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 0-21304
RIDGEWOOD ELECTRIC POWER TRUST II
(Exact Name of Registrant as Specified in Its Charter)
Delaware 22-3206429
(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 $23,426,700.
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, year 2000 remediation 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.
(a) General Development of Business.
Ridgewood Electric Power Trust II (the "Trust") was organized as a Delaware
business trust on November 20, 1992 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 shares of beneficial interest in the Trust ("Investor
Shares")in a private placement offering (the "Offering") which ended on January
31, 1994, at which time it had raised approximately $23.5 million. Net of
offering fees, commissions and expenses, the Offering provided approximately
$19.4 million of net funds available for investments in the development and
acquisition of Independent Power Projects. The Trust has 580 record holders of
Investor Shares (the "Investors"). As described below in Item 1(c)(2), the Trust
(and its subsidiaries) owns equity interests in four Independent Power Projects
and a debt interest in another.
The Trust is organized similarly 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 of the Trust meet together as the Board
of the Trust and take the actions that the 1940 Act requires a board of
directors to take for a business development company. 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") or the 1940 Act.
Ridgewood Holding is the Corporate Trustee of the Trust. 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 February 27, 1993, 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 April 29, 1993, the
election and registration became effective.
(b) Financial Information about Industry Segments.
The Trust operates in only one industry segment: investing in independent
power generation and similar energy projects.
(c) Narrative Description of Business.
(1) General Description.
The Trust was formed to participate in the development, construction and
operation of independent power projects that generate electricity or related
forms of energy for sale to manufacturers, utilities and other users. The Trust
also may invest in facilities related to those projects.
The Trust has equity investments totaling approximately $10.6 million in
four Projects: (i) a waste-to-energy generating facility located in Pittsfield,
Massachusetts (the "Berkshire Project"); (ii) a municipal waste transfer station
located in Columbia County, New York, near the Berkshire Project (the "Columbia
Project"); (iii) a natural gas-fired cogeneration facility located in Monterey
County, California (the "Monterey Project") and (iv) various natural gas-fueled
engines used to power irrigation well pumps in Ventura County, California (the
"California Pumping Project").
The Trust also invested $3.5 million in a district cooling facility located
in downtown San Diego, California, that supplies chilled water for office
building central air conditioning systems (the "San Diego Project"). The Trust
sold its interest in the San Diego Project in June 1997 for $6.15 million to a
subsidiary of a Minnesota-based utility. A portion ($2.7 million) of the sale
price is represented by an 8% secured promissory note of the buyer payable
monthly through June 25, 2003.
As discussed below, the Trust is a "business development company" under the
Investment Company Act of 1940. In accounting for its Projects, it treats each
Project as a portfolio investment that is not consolidated with the Trust's
accounts. Accordingly, the revenues and expenses of each Project are not
reflected in the Trust's financial statements and only cash distributions are
included, as revenue, when received. Accordingly, the recognition of revenue
from Projects by the Trust is dependent upon the timing of distributions from
Projects by the Managing Shareholder. As discussed below at Item 5 - Market for
Registrant's Common Equity and Related Stockholder Matters, distributions from
Projects may include both income and capital components.
(2) The Trust's Investments.
(i) Berkshire Project.
On January 4, 1994, the Trust made an approximately $2.3 million equity
investment in a limited partnership, Pittsfield Investors Limited Partnership,
formed to acquire the Berkshire Project, including the assets and business of
Pittsfield Resource Recovery Facility, from Vicon Recovery Associates ("Vicon"),
the developer and former operator of the facility. The Berkshire Project is a
waste to energy plant located in Pittsfield, Massachusetts, which is in the
Berkshire Mountains, approximately 150 miles west of Boston and 175 miles north
of New York City. The facility, which has been operating since 1981, burns
municipal solid waste supplied by the City of Pittsfield ("Pittsfield"),
surrounding communities and other providers.
The Berkshire Project receives "tipping fees" paid by the waste suppliers
based on the number of tons of waste delivered to the facility. Tipping fees
paid by Pittsfield are determined under a long-term waste supply agreement which
will remain in effect until November 2004. Tipping fees paid by other waste
suppliers are based on the spot market (i.e., current market prices). The
facility generates additional revenue by selling steam produced from the waste
burning process to a nearby paper mill owned by Crane & Co., Inc. ("Crane")
under a long-term contract which will remain in effect until November 2004. The
Crane paper mill is currently the only facility in the United States which
manufactures currency paper stock used to print United States currency (as well
as currency paper stock for other governments). Crane has had an exclusive
currency contract for 114 years, although the U.S. Treasury is taking steps to
create a competing supplier under legislation requiring the U.S.
Government to create competition wherever possible.
The Trust's partners in the Berkshire Project are subsidiaries of Energy
Answers Corporation (collectively, "EAC"). EAC made an equity investment of
approximately $1.3 million in the Berkshire Partnership and also serves as
manager and operator of the facility.
The investment structure affords the Trust a preferred 15% annual return on
its investment plus a potential share of any additional cash flow. More
specifically, the Trust is entitled to an annual preferred distribution of
available cash flow, representing revenue from the Berkshire Project, (after
funding debt service, debt service reserves and operating and maintenance
expenses) in an amount equal to 15% of its investment. In the event that
distributions are insufficient to pay the 15% preferred distribution in any
given year, the shortfall will be payable out of distributions, if any, in
subsequent years. After the Trust has received its 15% preferred distribution in
any given year, EAC is entitled to an annual management fee for operating and
managing the facility in an amount equal to $300,000, escalating with inflation.
After these initial distributions have been made, the Trust is entitled to
receive an additional amount equal to 5% of its investment and then EAC is
entitled to receive an additional amount equal to 10% of the amount previously
distributed to it. Any remaining distributable cash flow for the year will be
shared equally by the Trust and EAC.
Ownership rights to the Berkshire Project are held under a long term lease
purchase agreement and related non recourse industrial revenue bond financing
agreements among the Berkshire Project, Pittsfield's industrial development
authority and others. The remaining principal amount of the bonds was
approximately $6.2 million at December 31, 1997. In addition, the Berkshire
Project is subject to additional subordinated debt obligations of approximately
$1.8 million which were issued to Vicon in connection with the acquisition of
the facility.
Distributions to the Trust from the Berkshire Project in 1998 totalled
$176,000 (a 7.5% annual return based on the pre-writedown investment level), as
compared to $360,000 in 1997. . Distributions from the Berkshire Project, after
continuing at approximately the 1997 levels for the first six months of 1998,
ceased in the third quarter of 1998. In the third quarter of 1998, EAC informed
the Trust that significant and undisclosed cost overruns in the construction of
an ash handling system for the Berkshire Project had depleted the Project's
funds, including reserve funds for closure of a landfill and other reserves. EAC
believed that Berkshire could not continue operations without significant
capital injections from its two limited partners, one of whom is the Trust. EAC
further advised the Trust that even if the Project were to continue operations
with additional contributed capital, in that event distributions from Berkshire
to the Trust would cease for an indefinite period.
The Trust requested detailed additional information and a revised operating
plan from EAC. The Trust also conducted on-site reviews by its financial and
engineering personnel. In early November 1998, EAC installed a new financial
team for the Project and offered to contribute additional capital to the
Project. EAC has proposed to the Trust that EAC would contribute the additional
capital necessary to keep the Project solvent and that the Trust would
subordinate its rights to distributions from the Project until the additional
capital contributed by EAC was recouped. The Trust has not agreed to the
proposal and the parties are in contact with each other. The Project remains in
operation but has ceased distributions to the Trust and EAC. Based on EAC's
business plan and projections for the Project, the Trust does not anticipate
that distributions to it from the Project will resume during 1999 and that it is
unlikely that any material amounts will be received by the Trust until 2004,
which is the year in which the solid waste supply agreement and the steam sales
agreement expire. Accordingly, as described at Item 7 - Management's Discussion
and Analysis of Financial Condition and Results of Operations, the Trust wrote
down the estimated fair value of the Project to zero as of December 31, 1998.
(ii) Columbia Project.
On August 31, 1994, the Trust entered into a partnership,
B-3 Limited Partnership, with affiliates of EAC, the same firm with which the
Trust participates in the Berkshire Project. The Trust made an investment of
approximately $4 million into the B-3 Limited Partnership to construct a
municipal waste transfer station located in Columbia County, New York.
The purpose of a transfer station like the Columbia Project is to provide a
facility where municipal waste collected from nearby towns by smaller, short
haul trucks can be transferred to larger, long haul trucks for more efficient
transportation of the waste to distant landfills. The primary customers for the
Columbia Project are local waste haulers who dispose of waste at local landfills
scheduled for closing under state and federal requirements. Although designed to
operate as a stand-alone facility, the additional capacity of the Columbia
Project may support expanded operations of the Berkshire Project.
During the construction period, the Trust received interest on its
investment at the rate of 12% per annum. The Columbia Project commenced
operations in January 1995. The Trust is entitled to receive a cumulative
priority return on the Trust investment of 18% per annum, with any shortfalls
being carried forward into subsequent years. Thereafter, EAC affiliates will be
entitled to receive a management fee of $175,000 escalating with inflation. Any
additional cash flow will be split 50/50 between the Trust and EAC affiliates.
Distributions to the Trust from the Columbia Project during 1998 totalled
$250,000 (a 6.2% annual return), down from $265,000 in 1997.
Returns at the Columbia Project have been impaired by repeated one-year
extensions of the closing deadlines for some local landfills. If waste can be
cheaply deposited at local landfills, there is no demand for consolidating the
waste for transfer to distant sites. Further, in early 1998 a competing waste
management company has announced its intention to acquire or develop a competing
facility nearby, although the Trust believes that the competitor has suspended
its planning for the moment. Because of the extensions and the potential
competitive threat, the Trust anticipates that volume and prices at the Columbia
Project will be adversely affected for the foreseeable future. See Item 7
Management's Discussion and Analysis of Financial Condition and Results of
Operations for additional information.
(iii) Monterey Project.
