------
Providence Project
In 1996, Ridgewood Providence Power Partners, L.P. was formed as a
Delaware limited partnership ("Providence Power"). The Trust invested
$12,721,500 and owns a 64.3% limited partnership interest in Providence
Power. In addition, Ridgewood Providence Power Corporation, was formed
as a Delaware corporation ("RPPCorp."). The Trust invested $128,500 and
owns 64.3% of the outstanding common stock of RPPCorp., which is the
sole general partner of Providence Power.
On April 16, 1996, Providence Power 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.
Through ownership in RPPCorp. and Providence Power, the Trust owns
64.3% of the Providence Project. 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 as of April 16, 1996, and the results of operations of the
Providence Project have been included in the Trust's Consolidated
Financial Statements since that 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.
The following unaudited pro forma information has been prepared
assuming the Providence Project was acquired as of the beginning of the
period presented. The pro forma information is presented for
information purposes only and is not necessarily indicative of what
would have occurred if the formation and acquisition had been made as
of that date. In addition, the pro forma information is not intended to
be a projection of future results and does not reflect capital
equipment additions and changes in operating management which have been
made at the Providence Project subsequent to the acquisition.
-F9-
<PAGE>
Pro Forma Information
(Unaudited)
1996
Net sales ............ $5,511,642
Income from operations 1,032,806
Net income ........... 88,558
California Pumping Project
On December 31, 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. The purchase price
of $353,619 was paid in 1996. During 1996, the Trust acquired an
additional 9 engines with a rated capacity of 1.2 megawatts at a
purchase price of $344,111. 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, 1998
and 1997, the Trusts total investment in the California Pumping Project
was $597,478 and $648,176, 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 and 1997, the cost
of such equipment was $455,182.
Maine Hydro Projects
On September 5, 1996, Ridgewood Maine Hydro Partners, L.P. was formed
as a Delaware limited partnership ("Ridgewood Hydro L.P."). The Trust
made investments totaling $6,748,256 and owns a 50% limited partnership
interest in Ridgewood Hydro L.P. In addition, Ridgewood Maine Hydro
Corporation was formed as a Delaware corporation ("RMHCorp."). The
Trust invested $65,941 and owns 50% of the outstanding common stock of
RMHCorp., which is the sole general partner of Ridgewood Hydro L.P.
On December 23, 1996, in a merger transaction, Ridgewood Hydro L.P.
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's 50% share of the cash consideration paid was
$6,814,198. The remaining 50% was paid by Ridgewood Electric Power
Trust V ("Trust V"). Ridgewood Power Corporation 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 December 23, 1996.
The Maine Hydro Projects are operated by a subsidiary of 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
-F10-
<PAGE>
flow in excess of a target amount. The Maine Hydro Projects recorded
$429,714, $429,430 and $3,070 of expense under this arrangement during
the periods ended December 31, 1998, 1997 and 1996, respectively. The
agreement has a five-year term 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, 1998 December 31, 1997
----------- -----------
Current assets .............. $ 1,346,077 $ 1,757,908
Electric power sales contract 11,165,469 12,225,765
Other non-current assets .... 1,057,892 634,952
----------- -----------
Total assets ................ $13,569,438 $14,618,625
----------- -----------
Current liabilities ......... $ 438,443 $ 291,911
Non-current liabilities ..... 696,418 937,062
Partners' equity ............ 12,434,577 13,389,652
----------- -----------
Total liabilities and equity $13,569,438 $14,618,625
----------- -----------
Statement of Operations Information
For the period
December
For the Year Ended 23, 1996
December 31, (Acquisition)
------------------------- to December
1998 1997 31, 1996
----------- ----------- -----------
Revenue ................. $ 4,511,361 $ 4,113,065 $ 192,152
Total expenses .......... 3,217,846 2,952,589 50,340
Interest income (expense) 22,464 (117,056) 56,635
----------- ----------- -----------
Net income .............. $ 1,315,979 $ 1,043,420 $ 198,447
----------- ----------- -----------
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 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 Bangor Hydro-Electric
-F11-
<PAGE>
Company, a local utility ("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. 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 IV and 75% to the other Maine Biomass Project members.
In 1998, the Trust loaned $375,000 to the Maine Biomass Projects. The
loan is in the form of three demand notes that bear interest at 5% per
annum. Trust V, which owns an identical preferred membership interest
in the Maine Biomass Projects, also made identical loans to the Maine
Biomass Projects. The other Maine Biomass Project members also loaned
$750,000 to the Maine Biomass Projects with the same terms.
