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, 1996
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.
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 March 21, 1997 was
$23,426,700.
Exhibit Index is located on Page 55.
<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 and other matters relating to the Trust's future
results and the business climate and are found, among
other places, at Items 1(c)(3), 1(c)(4), 1(c)(6)(ii) and 7.
In order to make these statements, the Trust has had to make
assumptions as to the future. It has also had to make
estimates in some cases about events that have already
happened, and to rely on data that may be found to be
inaccurate at a later time. Because these forward-looking
statements are based on assumptions, estimates and
changeable data, and because any attempt to
predict the future is subject to other errors, what happens
to the Trust in the future may be materially different from
the Trust's statements here.
The Trust therefore warns readers of this document that they
should not rely on these forward-looking statements without
considering all of the things that could make them
inaccurate. The Trust's other filings with the Securities
and Exchange Commission and its Confidential Memorandum
discuss many (but not all) of the risks and uncertainties
that might affect these forward-looking statements.
Some of these are changes in political and economic
conditions, federal or state regulatory structures,
government taxation, spending and budgetary policies,
government mandates, demand for electricity and thermal
energy, the ability of customers to pay for energy received,
supplies of fuel and prices of fuels, operational status of
plant, mechanical breakdowns, availability of labor and the
willingness of electric utilities to perform existing power
purchase agreements in good faith. Some of these
cautionary factors that readers should consider are
described below at Item 1(c)(4) - Trends in the
Electric Utility and Independent Power Industries.
By making these statements now, the Trust is not making any
commitment to revise these forward-looking statements to
reflect events that happen after the date of this document
or to reflect unanticipated future events.
(a) General Development of Business.
Ridgewood Electric Power Trust II, the Registrant hereunder
(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 whole and fractional shares of beneficial
interest in the Trust ("Investor Shares") at $100,000 per
Investor Share. The Trust terminated its private placement
offering of Shares (the "Offering") 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 479 record holders of Investor
Shares (the "Investors"). As described below in Item 1(c)(2),
the Trust (and its subsidiaries) have invested its net funds in
five Independent Power Projects.
Ridgewood Power Corporation (the "Managing Shareholder"), a
Delaware corporation, is the Managing Shareholder of the Trust
and as such has direct and exclusive discretion in the 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).
Ridgewood Holding, as 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.
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. 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 electric power projects
that generate electricity for sale to utilities and other users,
and in some cases, to provide heat energy or chilled water as
well to users.
Historically, producers of electric power in the United
States consisted of regulated utilities and of industrial users
that produced electricity to satisfy their own needs. The
independent power industry in the United States was created by
federal legislation passed in response to the energy crises of
the 1970s. The Public Utility Regulatory Policies Act of 1978,
as amended ("PURPA"), requires utilities to purchase electric
power from "Qualifying Facilities" (as defined in PURPA),
including "cogeneration facilities" and "small power producers,"
and also exempts these Qualifying Facilities from most utility
regulatory requirements. Under PURPA, Projects that are
Qualifying Facilities are generally not subject to federal
regulation, including the Public Utility Holding Company Act of
1935, as amended, and state regulation. Furthermore, PURPA
generally requires electric utilities to purchase electricity
produced by Qualifying Facilities at the utility's avoided cost
of producing electricity (i.e., the incremental costs the utility
would otherwise face to generate electricity itself or purchase
electricity from another source).
The Trust has invested approximately $16.1 million of its
funds in five Projects: (i) a waste-to-energy generating
facility located in Pittsfield, Massachusetts (the "Berkshire
Project"); (ii) 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"); (iii) a municipal waste transfer station located in
Columbia County, New York, near the Berkshire Project (the
"Columbia Project"); (iv) a natural gas-fired cogeneration
facility located in Monterey County, California (the "Monterey
Project") and (v) various natural gas-fueled engines used to
power irrigation well pumps in Ventura County, California (the
"Sunkist Project"). The Trust has also invested approximately
$331,000 to acquire, store and transport used electric power
generation equipment for future use at its Projects.
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 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, 1996. 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
1996 totalled $351,000 (a 14.9% annual return), down from
$447,000 in 1995 and $482,000 in 1994. A decision to retain cash
flow for capital expenditures, as described at Item 7 -
Management's Discussion and Analysis of Results of Operations,
caused the decrease from 1995 to 1996.
(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 one-year extensions of the closing
deadlines for some local landfills have temporarily reduced
anticipated demand at the facility, the process of closing many
municipal landfills in the Albany area and the Berkshire region
is expected to reduce the number of alternative disposal sites
and increase the costs of alternative sites relative to the
Columbia Project. 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 1996 totalled $515,000
(approximately a 12.9% return). For the period ended December
31, 1995, the Trust had received approximately $510,000 in
distributions from the Columbia Project.