On January 9, 1995, the Trust purchased 100% of the equity interests in the
Monterey Project, which is an operating 5.5 megawatt cogeneration project
located in the City of Salinas, Monterey County, California, for a cash purchase
price of approximately $3.8 million plus the contribution of four
engine/generator sets, valued at $1.3 million, which were owned by the Trust and
cost approximately $1.6 million. The Monterey Project has been operating since
1991 and uses natural gas fired reciprocating engines to generate electricity
for sale to Pacific Gas and Electric Company under a long term contract expiring
in 2020 (the "Power Contract"). Thermal energy from the Monterey Project is used
to provide warm water to an adjacent greenhouse under a long term contract that
also terminates in 2020. For 1998, the Trust received approximately $515,000 (a
10.1% annual return), up from $784,000 for 1997 and $757,000 in 1996. The
decline in distributions reflected increased maintenance costs at the Project
from a periodic overhaul of the engines and a loss of revenues for the period of
the overhaul.
The Monterey Project is operated on behalf of the Trust by Ridgewood Power
Management Corporation, a New Jersey Corporation ("RPMCo"). RPMCo is a service
company affiliated with the Managing Shareholder, as further described at Item
10(g) - Directors and Executive Officers of the Registrant - RPMCo.
The Monterey Project is a "Qualifying Facility" under the Public Utility
Regulatory Policies Act of 1978, as amended ("PURPA"), because it is a
cogeneration facility that meets PURPA standards. 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. 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 Monterey Project sells its output to
Pacific Gas & Electric Company under the long-term contract at a formula price
set by the California Public Utilities Commission that approximates the
utility's avoided cost. Currently, the formula consists of a fixed payment for
the plant's capacity and a payment per unit of energy delivered that is tied to
85% of the cost of natural gas, the fuel used at the plant. The capacity
payments vary seasonally and are significantly higher during the summer peak
season.
California implemented a competitive power market beginning April 1,
1998 in which generators will eventually auction capacity and energy output that
is not committed for sale under long-term contracts. It is expected that
eventually the California Public Utilities Commission will change the payment
formula for many long-term contracts (including the Monterey Project's) to use
the auction prices for capacity and energy output. This would have effects on
the Project's revenues that are not predictable at this time but that might
result in a reduction in the prices paid by Pacific Gas and Electric Company for
off-peak periods.
See Item 1(a)(3) - Project Operations below for additional information
concerning a potential adverse event affecting the Project's revenues and Item 3
regarding related legal proceedings.
(iv) California Pumping Project
In March 1995, the Trust purchased 100% of the equity interests in the
California Pumping Project, which is an irrigation service Project located in
Ventura County, California, for a cash purchase price of approximately $732,000.
The Trust has made additional investments of $220,000 to purchase additional
engines and expand the Project. The California Pumping Project has been
operating since 1992 and uses 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
provides power equivalent to approximately 3 megawatts.
Until October 1998, the Trust had a management contract with the prior
operator of the Project. The prior operator received a fee 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 is 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
$105,840 to reimburse it for installation costs advanced by the operator. RPMCo
has operated the project since that time and the Trust reimburses it for its
costs and expenses.
In 1998 the Project paid $12,000 to the Trust (a 1.0% annual return), down
from $184,000 in 1997.
Ridgewood Power IV owns a package of similar engines located on different
sites and operated under identical terms by the same operator. The engines
operate independently of each other and revenues and expenses for each Trust are
segregated from those of the other.
(v) San Diego Project.
On June 25, 1997 the Trust sold its entire interest in its San Diego
Project to subsidiaries of NRG Energy, Inc. of Minneapolis, Minnesota ("NRG").
The San Diego Project is a district cooling system located in downtown San
Diego, California, that generated and supplied chilled water through sub-street
piping to approximately 10 large office buildings. The sale took the form of a
sale of all of the Trust's limited partnership interest in the limited
partnership that owned the Project and its interest in the general partner. The
sale price was $6,200,000, of which $3,500,000 was paid in cash at the closing.
The remaining $2,700,000 was paid by delivery of a secured, purchase money
promissory note of the principal NRG subsidiary purchasing the Project. The note
bears interest at 8% per year and is payable in equal monthly installments of
principal and interest through its maturity on June 25, 2003. The note is
secured by the partnership interests sold by the Trust to the NRG subsidiaries.
NRG and its subsidiaries participating in the transaction were not
affiliated with and had no material relationships with the Trust, its 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 NRG. In late 1997, a subsidiary of NRG and the Managing Shareholder
entered into negotiations for the investment by Ridgewood Electric Power Trusts
IV and V (which are also managed by the Managing Shareholder) of up to $32.5
million in up to 17 landfill-gas fueled generating plants being developed by the
NRG subsidiary. No binding agreement has been reached. The Trust is not a party
to the proposed transaction and will have no interest therein.
The Trust acquired its interest in the San Diego Project on March 21, 1994,
when it made an investment of approximately $2.3 million to acquire an 80%
interest in the Project. The Trust made additional capital contributions,
totaling approximately $1.2 million, to the Project to fund working capital and
to purchase various leased equipment. The Trust was entitled to an annual
cumulative preferred distribution of available cash flow attributable to the
facility (after funding, operating and maintenance expenses and reserves) equal
to 25% of its investment. Any additional cash flow went first to the operator of
the Project until it received 20% of the annual distribution and then the
remainder, if any, would go to the Trust. The operator also managed the facility
on a turnkey basis for a fixed payment of $100,000 per year, terminable annually
by the Trust if performance targets were not met.
The San Diego Project has been in continuous operation since 1972 and
currently sells chilled water to over 10 commercial, retail and government
office buildings connected to the facility by a closed underground pipeline loop
owned and used exclusively by the facility. The San Diego Project has 22 years
remaining on its franchise with the City of San Diego for the continued use of
the space beneath the city streets for the pipeline system. The underground
pipeline loop, which is approximately 2.5 miles in length, is capable of
providing chilled water to 25 customers or more in a 50 block area.
Distributions to the Trust from the Project for the period from January
1, 1997 to June 25, 1997 (the date the Trust sold its interest in the Project)
were $50,000. Distributions for all of 1996 totalled $618,000.
(vi) Discontinued Investments
Additional information regarding the Projects is found in the Notes to the
Financial Statements.
(3) Project Operations.
The Monterey Project's revenue from its Power Contract consists of two
components, energy payments and capacity payments. Energy payments are based on
a facility's net electric output, with payment rates usually indexed to the fuel
costs of the purchasing utility or to general inflation indices. Capacity
payments are based on either a facility's net electric output or its available
capacity. Capacity payment rates vary over the term of a Power Contract
according to various schedules.
The Berkshire Project obtains waste for fuel under a long term contract
providing it with revenues from tipping fees, which are subject to the default
risks of dealing with municipalities and small trash haulers, and sells steam to
Crane under a long-term contract. The Columbia Project obtains its revenues from
spot and contract sales of transfer station services which are dependent upon
the volume of waste delivered to it and which are sensitive to the prices of
alternative disposal methods and local economic activity.
The California Pumping Project sells its power to the farmers on whose land
its engines are situated under contracts terminable at any time on 60 days'
prior notice to the Trust. Although the Trust thus is at risk if many customers
concurrently terminate contracts, as might happen if an electric utility or
other supplier were to offer substantially discounted rates, the Trust believes
that it is currently a competitive supplier even as California begins
deregulation of electricity rates and that alternate customers can be secured in
the event contracts are terminated.
The San Diego Project sells its output to private customers under long-term
contracts that have similarities to Power Contracts in that they provide for
continuous sales and earnings over a sustained period of time. However, the
Project may be at somewhat greater risk of default from these customers as
compared to sales to utilities, which until recently had a relatively low risk
of default. Further, because customers have the option of installing or
continuing to operate their own air conditioning and heating equipment, and
because customers often prefer to operate themselves to assure control, it can
be difficult to obtain new customers.
The major costs of a 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 Berkshire, Columbia
and California Pumping Projects are managed by the development companies that
were responsible for developing those Projects, as described above. Each
development company also has an equity or an income interest in its Project
(which at the Berkshire and Columbia Projects are subordinated to the Trust's
preferred rights), which may create an additional incentive for the manager. The
Trust monitors their performance using RPMCo personnel and outside consultants.
The Trust has owned and managed the Monterey Project through a subsidiary
since its acquisition in 1994. The costs of operating this Project had been
wholly borne by the Trust as operating expenses and have not been borne by the
Managing Shareholder. RPMCo provides operations, management, purchasing,
engineering, planning and administrative services for the Projects and also
assisted in managing the San Diego Project during the first six months of 1997
prior to sale. The Managing Shareholder believes that for these Projects, where
RPMCo has necessary skills, having RPMCo manage the Projects benefits the Trust
by creating clear responsibilities and by capturing the profit component of the
management contract for the Trust.
See Item 10 - Directors and Executive Officers of the Registrant and Item
13 - Certain Relationships and Related Transactions for further information
regarding RPMCo and for the cost reimbursements received by RPMCo.
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. Steam produced by the Berkshire Project is conveyed
directly to the user by pipeline and the energy produced by the engines in the
California Pumping Project is applied directly to pumps.
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. Greenhouse demand for hot water from the Monterey Project peaks in
the winter and spring months, while demand for the San Diego Project's chilled
water for building cooling peaks in the summer and early fall. The impact of
fluctuations in the demand or supply of electrical or thermal products generated
upon the revenues of any particular Project is usually dependent on the terms of
the Power Contract pursuant to which the energy is purchased.
Generally, revenues from the sales of electric energy from a cogeneration
facility will represent the most significant portion of the facility's total
revenue. However, to maintain its status as a Qualifying Facility under PURPA,
it is imperative that the Monterey Project continue to satisfy PURPA
cogeneration requirements as to the amount of thermal products generated. See
Item 1(c)(6) - Regulatory Matters, for an explanation of these
requirements.Therefore, since the Monterey Project has only two customers (the
electric energy purchaser and the thermal products purchaser), loss of either of
these customers would probably have a material adverse effect on the Project.
From time to time Pacific Gas and Electric Company, the purchaser of
the electricity generated at the Monterey Project, has questioned whether the
Project is delivering sufficient thermal energy to its greenhouse customer to
meet PURPA requirements for Qualifying Facility status and has installed
metering devices to provide data. These inquiries are in large part caused by
the monitoring program that Pacific Gas and Electric Company undertakes as
required by the California Public Utilities Commission for data on thermal
deliveries.