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 Hydro 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 $200,00 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 of March 1, 1999
because certain preferred membership interest payments have not been
made. Under an Operating Agreement with the Trust, Ridgewood Power
Management Corporation ("Ridgewood Management"), an entity related to
the managing shareholder through common ownership, will provide
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
Summarized financial information for the Maine Biomass Projects is as
follows:
Balance Sheet Information
December 31, 1998 December 31, 1997
---------- ----------
Current assets: ............ $ 668,228 $ 861,677
Other non-current assets ... 3,339,584 3,524,356
---------- ----------
Total assets ............... $4,007,812 $4,386,033
---------- ----------
Current liabilities: ....... $1,952,062 $ 912,683
Members' equity ............ 2,055,750 3,473,350
---------- ----------
Total liabilities and equity $4,007,812 $4,386,033
---------- ----------
-F12-
<PAGE>
Statement of Operations Information
For the Period July
For the Year Ended 1, 1997 to December
December 31, 1998 31, 1997
----------- -----------
Revenue ...... $ 1,430,296 $ 2,991,793
Total expenses 2,847,896 4,376,458
----------- -----------
Net loss ..... $(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 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.
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 with Goodyear Tire & Rubber Company, Continental -
General Tire, Inc., British Tire & Rubber, Inc. and Recycled Solutions
for Industry, Inc. The agreements are contingent upon successful
testing of the facility's output.
The Trust's investment in the 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.
-F13-
<PAGE>
Summarized financial information for Santee River Rubber is as follows:
Balance Sheet Information
December 31, 1998
----------------------
Current assets $ 1,738,422
Construction in progress 18,468,255
Other non-current assets 25,622,193
----------------------
Total assets $ 45,828,870
----------------------
Liabilities $ 33,680,000
Members' equity 12,148,870
----------------------
Total liabilities and equity $ 45,828,870
----------------------
Statement of Operations Information
For the Period August 19,
1998 to December 31, 1998
----------
Revenue .......... $1,252,899
Operating expenses 604,029
----------
Net income ....... $ 648,870
----------
4. Long-Term Debt
Following is a summary of long-term debt at December 31, 1998:
Senior secured non-recourse notes payable $4,848,068
Less - Current maturity (651,613)
----------
Total long-term debt $4,196,455
==========
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, 1998 and
1997 or for the eight and one half months ending December 31, 1996. 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, 1998 and 1997, the cash balance in
these reserve accounts was $637,108 and $605,199, 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.
-F14-
<PAGE>
Scheduled repayments of long-term debt principal for the next five
years are as follows:
Year Ended
December 31, Repayment
1999 $651,613
2000 716,995
2001 788,937
2002 868,098
2003 955,202
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 borrowing 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 outstanding standby letters of credit totaling $300,000 which are
covered by the line of credit facility. At December 31, 1998 and 1997,
there were no borrowings outstanding under the credit facility.
5. Fair Value of Financial Instruments
At December 31, 1998 and 1997, 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 Company ("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, 1998 and 1997 and
the eight and one half months ended December 31, 1996, sales revenue
under the NEP Power Purchase Agreement amounted to $6,617,549,
$6,458,648 and $3,946,077, 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, 1998 and 1997 and the eight and one
half months ended December 31, 1996, royalty expense relating to the
RISWMC lease amounted to $986,224, 951,767 and $588,456, respectively.
Providence Power subleases the Central Landfill to Central Gas Limited
Partnership ("Gasco"). Gasco operates and maintains the landfill gas
-F15-
<PAGE>
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,
$369,000 and $261,375 for the years ended December 31, 1998 and 1997
and eight and one half months ended December 31, 1996, respectively.
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, 1998 and 1997 and the eight and one half months
ended December 31, 1996, amounted to $900,529, $863,536 and $555,447,
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.
For the period ended December 31, 1996, the Trust paid fees for these
services to the managing shareholder of $1,892,959. 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. For the period ended December 31,
1996, the Trust paid investment fees to the managing shareholder of
$627,561.
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,
1998, 1997 and 1996, the Trust paid an annual management fees to the
managing shareholder of $1,050,700, $1,154,758 and $888,209,
respectively. In 1999, the managing shareholder will waive 50% of the
management fees that it is entitled to.
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 each year an amount equal to 14% 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.
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 paid through December 31, 1998.