The Project currently benefits from discounted natural gas rates for
its fuel supply. If it is determined that the Project did not meet PURPA and
California efficiency standards, the Project would be required to refund the
discount to Pacific Gas and Electric Company. Further, the electric company
would be able to exclude a proportionate part of its purchases of electricity
from the long-term power contract and pay at substantially lower spot rates for
that part of its purchases. This would require the Project to refund substantial
amounts. Finally, it is possible that the Power Contract could be invalidated,
which might make the Project uneconomic to operate. See Item 1(c)(4) - Trends in
the Electric Utility and Independent Power Industries for further information.
In February 1999, Pacific Gas and Electric Company notified the Trust
that it had concluded that the Monterey Project had not met those requirements
by an unspecified amount and on April 1, 1999 it brought legal proceedings
against the Trust's subsidiary that owns the Project, as described at Item 3
Legal Proceedings. The complaint only requests that the Project refund the gas
price discounts received, but an adverse decision might affect
subsequent years and might also serve as the basis for an action to invalidate
the Power Contract. The Trust is investigating the matter and is retaining
counsel. The Trust believes that the Project has met and continues to meet the
PURPA requirements and that the utility's conclusion can be supported only by
improper action by the utility. In particular, the Trust believes that Pacific
Gas and Electric Company has chosen a new location at which it is metering and
computing efficiency standards. That location is materially different from the
location at which efficiency was measured from the inception of the Project and
is located at a point where efficiency measurements necessarily would be
materially lower. The Trust also is investigating whether there are systemic and
other problems with the utility's data. Although it is too early to estimate the
precise impact of this lawsuit on the Trust, the Trust may incur material costs
in defending this proceeding and other potential action by Pacific Gas and
Electric Company.
Customers of Projects that accounted for more than 10% of annual
distributions to the Trust from operating sources in each of the last three
fiscal years are:
<TABLE>
<CAPTION>
Calendar year
1998 1997 1996
<S> <C> <C> <C>
Crane & Co., Inc. 18.0% 21.0% 14.8%
Pacific Gas & Electric Co. 54.0% 45.7% 31.9%
</TABLE>
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 sources is usually the most significant factor in
determining working capital needs.
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. See
Item 7 - Management's Discussion and Analysis of Financial Condition and Results
of Operation for additional information regarding the effects of natural gas
price increases on certain Projects owned by the Trust. 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 Berkshire Project uses municipal wastes as fuel and the
Columbia Project charges on the basis of volume of waste. The availability of
spot waste (waste delivered otherwise than under contract) depends on the costs
of other disposal alternatives.
In general, cogeneration, due to its higher efficiency, tends to be
relatively more profitable as energy costs (including natural gas) increase and
relatively less profitable as such costs decrease. Projects which use natural
gas as a fuel source bear the risk of gas price fluctuations adversely affecting
their economics.
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. The
Trust currently does not anticipate that it will have to make material
additional investments for environmental compliance. The process of preparing
the new Title V applications for air pollution licensing of existing facilities,
however, is protracted and requires modest additional expenditures for
consultants. 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. See Item 1(c)(6) Business - Narrative Description of Business
- - Regulatory Matters.
(4) Trends in the Electric Utility and Independent Power Industries
The Trust is somewhat insulated from recent deregulatory trends in the
electric industry because the Monterey Project is a Qualifying Facility with a
long-term formula-price Power Contract. The 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 California
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 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. This
alternative, which is being implemented in California, is likely to reduce
incentives to invalidate the Monterey Project's Power Contract.
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 Monterey
Project's Power Contract, it will be entitled to the benefits of the contract.
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. See the discussion at Item 1(c)(3) above as to a possibility of such
action at the Monterey Project. Even if an attempt to invalidate a Power
Contract were unsuccessful, 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. The Managing Shareholder
has indicated its interest in selling the Power Contract for the Monterey
Project and Power Contracts for two other California cogeneration facilities
owned by Ridgewood Power III, and preliminary contacts have been made with
Pacific Gas and Electric Company. No negotiations have resulted.
Finally, the Power Contract is subject to modification or rejection in the
event that the utility purchaser enters bankruptcy. There can be no assurance
that utility purchasers would not declare bankruptcy.
After the Power Contract expires in 2020 or terminates for other reasons,
the Monterey Project under currently anticipated conditions would be free to
sell its 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 Project could sell
its output or do so profitably. Because the Project is fueled by natural gas
purchased at market prices and because the Projects is relatively small-scale,
it might have cost disadvantages in competing against larger competitors that
would enjoy economies of scale. The Trust is unable to anticipate whether
thermal sales from cogeneration would offset any possible cost disadvantages in
electric generation or whether in fact the Project would have cost disadvantages
after the Power Contract ends in 2020. It is thus impossible to predict the
profitability of the Project after the scheduled termination of the Power
Contract. If the Power Contract were to be terminated now, the short-term rates
available in California's competitive electricity market are substantially less
than the costs of operation of the Monterey Project and the Project would
probably be forced to close.
The Berkshire Project's contract to supply steam terminates in 2004.
Because it is normally inefficient to transport steam over long distances, the
Trust believes that so long as the cost of suitable municipal waste does not
substantially increase or the costs of alternate fuels does not decrease far
below current levels, the Berkshire Project should be able to renew its contract
at a price comparable to or lower than the cost to Crane & Co. of running its
own boilers or using a new cogeneration facility. There is no assurance that the
Project can do so or that the customer will be financially capable of doing so.
The Columbia and California Pumping Projects do not have long-term
contracts with any of their customers and are thus exposed to short- and
long-term market fluctuations.
(5) Competition
The Monterey and Berkshire Projects, as described above, are not currently
subject to competition because those Projects have entered into long-term
agreements to sell their output at specified prices. However, the Monterey
Project could be subject to future competition to market its electricity output
if its Power Contract expires or is terminated because of a default or failure
to pay by the purchasing utility or other purchaser; due to bankruptcy or
insolvency of the purchaser; because of the failure of a Project to comply with
the terms of the Power Contract; regulatory changes; or other reasons. The
Monterey Project would then face significant competition to market its capacity
and energy output in the newly developing competitive market in California and
would face material cost pressures. The Berkshire Project may face competition
after 2004 from fuel suppliers offering alternative means of providing energy
and possibly from other cogeneration or waste-to-energy providers.
There are a large number of participants in the independent power industry.
Several large corporations specialize in developing, building and operating
Independent Power Projects. 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
Projects. 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.
The Columbia Project, as described above, faces competition from a national
waste management company much larger than itself, from local landfill operators
(if their permits to receive waste are again extended) and possibly from other
local entrepreneurs. There are few barriers to entry in the waste transfer and
management industry. The California Pumping Project is subject to competition
from the local electric utility, which serves much of Southern California and
which offers electricity at discounted rates to operate electric pumps rather
than the natural gas-fueled pumps operated by the Project. As deregulation of
the electricity market proceeds in California, the Project will also face
competition from power marketers and independent generating companies. Barriers
to entry into the electric or gas-fueled irrigation pumping industry are also
low.
(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 operates as a "business development
company" under the 1940 Act, it is also subject to provisions of that act
pertaining to such companies.
(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 Monterey Project, which sells electricity to public
utilities, is a Qualifying Facility. The San Diego Project, which did not
ordinarily sell electricity, was also a Qualifying Facility. 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 requirements of PURPA, such as minimum operating efficiency
standards and minimum use of thermal energy by customers of a cogeneration
Project. The Trust endeavors to comply with these requirements, but 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. In California, the state regulator has authorized a
comprehensive monitoring system under which electric utilities continuously
meter a Project's performance. Many California utilities, including Pacific Gas
and Electric Company, the utility that purchases the Monterey Project's electric
output, aggressively use this data to press for termination of Qualifying
Facility status or reduction of rates payable for output, and there is an
ongoing risk that the utility will assert that the Project does not qualify for
any given year. As discussed above, the Trust believes that the Monterey Project
has qualified and will continue to qualify. The other Projects do not sell
electricity to utilities or off-site customers; therefore, they need not be
Qualifying Facilities.
(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.
(D) Fuel Use Act. Projects 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. The Trust believes that the Monterey Project is coal-capable and thus
qualifies for exemption from 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.
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 Environmental Protection Agency ("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.
The Berkshire Project is not a Qualifying Facility and does not generate
electricity. However, it was operating prior to November 15, 1990 and is thus
currently exempt from the requirement to obtain sulfur dioxide allowances.
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 Massachusetts and New York, 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 will 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 will result in any material adverse effect on it.
Based on current trends, the Managing Shareholder expects that
environmental and land use regulation will become more stringent. The Trust and
the Managing Shareholder have developed limited expertise and experience in
obtaining necessary licenses, permits and approvals and may rely on co-owners of
Projects. The Trust will rely upon qualified environmental consultants and
environmental counsel retained by it or by Project co-owners 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 February 27, 1993, 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 April 29, 1993, the
election and registration became effective. As a "business development company,"
the Trust is a closed-end company (defined by the 1940 Act as a company that
does not offer for sale or have outstanding any redeemable security) that is
regulated under the 1940 Act only as a business development company. The act
contains prohibitions and restrictions on transactions between business
development companies and their affiliates as defined in that act, and requires
that a majority of the board of the company be persons other than "interested
persons" as defined in the act. The board of the Trust is comprised of Ridgewood
Power and two individuals, Ralph O. Hellmold and Jonathan C. Kaledin, who also
serve as independent trustees of Ridgewood Electric Power Trust III, and who are
Independent Panel Members for Ridgewood Electric Power Trust V but who are not
otherwise affiliated with the Trust, Ridgewood Power or any of their affiliates.
See Item 10 - Directors and Executive Officers of the Registrant.
Under the 1940 Act, Commission approval is 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. There
can be no assurance that such approval, if required, would be obtained. In
addition, a business development company may not change the nature of its
business so as to cease to be, or to withdraw its election as, a business
development company unless authorized to do so by at least a majority vote of
its outstanding voting securities.
The 1940 Act restricts the kind of investments a business development
company may make. A business development company 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 company'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.
The Managing Shareholder believes that it may no longer be necessary for
the Trust to continue its status as a business development company, because of
the Managing Shareholder's active involvement in operating Projects through the
Trust and other investment programs. Although the Managing Shareholder believes
it would be beneficial to the Trust to end the election and reduce costs of
legal compliance that do not contribute to income, the process of withdrawing
the business development company election requires a proxy solicitation and a
special vote of investors, which is also costly. Accordingly, the Managing
Shareholder does not intend at this time to request the Investors' consent to
withdrawing the business development company election. Any change in the Trust's
status will be effected only with the Investors' consent.
(iv) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not
limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are
subject to amendment or repeal. Future legislation and regulation is uncertain,
and could have material effects on the Trust.
(d) Financial Information about Foreign and Domestic Operations and Export
Sales.
The Trust has invested in Projects located in California, Massachusetts and
New York and has no foreign operations.
(e) Employees.
The operating personnel of the Monterey and California Pumping Projects are
employed by RPMCo and accordingly 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) - Directors and Executive Officers of the
Registrant - Management Agreement), 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 in which the Trust
has an interest. Ownership rights to the property associated with the Berkshire
Project are held under a long-term lease-purchase agreement and related
non-recourse industrial revenue bond financing agreements among Pittsfield's
industrial development authority and others. Upon repayment of the bonds and the
satisfaction of other conditions, the partnership which operates the facility
and in which the Trust owns an interest, will have the option to acquire the
facility for nominal consideration. The other properties are not subject to any
mortgages, liens or encumbrances. All of the Projects are described in further
detail at Item 1(c)(2).
<TABLE>
<CAPTION>
Approximate
Square
Ownership Ground Approximate Footage of Description
Interests Lease Acreage Project (Actual of
Project Location in Land Expiration of Land or Projected) Project
<S> <C> <C> <C> <C> <C> <C>
Berkshire Pittsfield, Massachusetts Leased 2004 5 30,000 Waste-to energy
facility
Columbia Columbia, New York Owned __ 44 25,000 Municipal waste
transfer station
Monterey Monterey, California Leased 2020 2 10,000 Gas-fired
cogeneration
facility
Cal. Pumping Ventura County, Leased N/A N/A N/A Natural gas fired
California or engines powering
licensed irrigation pumps
located on various
farms
</TABLE>
Item 3. Legal Proceedings.
On April 1, 1999, Pacific Gas and Electric Company, the purchaser of
the electricity generated by the Trust's Monterey Project, sued the Trust's
subsidiary that owns the Project in the Superior Court of California for the
City and County of San Francisco. Pacific Gas and Electric alleged that the
Project did not meet federal and state efficiency requirements and that
accordingly the Project was not entitled to the benefit of discounted natural
gas fuel rates allowable to qualifying cogeneration facilities. The lawsuit
claimed an unspecified amount of damages. The Trust will defend the lawsuit
vigorously. See also the discussion at Item 1(c)(3) above.
Item 4. Submission of Matters to a Vote of Security Holders.
The Trust did not submit any matters to a vote of the Investors 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 235.3775 Investor Shares of beneficial interest in the Trust
in its private placement offering of Investor Shares which closed on January 31,
1994. 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 and the Trust has no
intention to make any public offering of Investor Shares.
Investor Shares are restricted as to transferability under the Declaration,
and are restricted under federal and state laws regulating securities when the
Investor Shares are held by persons in a control relationship with the Trust.
Investors wishing to transfer Shares should also consider the applicability of
state securities laws. 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 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, III, 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 Trust 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 580 recordholders of Investor
Shares.
(c) Dividends
The Trust made distributions as follows for the years 1997 through 1998:
Year ended Year ended
December 31, December 31,
1997 1998
Total distributions to Investors $4,634,952 $1,412,273
Distributions per Investor Share $ 19,692 $6,000
Distributions to Managing Shareholder $ 46,818 $14,265
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. See Item 7 - Management's Discussion
and Analysis.
The Trust's cash flow comes primarily from distributions from Projects.
Those distributions are from cash flow of the Projects, which includes income of
Projects plus funds representing depreciation and amortization charges taken by
the Projects. Nevertheless, because the Projects are not consolidated with the
Trust for accounting purposes, all funds received from Projects are considered
to be revenue to the Trust for accounting purposes. Occasionally, distributions
may also include funds derived from operating or debt service reserves or other
non-cash charges against earnings. 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
Schedule
Selected Financial Data As of and for the years ended December 31,
1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
Total Fund Information:
Net revenue from
operating projects $ 953,576 $ 1,715,860 $2,371,208 $2,696,578 $916,588
Net income (loss) (1,704,811) 3,591,765 1,970,401 2,149,184 (1,698,844)
Net assets
(shareholders' equity) 12,132,405 15,263,754 16,353,759 16,477,149 16,760,003
Investments in Project
development and power
generation limited
partnerships 10,594,402 12,733,179 16,116,582 16,056,151 9,236,653
Note receivable 2,140,866 2,521,001 0 0 0
Total assets 12,747,675 15,432,434 16,466,241 16,521,944 16,791,571
Per Investor Share:
Revenues 4,886 $ 18,674 $10,076 $11,456 $3,894
Expenses 12,129 3,415 1,705 2,473 12,368
Net income (loss) (7,243) 15,260 8,371 9,131 (7,218)
Net asset value 51,544 64,848 69,639 70,158 71,345
Distributions to
Investors 6,000 19,692 $8,849 $10,440 $5,285
</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 elsewhere
herein. The Trust's financial statements are prepared under generally accepted
accounting principles applicable to business development companies. Accordingly,
the Trust carries its investment in the Projects it owns at fair value and does
not consolidate its financial statements with the financial statements of the
Projects. Revenue is recorded by the Trust as cash distributions are declared by
the Projects. Trust revenues may fluctuate from period to period depending on
the operating cash flow generated by the Projects and the amount of cash
retained to fund capital expenditures. Dollar amounts in this discussion are
generally rounded to the nearest $1,000.
Outlook
The U.S. electricity markets are being restructured and there is a trend
away from regulated electricity systems towards deregulated, competitive market
structures. California, where the Trust's Monterey Project operates, has passed
new legislation that permits utility customers to choose their electricity
supplier in a competitive electricity market. The Monterey Project is a
"Qualified Facility" as defined under the Public Utility Regulatory Policies Act
of 1978 and currently sells its electric output to a utility under a long-term
contract expiring in 2021. During the term of the contract, the utility may or
may not attempt to buy out the contract prior to expiration. At the end of the
contract, the Monterey Project will become a merchant plant and may be able to
sell the electric output at then current market prices. There can be no
assurance that future market prices will be sufficient to allow the Monterey
Project to operate profitably. See Item 1(c)(3) - Plant Operations for
information concerning a potential challenge to the Project's Power Contract.
The Berkshire Project receives revenue in the form of tipping fees for
waste delivered to the facility and from steam sold under a long-term contract
which expires in 2004. Tipping fees are based on spot market prices which may
fluctuate from time to time. The Project's steam customer may or may not extend
its purchases beyond the year 2004.
The Columbia Project receives revenue in the form of tipping fees for waste
delivered to the facility by local waste haulers and transferred to long haul
trucks for delivery to distant landfills. The Project's profit margins have been
reduced due to competition from national waste management companies operating in
the same region.
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
Year ended December 31, 1998 compared to year ended December 31, 1997
Total revenue decreased 73.8% to $1,150,000 in 1998 compared to $4,395,000
in 1997, primarily due to lower income from power generation projects and the
absence of a $2,546,000 gain from the sale of the San Diego Project. The Project
was sold in June 1997 for $6,150,000 and the Trust received $3,450,000 in cash
and $2,700,000 in the form of an 8% promissory note payable over six years. In
July 1997, the Trust made a special distribution to shareholders of $2,942,000.
As summarized below, income from power generation projects decreased 44.4%
to $954,000 in 1998 compared to $1,716,000 in 1997:
Project 1998 1997
- ------- ---- ----
Monterey $515,000 $ 784,000
Berkshire 176,000 360,000
Columbia 250,000 265,000
San Diego --- 50,000
California Pumping 13,000 184,000
Other --- 73,000
------------- -------------
Total $954,000 $1,716,000
======== ==========-
The decline from the Monterey Project was attributable to increased
maintenance costs from a periodic overhaul of its engines and reduced revenues
because of the scheduled shutdown.
The decline in revenue at Berkshire was a result of distributions from the
project ceasing in the third quarter of 1998. In the third quarter of 1998, the
manager of Berkshire informed the Trust that significant cost overruns in the
construction of an ash handling system for the Berkshire project had depleted
Berkshire's funds, including reserve funds for closure of a landfill and other
reserves. The project manager believed that Berkshire could not continue long
term operations without significant capital injections from its two limited
partners, one of whom is the Trust. The project manager further advised the
Trust that distributions from Berkshire to the Trust would cease. The Trust's
managing shareholder requested detailed additional information and a revised
operating plan from the project manager and conducted on-site reviews by its
financial and engineering personnel. The Trust has reviewed the short-term and
long-term viability of the Berkshire project and wrote down the carrying value
of the investment from $2,347,000 to zero.
The California Pumping Project suffered from the extraordinary rainfall
that occurred in California in the first half of 1998. In addition, 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 Trust paid $106,000 to the third
party manager to terminate the operating agreement, further reducing revenues
from the project.
The Columbia Project's 1998 and 1997 operating results were consistent.
Operating cash flow from the San Diego Project ended as a result of the 1997
sale of the Project, but interest income on the note was earned in the latter
portion of 1997 and all of 1998. In addition, in 1997 the Trust received a
$73,000 distribution from a project development limited partnership for which
the Trust had previously written off its investment.
Total expenses increased $2,054,000 (255.7%) to $2,858,000 in 1998 compared
to $804,000 in 1997, primarily due to the $2,347,000 writedown of the Berkshire
Project in 1998, partially offset by the 1997 writedown of $331,000 of certain
electric power equipment. In 1998, the Trust recorded $7,000 of interest expense
on its borrowings under its line of credit. All other 1998 Trust expenses were
comparable to 1997.