-F16-
<PAGE>
The managing shareholder purchased one 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
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 amount invested in
projects managed by Ridgewood Management. During the years ended
December 31, 1998 and 1997 and the eight and one half months ended
December 31, 1996, Ridgewood Management charged Providence Power
$401,290, $467,881 and $337,228, respectively. During the periods ended
December 31, 1998, 1997 and 1996, Ridgewood Management did not charge
any amounts to the Maine Hydro projects or the Maine Biomass projects.
9. 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
RPPP seeking to recover civil penalties of up to $190,000 for alleged
violations of operational recordkeeping and training requirements at
the Providence Project. RPPPP answered and the matter has been referred
to an alternate dispute resolution procedure within the EPA. In the
course of discussions with the EPA and through the alternate dispute
resolution procedure, the EPA has offered to reduce the penalty to
$88,750. Further, EPA is discussing with RPPP a proposal to offset a
portion of the penalty by crediting RPPP with certain environmental
audit and remediation expenditures, over and above those required by
law, that the Trust and other Ridgewood Power Trusts may agree to make.
RPPP expects to resolve this matter in the second quarter of 1999 and
does not anticipate that it will have to make further material capital
expenditures to remedy the items identified by the EPA or that this
proceeding will have a material adverse impact on it. The Trust does
not anticipate that it will be liable for or will have to fund the
costs of the proceeding.
-F17-
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Financial Statements
December 31, 1998, 1997 and 1996
-F1-
<PAGE>
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10036
[Letterhead of PricewaterhouseCoopers LLP]
Report of Independent Accountants
March 23, 1999
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 shareholders' 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, 1998 and 1997, and the results of its
operations and its cash flows for each of the two years in the period ended
December 31, 1998 and the period September 5, 1996 (date of formation) through
December 31, 1996, in conformity with generally accepted accounting principles.
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 generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
/s/ PricewaterhouseCoopers LLP
-F2-
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Balance Sheet
- --------------------------------------------------------------------------------
December 31,
----------------------------
1998 1997
------------ ------------
Assets:
Cash and cash equivalents ................. $ 607,119 $ 596,208
Accounts receivable, trade ................ 574,022 468,651
Due from affiliates ....................... 87,369 103,650
Deposits .................................. -- 500,000
Prepaid and other current assets .......... 77,567 89,399
------------ ------------
Total current assets ................. 1,346,077 1,757,908
Property, plant and equipment ............. 1,089,248 336,635
Accumulated depreciation .................. (31,356) (1,683)
------------ ------------
Property, plant and equipment, net ... 1,057,892 334,952
------------ ------------
Electric power sales contracts ............ 13,311,374 13,311,374
Accumulated amortization .................. (2,145,905) (1,085,609)
------------ ------------
Electric power sales contracts, net .. 11,165,469 12,225,765
------------ ------------
Deposits .................................. -- 300,000
------------ ------------
Total assets ......................... $ 13,569,438 $ 14,618,625
------------ ------------
Liabilities and Partners' Equity:
Liabilities:
Accounts payable and accrued expenses ..... $ 197,799 $ 157,017
Current portion of
long-term lease obligations ............. 240,644 134,894
------------ ------------
Total current liabilities ............ 438,443 291,911
Non-current portion of long-term
lease obligations ....................... 696,418 937,062
------------ ------------
Commitments and contingencies
Partners' equity:
General partner ........................... 114,624 124,175
Limited partners .......................... 12,319,953 13,265,477
------------ ------------
Total partners' equity ............... 12,434,577 13,389,652
------------ ------------
Total liabilities and partners' equity $ 13,569,438 $ 14,618,625
------------ ------------
See accompanying notes to the financial statement
-F3-
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Statement of Operations
- --------------------------------------------------------------------------------
For
the Period
September
For the For the 5, 1996
Year Ended Year Ended (Inception)
December December to December
31, 1998 31, 1997 31, 1996
----------- ----------- -----------
Net sales ................... $ 4,511,361 $ 4,113,065 $ 192,152
----------- ----------- -----------
Operating expenses:
Depreciation and amortization 1,089,969 1,062,838 24,454
Labor ....................... 592,812 549,289 11,071
Insurance ................... 194,458 246,665 5,069
Property taxes .............. 267,046 258,953 5,938
Contract management ......... 429,714 429,430 3,070
Other expenses .............. 643,847 405,414 738
----------- ----------- -----------
3,217,846 2,952,589 50,340
----------- ----------- -----------
Income from operations ...... 1,293,515 1,160,476 141,812
----------- ----------- -----------
Other income (expense):
Interest income ............. 153,983 30,812 59,479
Interest expense ............ (131,519) (147,868) (2,844)
----------- ----------- -----------
Other income (expense), net 22,464 (117,056) 56,635
----------- ----------- -----------
Net income .................. $ 1,315,979 $ 1,043,420 $ 198,447
----------- ----------- -----------
See accompanying notes to the financial statements.