Year ended December 31, 1997 compared to year ended December 31, 1996
Total revenue increased 85.3% to $4,395,000 in 1997 compared to $2,372,000
in 1996, primarily due to the $2,546,000 gain on the sale of the San Diego
Project.
As summarized below, income from power generation projects decreased 27.6%
to $1,716,000 in 1997 compared to $2,371,000 in 1996:
Project 1997 1996
- ------- ---- ----
Monterey $ 784,000 $ 757,000
Berkshire 360,000 352,000
Columbia 265,000 515,000
San Diego 50,000 618,000
California Pumping 184,000 129,000
Other 73,000 ---
------------- --------------
Total $1,716,000 $2,371,000
========== ==========
The Monterey, Berkshire and California Pumping Projects had improved
operating results in 1997. The Columbia Project's profit margin was negatively
impacted due to increased competition from other waste management companies
operating in the region. Operating cash flow distributions from the San Diego
Project were suspended in 1997 pending the sale of the Project. In addition, the
Trust received a $73,000 distribution from a project development limited
partnership for which the Trust had previously written off its investment.
Interest and dividend income increased to $134,000 in 1997 compared to $1,000 in
1996. Interest income increased because cash was consolidated at the Trust level
in early 1997 and invested in higher yielding investment accounts.
Total expenses increased $403,000 (100.5%) to $804,000 in 1997 compared to
$401,000 in 1996, primarily due to the $331,000 write-off of certain electric
power equipment. Management fee expense increased $72,000 (21.9%) to $401,000 in
1997 compared to $329,000 in 1996 because the Managing Shareholder waived
certain management fees in 1996. All other 1997 Trust expenses were comparable
to 1996.
Liquidity and Capital Resources
During 1998, the Trust's operating activities generated $951,000 of cash
compared to $4,857,000 of cash during 1997. The change is primarily attributable
to the $3,353,000 of cash received from the sale of the San Diego Project in
1997. Cash distributions to shareholders decreased to $1,427,000 in 1998 from
$4,858,000 in 1997 due to the absence of the $2,942,000 special distribution
from the proceeds from the sale of the San Diego Project and decreases in the
monthly cash distribution rate in 1998.
In 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 $750,000. 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. The Trust borrowed $200,000 in
August 1998, $100,000 in October 1998 and an additional $50,000 in January 1999.
The current interest rate is 7.73% per year. The Trust anticipates that cash
flows from operations, other financing sources and reduced distributions will be
sufficient to repay these borrowings.
Obligations of the Trust are generally limited to payment of the management
fee to the Managing Shareholder, repayment of borrowings under the line of
credit, 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 its cash flow from operations during 1999 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 approximately $300.
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 no more than $5,000 and is estimated to be not more than approximately $4,500
for 1999.
Each of the Trust's facilities is being reviewed during the first quarter
of 1999 by an outside consultant or by personnel of Ridgewood Power Management
Corporation to determine if its electronic control systems contain software
affected by the Year 2000 problem or contain embedded components that contain
Year 2000 flaws. The Trust owns one small electric generating facility and a
number of pumping equipment sets, and interests in two waste disposal
facilities. These assets rely on mechanical and analog systems, many of which
are not expected to be vulnerable to Year 2000 problems. The facilities use
personal computers running packaged software for routine recordkeeping and data
logging, which have been upgraded as described above. To date the Trust has
discovered no other systems having a material impact on output, environmental
compliance, recordkeeping or any other material impact that have Year 2000
concerns. The Trust's share of the estimated costs of the consultant's review
and of any minor upgrades or rehabilitation is estimated at less than $25,000.
The Managing Shareholder and its affiliates do not significantly rely on
computer input from suppliers and customers and thus are not directly affected
by other companies' year 2000 compliance. However, if customers' payment systems
or suppliers' systems were adversely affected by year 2000 problems, the Trust
could be affected. For example, if the utility that purchases 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 quarter 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 or heat, but that they will decline to give
any assurance that they will be able to do so if third persons fail to meet
their obligations to those non-utility customers.
The Trust's main supply contingency is the availability of natural gas from
pipelines for fueling the Monterey electric generating plant and the irrigation
pumping sets. Accordingly the Trust is exposed to a possible interruption of gas
supply if year 2000 problems interfere with pipeline service. There is no
reasonably available alternate source of gas and accordingly an interruption of
supply would necessarily close the plant or halt the pumping sets. The Berkshire
and Columbia facilities burn or process municipal trash, the supply of which is
unlikely to be 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 or that natural gas pipelines
will fail to deliver gas 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 manualor analog control systems if Year 2000 problems
cannot be remediated. Becausethe plants are small and use simple technologies
that are not dependent on computers or date-sensitive electronics, the Trust
believes that it is unlikely that any of its facilities would be unable to
operate because of Year 2000 problems at the facility.
Based on its internal evaluations and the risks and contexts identified by
the Commission in its rules and interpretations, the Trust believes that Year
2000 issues relating to its assets and remediation program will not have a
material effect on its facilities, financial position or operations, and that
the costs of addressing the Year 2000 issues will not have a material effect on
its future consolidated operating results, financial condition or cash flows.
However, this belief is based upon current information, and there can be no
assurance that unanticipated problems will not occur or be discovered that would
result in material adverse effects on the Trust.
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 the
Monterey, Berkshire and Columbia 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
bematerially 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. In addition, the Monterey and Pump Services facilities rely on natural
gas pipelines for fuel. If the pipelines do not function properly because of
year 2000 problems, these facilities would have to reduce or cease operations.
In 1998, the Monterey and Pump Services facilities contributed approximately 58%
of the Trust's revenues.
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
2003
(U.S. $)
Note receivable from NRG $ 2,140,866
Interest rate 8%
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Balance Sheet at December 31, 1998 and 1997 F-3
Statement of Operations For the Three Years
Ended December 31, 1998 F-4
Statement of Changes in Shareholders' Equity For
the Three Years Ended December 31, 1998 F-5
Statement of Cash Flows For the Three Years
Ended December 31, 1998 F-6
Notes to Financial Statements F-7 to F-11
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 and Securities and Exchange Commission positions
applicable to business investment companies, which require the Trust's
investments in Projects to be presented on the cash method, rather than on the
equity 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.
Ridgewood Power Corporation also organized Ridgewood Electric Power Trust I
("Ridgewood Power I"), Ridgewood Electric Power Trust III ("Ridgewood Power
III"), Ridgewood Electric Power Trust IV ("Ridgewood Power IV"), 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.
The Managing Shareholder is an affiliate of Ridgewood Energy Corporation
("Ridgewood Energy"), which through its predecessor 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"), 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. Each
of these companies are controlled by Robert E. Swanson, who is their sole
manager or director. For convenience, the discussion below of the limited
liability companies, all of which are recently organized, treats each of them
and their corporate predecessor as a single entity.
Robert E. Swanson has been the President, sole director and sole
stockholder of Ridgewood Power Corporation since its inception in February 1991.
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 III, Ridgewood Power IV, Ridgewood Power V and the Growth Fund,
since their respective inceptions. Mr. Swanson has been President and registered
principal of Ridgewood Securities since it was organized in 1983. He became the
Chairman of the Board of Ridgewood Capital on its organization in 1998 and is
the Chairman of the Board of Ridgewood Capital Venture Partners, LLC and
Ridgewood Institutional Venture Partners, LLC, the two venture capital funds
managed by Ridgewood Capital. In addition, he has been President and sole
stockholder 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 III,
Ridgewood Power IV, 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 and 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 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, 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 also is Senior Vice President of Ridgewood Capital and 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 other 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 also is the
Chief Financial Officer of Ridgewood Capital and the two venture capital funds
it manages.
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 III, Ridgewood Power IV, Ridgewood Power V, the Growth Fund and the two
venture capital funds managed by Ridgewood Capitalsince 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 Ralph O. Hellmold and Jonathan C.
Kaledin. Set forth below is certain information concerning Mr. Hellmold and Mr.
Kaledin, who also serve as independent trustees of Ridgewood Power III and as
independent panel members of Ridgewood Power V. Both are independent power
programs sponsored by Ridgewood Power. Independent panel members must approve
transactions between their program and the Managing Shareholder or companies
affiliated with the Managing Shareholder, but have no other responsibilities.
Neither Mr. Hellmold nor Mr. Kaledin is otherwise affiliated with the Trust, any
of the Trust's officers or agents, the Managing Shareholder, any other Trustee,
any affiliates of the Managing Shareholder and any other Trustees, or any
director, officer or agent of any of the foregoing.
Ralph O. Hellmold, age 58, is founder, sole shareholder and President of
Hellmold Associates, Inc., an investment banking firm and investment adviser
specializing in working with troubled companies or their creditors to raise
capital, divest businesses and restructure liabilities, whether in or outside
bankruptcy. Other financial advisory services provided by Hellmold Associates,
Inc. include mergers and acquisitions advice, valuations, fairness opinions and
expert witness testimony. In addition to working with troubled companies or
their creditors, Hellmold Associates, Inc. also acts as general partner of funds
which invest in the securities of financially distressed companies.
From 1987 to 1990, when he formed Hellmold Associates, Inc., Mr. Hellmold
was a Managing Director at Prudential-Bache Capital Funding, where he served as
co-head of the Corporate Finance Group, co-head of the Investment Banking
Committee and head of the Financial Restructuring Group. From 1974 to 1987, Mr.
Hellmold was a partner at Lehman Brothers and its successors, where he worked in
the General Corporate Finance Group and co-founded the Financial Restructuring
Group. Prior thereto, he was a research analyst at Lehman Brothers and at
Francis I. du Pont & Company. He received his undergraduate degree magna cum
laude from Harvard College and an M.B.A. from Columbia University. He is a
Chartered Financial Analyst and a member of the New York Society of Security
Analysts. Mr. Hellmold is the holder of one-half share in each of Ridgewood
Power I and Ridgewood Power III, a shareholder of one-half Share in the Trust
and a limited partner or shareholder in numerous limited partnerships and a
business trust sponsored by Ridgewood Energy to invest in oil and gas
development and related businesses. Mr. Hellmold is a director of Core Materials
Corporation, Columbus, Ohio and of International Aircraft Investors, Torrance,
California.
Jonathan C. Kaledin, age 41, has been New York Regional Counsel of The
Nature Conservancy, the international land conservation organization, since
September 1995. From 1990 to June 1995, he was the Executive Director of the
National Water Funding Council ("NWFC"), an advocacy and public affairs
organization representing municipalities, businesses, financial institutions and
others on the financial aspects of clean water infrastructure projects required
by the federal Clean Water Act and the federal Safe Drinking Water Act.. Prior
to running the NWFC, Mr. Kaledin practiced law in both the private and public
sectors, specializing in environmental and real estate matters. Mr. Kaledin
received his undergraduate degree magna cum laude from Harvard College and a law
degree from New York University.
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 III, Ridgewood Power IV and Ridgewood
Power V and of an oil and gas business trust sponsored by Ridgewood Energy 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. See -- 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
To the knowledge of the Trust, there were no violations of the reporting
requirements of section 16(a) of the 1934 Act by officers and directors of the
Trust in the last fiscal year.
(g) RPMCo.
As discussed above at Item 1 - Business, RPMCo has assumed day-to-day
management responsibility for the Monterey Project, effective January 1, 1996
and operating responsibility for the Sunkist Project in October 1998 and had
assumed certain responsibilities for the San Diego Project in early 1997 until
its sale. Like the Managing Shareholder, RPMCo is controlled by Robert E.
Swanson. It has entered into an "Operation Agreement" with certain of the
Trust's subsidiaries, effective January 1, 1996, under which RPMCo, under the
supervision of the Managing Shareholder, provides the management, purchasing,
engineering, planning and administrative services for those Projects that were
previously furnished by employees of the Trust or by unaffiliated professionals
or consultants and that were borne by the Trust or Projects as operating
expenses. To the extent that those services were provided by the Managing
Shareholder and related directly to the operation of the Project, RPMCo charges
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 are 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, although it may be authorized to act on behalf of the subsidiaries
that own Projects.
The Operation Agreement does not have a fixed term and is terminable by
RPMCo, by the Managing Shareholder or by vote of a majority of 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 28 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 the Managing Shareholder's business. In 1996 and future years, the Managing
Shareholder will compensate these persons 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 allocable 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 1996 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 Trust sold 235.3775 Investor Shares (approximately $23.5 million of
gross proceeds) of beneficial interest in the Trust pursuant to a private
placement offering under Rule 506 of Regulation D under the Securities Act. The
offering closed on January 31, 1994. Further details concerning the offering are
set forth above at Item 1 -- Business.
The Managing Shareholder purchased for cash in the offering 1.45 Investor
Shares (.6 of 1% of the outstanding Investor Shares). Ralph O. Hellmold, an
Independent Trustee of the Trust, purchased for cash in the offering one-half of
a full Investor Share. By virtue of their purchases of Investor Shares, the
Managing Shareholder and Mr. Hellmold are 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.
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 such (excluding its interest in the Trust
attributable to Investor Shares it acquired in the offering). Additional
information concerning the management rights of the Managing Shareholder is at
Item 1 - Business and at 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 15% of their total capital contributions (a "15% 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 15% 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.
In 1998 and 1997, as stated at Item 5 - Market for Registrant's Common
Equity and Related Stockholder Matters, as well as in prior years, the Trust
made distributions to the Managing Shareholder (which is a member of the Board
of the Trust). In addition, the Trust and its subsidiaries paid fees and
reimbursements to the Managing Shareholder and its affiliates as follows:
<TABLE>
<CAPTION>
Fee Paid to 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C> <C>
Management Managing
fee Shareholder $ 381,594 $ 401,085 $328,952 $494,000 $495,000
Cost reimburse-
ments* RPMCo 1,470,207 1,610,806 1,207,252 0 0
Investment Managing
fee Shareholder 0 0 0 0 59,000
Placement Ridgewood
agent fee Securities
and sales Corporation
commissions 0 0 0 0 4,000
Organizational, Managing
distribution Shareholder
and offering
fee 0 0 0 0 149,000
</TABLE>
* Prior to 1996, these costs were either absorbed by the Trust or by the
Projects directly. These include all payroll, fuel and other expenses of
operating Projects that are not operated by non-affiliated managers, and an
allocation of RPMCo's overhead costs. These costs are almost exclusively paid by
the Projects and do not appear in the Trust's financial statements.
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 2.5% 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. Under the
Declaration of Trust, the annual rate fell to 1.5% per year beginning February
1, 1999.
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 in years before 1996 for payroll and other
costs of operation of the Monterey and California Pumping Projects. In 1996 and
1997, 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 Forms 8-K were 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 to the Registrant's Registration Statement on Form 10
filed with the Commission on February 27, 1993.
3B. Amended and Restated Declaration of Trust of the Registrant, is
incorporated by reference to Exhibit 4 to the Quarterly Report on
Form 10Q of the Registrant for the quarter ended September 30, 1993.
10A. Management Agreement dated as of January 4, 1993 between the
Registrant and Ridgewood Power Corporation, is incorporated by
reference to Exhibit 10 to the Registrant's Registration Statement
on Form 10 filed with the Commission on February 27, 1993.
10B. Limited Partnership Agreement of Pittsfield Investors Limited
Partnership (without exhibits), is incorporated by reference to
Exhibit 2(i) to the Form 8-K of Registrant filed with the Commission
on January 19, 1994.
10C. Asset Purchase Agreement between EAC Systems, Inc. and Vicon
Recovery Associates ("Vicon") dated as of December 23, 1992 (the
"Asset Purchase Agreement") (without exhibits), is incorporated by
reference to Exhibit 2(ii) to the Form 8-K of Registrant filed with
the Commission on January 19, 1994.
10D. First Amendment of Asset Purchase Agreement dated as of December 30,
1993 (without exhibits), is incorporated by reference to Exhibit
2(ii) to the Form 8-K of Registrant filed with the Commission on
January 19, 1994.
10E. Lease dated as of September 1, 1979 between the City of Pittsfield,
Massachusetts (acting by and through its Industrial Development
Financing Authority), is incorporated by reference to Exhibit 2(iv)
to the Form 8-K of Registrant filed with the Commission on January
19, 1994.
10F. Amended and Restated Solid Waste Disposal and Resource Recovery
Agreement dated August 6, 1979 by and among the City of Pittsfield,
Vicon and others (together with amendments dated October 26, 1984,
July 28, 1989 and December 29, 1993), is incorporated by reference
to Exhibit 2(v) to the Form 8-K of Registrant filed with the
Commission on January 19, 1994.
10G. Steam Purchase Agreement by and between Crane & Co., Inc. and Vicon
dated as of February 1, 1979 (with amendments), is incorporated by
reference to Exhibit 2(vi) to the Form 8-K of Registrant filed with
the Commission on January 19, 1994.
The Registrant is no longer a party to former Exhibits 10H
through 10M because of its sale of the San Diego Project. See
Exhibits 10P-R.
10N. Acquisition Agreement dated as of January 9, 1995 among Sunnyside
Cogen, Inc., and NorCal Sunnyside Inc., as Sellers, and RW Monterey,
Inc. and Ridgewood Electric Power Trust II, as Purchasers, is
incorporated by reference to Exhibit 2(i) to the Form 8K of
Registrant filed with the Commission on February 16, 1995.
10O. Acquisition Agreement, dated as of March 31, 1995, by and among the
Trust and its subsidiary, Pump Services Corporation, as purchasers
and Donald C. Stewart, Union Energy Corp. and Donald A. Sherman as
sellers. Incorporated by reference to Exhibit 10O to the Annual
Report on Form 10-K of the Registrant for the year ended December
31, 1995.
10P. Partnership Interest Purchase Agreement, dated as of
June 25, 1997, by and among the Trust, RSD Power
Corp., NRG San Diego, Inc., and NRG del Coronado,
Inc. Incorporated by reference to Exhibit 2.A. of
the Current Report on Form 8-K of the Registrant,
dated June 25, 1997. Exhibits and schedules are
omitted, and a list of the omitted documents is found
at page 20 of the Agreement. The Registrant agrees
to furnish supplementally a copy of any omitted
exhibit or schedule to the Partnership Interest
Purchase Agreement to the Commission upon request.
10Q. Purchase Money Promissory Note. Incorporated by
reference to Exhibit 2.B. of the Current Report
on Form 8-K of the Registrant, dated June 25, 1997.
10R. Security and Pledge Agreement, dated as of June 25, 1997, by and
among the Trust, RSD Power Corp., NRG San Diego, Inc., and NRG del
Coronado, Inc. Incorporated by reference to Exhibit 2.C. of the
Current Report on Form 8-K of the Registrant, dated June 25, 1997.
21. Subsidiaries of the Registrant. Page 66
24. Powers of Attorney Page 67
27. Financial Data Schedule Page 69
<PAGE>
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 II (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 April 14, 1999
Martin V. Quinn and Chief Financial Officer
By: /s/Kathleen P. McSherry Controller April 14, 1999
Kathleen P. McSherry
RIDGEWOOD POWER CORPORATION Managing Shareholder April 14, 1999
By: /s/Robert E. Swanson President
Robert E. Swanson
/s/Robert E. Swanson * Independent Trustee April 14, 1999
Ralph O. Hellmold
/s/Robert E. Swanson * Independent Trustee April 14, 1999
Jonathan C. Kaledin
* Robert E. Swanson, as attorney-in-fact for the Independent Trustee
<PAGE>
Ridgewood Electric Power Trust II
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 II
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 Electric Power
Trust II (the "Trust") at December 31, 1998 and 1997, and the results of its
operations and its 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.
As explained in Note 3, the financial statements include investments, valued
at $10,594,402 and $12,733,179 (87% and 83% of shareholders' equity,
respectively) as of December 31, 1998 and 1997, respectively, whose values
have been estimated by management in the absence of readily ascertainable
market values. We have reviewed the procedures used by management in arriving
at their estimate of value and have inspected underlying documentation, and,
in the circumstances, we believe the procedures are reasonable and the
documentation appropriate. However, those estimated values may differ
significantly from the values that would have been used had a ready market for
the investments existed, and the differences could be material to the
financial statements.