-F4-
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Statement of Changes in Partners' Equity
For the Years Ended December 31, 1998 and 1997 and the Period September 5, 1996
(Inception) to December 31, 1996
- --------------------------------------------------------------------------------
Limited General
Partners Partner Total
------------ ------------ ------------
Initial capital contributions $ 13,496,513 $ 131,882 $ 13,628,395
Net income for the period ... 196,463 1,984 198,447
------------ ------------ ------------
Partners' equity,
December 31, 1996 ......... 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
------------ ------------ ------------
See accompanying notes to the financial statements.
-F5-
<PAGE>
Ridgewood Maine Hydro Partners, L.P.
Statement of Cash Flows
- --------------------------------------------------------------------------------
For
the Period
September
For the For the 5, 1996
Year Ended Year Ended (Inception)
December December to December
31, 1998 31, 1997 31, 1996
------------ ------------ ------------
Cash flows from operating
activities
Net income .................. $ 1,315,979 $ 1,043,420 $ 198,447
------------ ------------ ------------
Adjustments to reconcile net
income to net cash flows
from operating activities
Depreciation and
amortization .............. 1,089,969 1,062,838 24,454
Changes in assets and
liabilities, net of effects
of the Maine Hydro Projects
purchase:
(Increase) decrease in
accounts receivable ...... (105,371) 529,205 (163,519)
(Increase) decrease prepaid
and other current assets .. 11,832 (41,722) (9,154)
Decrease (increase) in due
to/from affiliates, net ... 16,281 (303,259) 199,609
Accounts payable and accrued
expenses .................. 40,782 (505,122) 496,782
------------ ------------ ------------
Total adjustments ........... 1,053,493 741,946 548,172
------------ ------------ ------------
Net cash provided by
operating activities ....... 2,369,472 1,785,366 746,619
------------ ------------ ------------
Cash flows from investing
activities
Payments to purchase Maine
Hydro Projects ............ -- (323,217) (13,305,178)
Capital expenditures ........ (752,613) (336,635) --
------------ ------------ ------------
Net cash used in investing
activities ................. (752,613) (659,852) (13,305,178)
------------ ------------ ------------
Cash flows from financing
activities
Cash contributed by partners -- 531,906 13,628,395
Cash distributions to
partners ................... (2,271,054) (2,012,516) --
Return of deposits ......... 800,000 -- --
Payments to reduce long-term
lease obligations .......... (134,894) (118,532) --
------------ ------------ ------------
Net cash (used in) provided
by financing activities .... (1,605,948) (1,599,142) 13,628,395
------------ ------------ ------------
Net increase (decrease) in
cash and cash equivalents ... 10,911 (473,628) 1,069,836
Cash and cash equivalents,
beginning of period ......... 596,208 1,069,836 --
------------ ------------ ------------
Cash and cash equivalents,
end of period ............... $ 607,119 $ 596,208 $ 1,069,836
------------ ------------ ------------
See accompanying notes to the financial statement
-F6-
<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 ("Ridgewood Hydro L.P."). Ridgewood
Maine Hydro Corporation, a Delaware Corporation ("RMHCorp"), is the
sole general partner of Ridgewood Hydro L.P. 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 Ridgewood Hydro
L.P. The Trusts receive funds from private placement offerings of
shares of beneficial interest and invest the net proceeds received in
independent power generation facilities.
In 1996, the general and limited partners made the following capital
contributions to Ridgewood Hydro L.P.:
General Partner RMHCorp $ 131,882
Limited Partner Trust IV 6,748,256
Limited Partner Trust V 6,748,257
-----------
$13,628,395
-----------
On December 23, 1996, in a merger transaction, Ridgewood Hydro L.P.
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. In 1997,
the limited partners made additional contributions of $531,906.
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
Ridgewood Hydro L.P. 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, 1998 and 1997, Maine Hydro, L.P. recorded
depreciation expense of $29,673 and $1,683, respectively.
-F7-
<PAGE>
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, 1998, 1997 and 1996,
Maine Hydro, L.P. recorded amortization expense of $1,060,296,
$1,061,155 and $24,454, respectively.