/s/ PricewaterhouseCoopers LLP
-F2-
<PAGE>
Ridgewood Electric Power Trust II
Balance Sheet
- -------------------------------------------------------------------------
December 31,
----------------------------
1998 1997
------------ ------------
Assets:
Investments in power generation projects . $ 10,594,402 $ 12,733,179
Cash and cash equivalents ................ -- 175,818
Notes receivable from sale of investment . 2,140,866 2,521,001
Due from affiliates ...................... 8,819 --
Other assets ............................. 3,588 2,436
------------ ------------
Total assets .................... $ 12,747,675 $ 15,432,434
------------ ------------
Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses .... $ 100,897 $ 32,186
Borrowings under line of credit facility . 300,000 --
Due to affiliates ........................ 214,373 136,494
------------ ------------
Total liabilities ............... 615,270 168,680
------------ ------------
Commitments and contingencies
Shareholders' equity:
Shareholders' equity (235.3775 shares
issued and outstanding)
12,212,324 15,312,360
Managing shareholder's accumulated deficit (79,919) (48,606)
------------ ------------
Total shareholders' equity ...... 12,132,405 15,263,754
------------ ------------
Total liabilities and
shareholders' equity .......... $ 12,747,675 $ 15,432,434
------------ ------------
See accompanying notes to financial statements.
-F3-
<PAGE>
Ridgewood Electric Power Trust II
Statement of Operations
- --------------------------------------------------------------------------------
Year Ended December 31,
----------------------------------------
1998 1997 1996
----------- ----------- -----------
Revenue:
Income from power
generation projects ..... $ 953,576 $ 1,715,860 $ 2,371,208
Gain on sale of RSD
Power Partners, L.P. .... -- 2,545,846 --
Interest income ........... 196,480 133,770 540
----------- ----------- -----------
Total revenue ......... 1,150,056 4,395,476 2,371,748
----------- ----------- -----------
Expenses:
Writedown of investment
in Pittsfield Investors
Limited Partnership ..... 2,347,330 -- --
Writedown of electric power
equipment ............... -- 331,018 --
Management fee ............ 381,594 401,085 328,952
Accounting and legal fees . 75,111 39,853 31,750
Interest .................. 7,081 -- --
Miscellaneous ............. 43,751 31,755 40,645
----------- ----------- -----------
Total expenses ........ 2,854,867 803,711 401,347
----------- ----------- -----------
Net (loss) income ..... $(1,704,811) $ 3,591,765 $ 1,970,401
----------- ----------- -----------
See accompanying notes to financial statements.
-F4-
<PAGE>
Ridgewood Electric Power Trust II
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 ... $ 16,513,521 $ (36,372) $ 16,477,149
Capital contributions 10,000 -- 10,000
Cash distributions .. (2,082,754) (21,037) (2,103,791)
Net income .......... 1,950,697 19,704 1,970,401
------------ ------------ ------------
Shareholders' equity,
December 31, 1996 . 16,391,464 (37,705) 16,353,759
Cash distributions .. (4,634,952) (46,818) (4,681,770)
Net income .......... 3,555,848 35,917 3,591,765
------------ ------------ ------------
Shareholders' equity,
December 31, 1997 . 15,312,360 15,263,754
(48,606)
Cash distributions .. (1,412,273) (14,265) (1,426,538)
Net loss ............ (1,687,763) (17,048) (1,704,811)
------------ ------------ ------------
Shareholders' equity,
December 31, 1998 . $ 12,212,324 $ (79,919) $ 12,132,405
------------ ------------ ------------
See accompanying notes to financial statements.
-F5-
<PAGE>
Ridgewood Electric Power Trust II
Statement of Cash Flows
- --------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------
1998 1997 1996
----------- ----------- -----------
Cash flows from operating activities:
Net (loss) income ............. $(1,704,811) $ 3,591,765 $ 1,970,401
----------- ----------- -----------
Adjustments to reconcile net
(loss) income to cash flows
from operating activities:
Writedown of investment in
Pittsfield Investors
Limited Partnership ....... 2,347,330 -- --
Writedown of electric power
equipment ................. -- 331,018 --
Gain on sale of RSD Power
Partners, L.P. ............ -- (2,545,846) --
Proceeds from sale of
investment in RSD Power
Partners, L.P., net ...... -- 3,353,121 --
Proceeds from note receivable 380,135 178,999 --
Investments in power
generation projects ....... (208,553) (123,872) (60,431)
Changes in assets and
liabilities:
(Increase) decrease in
other assets .............. (1,152) 16,205 14,159
Increase in due from
affiliates ................ (8,819) -- --
Increase (decrease) in
accounts payable and
accrued expenses .......... 68,711 (80,296) 67,687
Increase in due to affiliates 77,879 136,494 --
----------- ----------- -----------
Total adjustments ........... 2,655,531 1,265,823 21,415
----------- ----------- -----------
Net cash provided
by operating activities ... 950,720 4,857,588 1,991,816
----------- ----------- -----------
Cash flows from financing
activities:
Proceeds from shareholders'
contributions ............... -- -- 10,000
Borrowings under line of
credit facility ............. 300,000 -- --
Cash distributions to
shareholders ................ (1,426,538) (4,681,770) (2,103,791)
----------- ----------- -----------
Net cash used in financing
activities ................ (1,126,538) (4,681,770) (2,093,791)
----------- ----------- -----------
Net (decrease) increase in
cash and cash equivalents . (175,818) 175,818 (101,975)
Cash and cash equivalents,
beginning of year ............. 175,818 -- 101,975
----------- ----------- -----------
Cash and cash equivalents, end
of year ....................... $ -- $ 175,818 $ --
----------- ----------- -----------
Non-cash activities:
Note received from sale of
RSD Power Partners, L.P. ...... $ -- $ 2,700,000 $ --
----------- ----------- -----------
See accompanying notes to financial statements.
-F6-
<PAGE>
Ridgewood Electric Power Trust II
Notes to Financial Statements
- --------------------------------------------------------------------------------
1. Organization and Purpose
Nature of business
Ridgewood Electric Power Trust II (the "Trust") was formed as a Delaware
business trust on November 20, 1992, 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 January 4, 1993 and discontinued its offering of shares on January 31,
1994.
The Trust was organized to invest in independent power generation
facilities and in the development of these facilities. These independent
power generation facilities include cogeneration facilities which produce
electricity and thermal energy and other power plants that use various fuel
sources (except nuclear). The power plants sell electricity and, in some
cases, thermal energy to utilities and industrial users under long-term
contracts.
"Business Development Company" election
Effective April 29, 1993, the Trust elected to be treated as a "Business
Development Company" under the Investment Company Act of 1940 and
registered its shares under the Securities Exchange Act of 1934.
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.
Investments in power generation projects
The Trust holds investments in power generation projects which are stated
at fair value. Due to the illiquid nature of the investments, the fair
values of the investments are assumed to equal cost, unless current
available information provides a basis for adjusting the carrying value of
the investments.
Revenue recognition
Income from investments is recorded when distributions are declared.
Interest income is recorded as earned.
Cash and cash equivalents
The Trust considers all highly liquid investments with maturities when
purchased of three months or less as cash and cash equivalents.
Due diligence costs relating to potential power project investments Costs
relating to the due diligence performed on potential power project
investments are initially deferred, until such time 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.
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 Trusts.
Reclassification
Certain amounts presented in prior years have been reclassified for
comparative purposes.
-F7-
<PAGE>
3. Investments in Power Generation Projects
The Trust had the following investments in power generation and other
projects:
December December
31, 1998 31, 1997
----------- -----------
Pittsfield Investors Limited Partnership $ -- $ 2,347,330
B-3 Limited Partnership ................ 4,001,843 4,001,843
Sunnyside Cogeneration Partners, L.P. .. 5,425,020 5,432,339
California Pumping Project ............. 1,167,539 951,667
----------- -----------
$10,594,402 $12,733,179
----------- -----------
The Trust's distribution income from the projects was as follows:
For the Year Ended December 31,
-------------------------------------
1998 1997 1996
---------- ---------- ----------
Pittsfield Investors Limited Partnership $ 175,725 $ 359,494 $ 351,451
B-3 Limited Partnership ................ 250,000 265,000 515,000
Sunnyside Cogeneration Partners, L.P. .. 515,403 784,449 757,498
California Pumping Project ............. 12,448 183,623 129,179
RSD Power Partners, L.P. ............... -- 50,000 618,080
Project development limited partnerships -- 73,294 --
---------- ---------- ----------
$ 953,576 $1,715,860 $2,371,208
---------- ---------- ----------
Pittsfield Investors Limited Partnership (known as the Berkshire project)
On January 4, 1994, the Trust made a limited partnership investment in this
partnership, which was formed to acquire an operating facility, located in
Pittsfield, Massachusetts. The facility, which has been operating since
1981, burns municipal solid waste supplied by the City of Pittsfield and
surrounding communities. The facility has a long-term supply agreement with
the City of Pittsfield, which expires in November 2004, under which the
City makes payments to the facility for receiving the waste. The facility
generates additional revenue by selling steam produced from the waste
burning process to a nearby paper mill under a long-term contract, which
also expires in November 2004.
In exchange for its investment, the Trust is entitled to receive annually a
preferred distribution from available cash from the facility equal to 15%
of its investment. In the event that in any given year available net cash
flow from the project does not at least equal the amount of the preferred
minimum return, the amount of such shortfall is payable on a priority basis
out of any available net cash flow in subsequent years. The Trust may also
be entitled to receive additional distributions from any net cash flow in
excess of the 15% return on its investment. The aggregate cost of the
Trust's investment in the partnership was $2,347,330. The Trust received
distributions of $175,725, $359,494 and $351,451 from the project for the
years ended December 31, 1998, 1997 and 1996, respectively.
In 1998, the City of Pittsfield closed the nearby landfill to which the
project had sent the ash residue from the burning of the municipal solid
waste. The additional cost of transporting the ash to other landfills has
significantly reduced the cash flows generated by the project. Although the
project manager is actively seeking ways to enhance the project's revenue,
the ability of the project to make distributions to the Trust in the future
is questionable. Accordingly, in 1998 the Trust recorded a writedown of
$2,347,330 to reduce the estimated fair value of the project to zero.
B-3 Limited Partnership (known as the Columbia project) On August 31, 1994,
the Trust made a limited partnership investment in this partnership, which
was formed to construct and operate a municipal waste transfer station,
located in Columbia County, New York. The project commenced operations in
January 1995.
-F8-
<PAGE>
In exchange for its investment, the Trust is entitled to receive annually a
preferred distribution of available net cash flow from the facility equal
to 18% of its investment. In the event that in any given year available net
cash flow from the project does not at least equal the amount of the
preferred minimum return, the amount of such shortfall is payable on a
priority basis out of any available net cash flow in subsequent years. The
Trust may also be entitled to receive additional distributions from any net
cash flow in excess of the 18% return on its investment. The aggregate cost
of the Trust's investment in the partnership was $4,001,843. The Trust
received distributions of $250,000, $265,000 and $515,000 from the project
for the years ended December 31, 1998, 1997 and 1996, respectively.
Sunnyside Cogeneration Partners, L.P. (known as the Monterey project) On
January 9, 1995, the Trust acquired 100% of the existing partnership
interests of Sunnyside Cogeneration Partners, L.P., which owns and operates
a 5.5 megawatt electric cogeneration facility, located in Monterey County,
California. Electricity is sold to the Pacific Gas and Electric Company
("PG&E") under a long term contract expiring in 2020. The initial cost of
the investment was $5,308,467, which consisted of $3,782,000 of cash,
$226,467 of due diligence and other costs, and electric power equipment
valued at $1,300,000. The aggregate cost of the Trust's investment at
December 31, 1998 and 1997 was $5,425,020 and $5,432,339, respectively. The
Trust received distributions of $515,403, $784,449 and $757,498 from the
project for the years ended December 31, 1998, 1997 and 1996, respectively.
In February 1999, PG&E notified the Monterey Project that it had concluded
that the Monterey Project had not met certain thermal energy delivery
requirements of a cogeneration facility. On April 1, 1999 it brought legal
proceedings against the Trust's subsidiary that owns the Project. The
complaint only requests that the Project refund the gas price discounts
received, but an adverse decision might affect subsequent years
and might also serve as the basis for an action to invalidate the Power
Contract. The Trust is investigating the matter and is retaining counsel.
The Trust believes that the Project has met and continues to meet the
requirements and that the utility's conclusion can be supported only by
improper action by the utility. In particular, the Trust believes that PG&E
has chosen a new location at which it is metering and computing efficiency
standards. That location is materially different from the location at which
efficiency was measured from the inception of the Project and is located at
a point where efficiency measurements necessarily would be materially
lower. The Trust also is investigating whether there are systemic and other
problems with the utility's data. Although it is too early to estimate the
precise impact of this lawsuit on the Trust, the Trust may incur material
costs in defending this proceeding and other potential action by Pacific
Gas and Electric Company.
California Pumping Project
On March 31, 1995, the Trust acquired a package of natural gas and diesel
engines which drive deep irrigation well pumps in Ventura County,
California. 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. 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 Trust paid $105,840 to the third party manager
to terminate the operating agreement. The total investment in the project
at December 31, 1998 and 1997 was $1,167,539 and $951,667 and the project
has an equivalent of 3 megawatts of power. The operator pays for fuel,
maintenance, repair and replacement. The Trust received distributions of
$12,448, $183,623, and $129,179 from the project for the years ended
December 31, 1998, 1997 and 1996, respectively.
RSD Power Partners, L.P. (known as the San Diego project) On March 21,
1994, the Trust made a limited partnership investment in the partnership,
which was formed to acquire an operating facility, located in San Diego,
California. The facility, which has been operating since 1972, sells
chilled water used in the central air conditioning of commercial, retail
and government office buildings connected by a closed underground pipeline
loop owned and used exclusively by the San Diego project.
In exchange for its investment, the Trust was entitled to receive annually
the greater of either 80% of net profits, as defined, from the project or a
preferred minimum return of 25% on its total investment. The aggregate cost
of the Trust's investment in the partnership was $3,507,275. The Trust
received distributions of $50,000 and $618,080 from the project for the
years ended December 31, 1997 and 1996, respectively.
-F9-
<PAGE>
On June 25, 1997, the Trust sold its entire partnership interest in RSD
Power Partners, L.P. to subsidiaries of NRG Energy, Inc. of Minneapolis,
Minnesota for $6,150,000. The Trust received $3,450,000 in cash and
$2,700,000 in the form of an 8% promissory note payable monthly over six
years. The sale resulted in a gain of $2,545,846, after deducting
transaction costs of $96,879.
Investments in project development limited partnerships In prior years, the
Trust made investments in several limited partnerships with other major
participants in the power industry to provide access to investments in
larger projects in which these participants would take the leading role in
the acquisition or development of such projects. In 1994, the Trust wrote
off its investment in these limited partnerships of $1,065,798.
In 1997, a major participant refunded $73,294 to the Trust of its original
capital investment of $101,850. The refund was recorded as income from
power generating projects for the year ended December 31, 1997.
4. Electric Power Equipment
The Trust purchased various used electric power generation equipment to be
used in potential power generation projects. The equipment was held in
storage and depreciation was not recorded. In 1997, the Trust wrote-off the
equipment and recorded a loss of $331,018.
5. Line of Credit Facility
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 $750,000. At
December 31, 1997, there were no borrowings outstanding under the credit
facility. In 1998, the Trust borrowed $300,000 under the credit facility.
Outstanding borrowings bear interest at LIBOR plus 2.5% (7.73% at December
31, 1998). These borrowing must be repaid by July 1, 1999. 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.
6. Transactions With Managing Shareholder And Affiliates
The Trust pays to the managing shareholder a distribution and offering fee
in an amount up to 5% of each capital contribution made to the Trust. This
fee is intended to cover legal, accounting, consulting, filing, printing,
distribution, selling and closing costs for the offering of the Trust.
These fees were recorded as a reduction in shareholders' capital
contributions.
The Trust also pays to the managing shareholder an investment fee of 2% of
each capital contribution made to the Trust. The fee is payable to the
managing shareholder for its services in investigating and evaluating
investment opportunities and effecting transactions for investing the
capital of the Trust.
The Trust entered into a management agreement with the managing
shareholder, under which the managing shareholder renders certain
management, administrative and advisory services and provides office space
and other facilities to the Trust. As compensation to the managing
shareholder, the Trust paid to the managing shareholder an annual
management fee equal to 2.5% 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 management fees to the managing
shareholder of $381,594, $401,085 and $328,952, respectively. Under the
terms of the management agreement, the annual management fee decreases to
1.5% of the net asset value of the Trust effective February 1, 1999.
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 in respect of the year an amount equal
to 15% of their equity contribution. Thereafter, the managing shareholder
is entitled to receive 20% of the
-F10-
<PAGE>
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.
The managing shareholder owns 1.45 shares of the Trust with a cost of
$121,800. In conjunction with the offering of the Trust shares, commissions
and placement fees of $248,807 were earned by Ridgewood Securities
Corporation, an affiliate of the managing shareholder.
In 1996, 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 power
generation project operated by the Trust. Ridgewood Management charges the
project 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 year ended December
31, 1998, 1997 and 1996, Ridgewood Management charged Sunnyside
Cogeneration Partners $119,823, $94,516 and $92,015, respectively, for
overhead items allocated in proportion to the amount invested in projects
managed. During the three month period ended December 31, 1998, Ridgewood
Management charged the California Pumping Project $25,973 for overhead
items allocated in proportion to the amount invested in projects managed.
Ridgewood Management also charged Sunnyside Cogeneration Partners and the
California Pumping Project for all of the remaining direct operating and
non-operating expenses incurred during the periods.
-F11-
<PAGE>
EXHIBIT 21 - SUBSIDIARIES OF THE REGISTRANT
Subsidiary corporations that serve as general partners of limited partnerships
are listed with those partnerships.
Name of subsidiary Type of Jurisdiction of
entity organization
Pittsfield Investors Limited limited partnership Delaware Partnership
B-3 Limited Partnership limited partnership Delaware
Berkshire B-3 Inc. corporation Delaware (general partner)
Sunnyside Cogeneration limited partnership Delaware Partners, L.P.
RW Monterey, Inc. corporation Delaware (general partner)
Pump Services Company, L.P. limited partnership Delawar
Ridgewood Pump Services corporation Delaware Corporation
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, Ralph O.
Hellmold, 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 II and of
Ridgewood Electric Power Trust III, 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/Ralph O. Hellmold
Ralph O. Hellmold
<PAGE>
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, Jonathan C.
Kaledin, 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 II and of
Ridgewood Electric Power Trust III, 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, atNaples, Florida.
/s/Jonathan C. Kaledin
Jonathan C. Kaledin
<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> 0000895993
<NAME> RIDGEWOOD ELECTRIC POWER TRUST II
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 0
<SECURITIES> 12,735,268<F1>
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 12,407<F2>
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 12,747,675
<CURRENT-LIABILITIES> 615,270<F3>
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 12,132,405<F4>
<TOTAL-LIABILITY-AND-EQUITY> 12,747,675
<SALES> 0
<TOTAL-REVENUES> 1,150,056<F5>
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 2,847,867
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7,081
<INCOME-PRETAX> (1,704,811)<F5>
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,704,811)<F5>
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,704,811)<F5>
<EPS-PRIMARY> (7,242)
<EPS-DILUTED> (7,242)
<FN>
<F1>Investments in power project partnerships and face value($2,140,866)of note
for sale of San Diego Project.
<F2>Includes $8,819 due from affiliates.
<F3>Includes $214,373 due to affiliates.
<F4>Represents Investor Shares of beneficial interest in Trust with
capital accounts of $12,212,324 less managing shareholder's accumulated deficit
of $79,919.
<F5>Includes writedown of investment of $2,347,330.
</FN>
</TABLE>