Income taxes
No provision is made for income taxes in the accompanying financial
statements as the income or loss of Ridgewood Hydro L.P. is passed
through and included in the tax returns of the individual partners.
3. Acquisition of the Maine Hydro Project
On December 23, 1996, in a merger transaction, Ridgewood Hydro L.P.
acquired the Maine Hydro projects. 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 acquisition of the Maine Hydro Projects was accounted for as a
purchase as of December 23, 1996, and the results of operations of the
Maine Hydro Projects have been included in Maine Hydro L.P.'s financial
statements since that date. The purchase price was allocated to the net
assets acquired, based on their respective fair values. A portion of
the purchase price ($13,311,374) was allocated to the Electric Power
Sales Contracts.
4. Obligation Under Capital Lease
Ridgewood Hydro L.P. assumed a hydroelectric facility leased pursuant
to a long-term lease agreement dated July 16, 1979, and as amended (the
"Agreement"). Upon proper notice, Ridgewood Hydro L.P. 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, Ridgewood Hydro L.P. 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 lease obligation has been recorded
in the accompanying balance sheet.
Aggregate minimum future lease payments are as follows:
1999 $ 266,400
2000 816,600
Thereafter ---
--------------
Total minimum lease payments 1,083,000
Less: Amount representing interest (145,938)
--------------
Present value of net minimum lease payments
937,062
Less: Current portion (240,644)
--------------
$ 696,418
--------------
5. Lease Commitments
The Company leases the sites of two of its hydroelectric projects under
operating leases expiring in June 2078. Total monthly payments in 1998
-F8-
<PAGE>
were the greater of $1,216 or a percentage of the revenue from the
hydroelectric project. At December 31, 1998, the future minimum rental
payments required under these leases are as follows:
1999 $ 14,592
2000 14,592
2001 14,592
2002 14,592
2003 14,592
Thereafter 1,087,104
------------------
$1,160,064
------------------
6. Power Generation Contracts
Ridgewood Hydro L.P. 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. Ridgewood Hydro L.P. 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.
Ridgewood Hydro is required to maintain standby letters of credit
totaling $300,000 under the long-term power purchase agreement.
7. Fair Value of Financial Instruments
At December 31, 1998 and 1997, the carrying value of the Trust'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.
8. Management Agreement
The Maine Hydro Projects are operated by a subsidiary of 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 maximum incentive fee payable in
a year is $112,500. The Maine Hydro Projects recorded $429,714,
$429,430 and $3,070 of expense under this arrangement during the
periods ended December 31, 1998, 1997 and 1996, 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.
-F9-
Exhibit 21 - Subsidiaries of the Registrant
Subsidiary corporations serving as general partners or managers of limited
liability entities are listed with those entities.
<TABLE>
<CAPTION>
Name of Subsidiary Type of entity Jurisdiction
of organization
<S> <C> <C>
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.
</TABLE>
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, 1998 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 27th day of March, 1999, at Naples, 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, 1998 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 27th day of March, 1999, at Naples, Florida.
/s/Richard Propper, M.D.
Richard Propper, M.D.
<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, 1998
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-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,021,168
<SECURITIES> 17,025,464<F1>
<RECEIVABLES> 617,973
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,074,826<F2>
<PP&E> 16,359,211
<DEPRECIATION> (2,073,744)
<TOTAL-ASSETS> 43,060,184
<CURRENT-LIABILITIES> 441,614<F3>
<BONDS> 4,196,455
0
0
<COMMON> 0
<OTHER-SE> 31,003,923<F4>
<TOTAL-LIABILITY-AND-EQUITY> 43,060,184
<SALES> 6,905,883
<TOTAL-REVENUES> 7,274,883
<CGS> 5,638,396
<TOTAL-COSTS> 5,638,396
<OTHER-EXPENSES> 1,964,994<F5>
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 496,658
<INCOME-PRETAX> (602,091)
<INCOME-TAX> 0
<INCOME-CONTINUING> (602,091)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (602,091)
<EPS-PRIMARY> (1,263)
<EPS-DILUTED> (1,263)
<FN>
<F1>Investment in power project partnership and limited liability company
accounted for on equity basis.
<F2>Includes $377,710 due from affiliates.
<F3>Includes $441,614 due to affiliates.
<F4>Represents Investor Shares of beneficial interest in Trust with capital
accounts of $31,098,950 less managing shareholder's accumulated deficit of
$95,027.
<F5>Includes minority interest in earnings of project.
</FN>
</TABLE>