(iii) San Diego Project.
On March 21, 1994, the Trust made an investment of
approximately $2.3 million to acquire an 80% interest in a
limited partnership, RSD Power Partners, L.P. (the "San Diego
Partnership"), formed to acquire the San Diego Project, including
the assets and business of San Diego Central Cooling Company,
from a subsidiary of Pacific Generating Corporation, the former
owner and operator of the limited partnership. The Trust made
additional capital contributions, totaling approximately $1.2
million, to the San Diego Partnership to fund working capital and
to purchase various leased equipment. 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 is a fundamental part of the infrastructure of
downtown San Diego in that the chilled water provided by the
facility is used in the central air conditioning systems of a
significant portion of the downtown commercial space. The San
Diego Project has 24 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 facility has the
potential to substantially expand its number of customers and
volume of chilled water sales. 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.
The Trust's partner in the San Diego Project is Wilton
Technology Associates ("Wilton"), which is owned by Steven Jay
Mueller. The investment structure affords the Trust a preferred
25% annual return on its investment plus a potential share of any
additional net cash flow. More specifically, the Trust is
entitled to an annual preferred distribution of available cash
flow attributable to the facility (after funding, operating and
maintenance expenses and reserves) in an amount equal to 25% of
its investment. In the event that distributions are insufficient
to pay the 25% preferred distribution in any given year, the
shortfall will be payable out of any distributions in subsequent
years. After the Trust has received its 25% preferred
distribution in any given year, Wilton will be entitled to
receive any further distributions during the year until it has
received an amount equal to 25% of the amount distributed to the
Trust. Thereafter, distributions will be shared on a basis of
80% to the Trust and 20% to Wilton. Wilton 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. During 1996, the Trust's affiliate, Ridgewood
Power Management Corporation ("RPMC"), began taking on
responsibility for operation and maintenance and Wilton's
activities were focused on marketing and expansion planning.
Distributions to the Trust from the Project in 1996 totaled
$618,000 (a 17.6% annual return on investment), down from
$1,027,000 in 1995 and $435,000 in 1994. The decrease reflected
the loss of a significant customer, higher natural gas prices and
a relatively cool summer. In early 1997 the Trust entered into
discussions with Wilton about modifying or terminating the
management agreement and the prospects for obtaining additional
customers (which might require a material expansion of the
Project).
(iv) 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 (the "Power
Contract"). Thermal energy from the Monterey Project is used to
provide warm water to an adjacent greenhouse under a long term
contract. For 1996, the Trust had received approximately $757,000
in distributions (a 14.3% annual return) from the Monterey
Project, up from $607,000 in 1995. The Trust's investment in
operating and maintenance improvements was the primary reason for
the increase.
(v) Sunkist Project
In March 1995, the Trust purchased 100% of the equity
interests in the Sunkist 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 Sunkist 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 Sunkist Project
will provide power equivalent to approximately .3 megawatts.
The Trust has entered into a management contract with the
prior operator of the Project 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. The
Trust receives 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, receives
the remainder. In 1996, the Project paid $129,000 to the Trust
(a 13.6% annual return), up from $105,742 in 1995.
(vi) Discontinued Investments
The Trust made an investment of $811,000 in a partnership
organized for the purpose of pursuing the acquisition of existing
larger Projects. The Trust also made equity investments of
totalling $254,000 in two other partnerships organized for the
purpose of pursuing the development and construction of larger
Projects. Despite substantial efforts, none of these
partnerships produced an investment opportunity which was
satisfactory to the Trust, and the Trust terminated its
participation in these partnerships and wrote off those
investments in December 1994. Further, in 1994 the Trust wrote
off an additional $332,000 with respect to development for a
Project which failed to meet the requirements for construction.
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 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 Trust 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 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 Sunkist 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
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 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 Sunkist 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 subordinated to
the Trust's preferred rights, which may create an additional
incentive for the manager. The Trust monitors their performance
using its own personnel and outside consultants. At the San
Diego Project, a similar arrangement was in place, but the Trust
has taken on the major portion of the operating and management
responsibility beginning in 1996.
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. Effective January 1, 1996, the Managing Shareholder
organized RPMC and has caused the Trust's subsidiaries to hire
RPMC to provide management, purchasing, engineering, planning and
administrative services for the Monterey Project and operating,
administrative and maintenance functions for the San Diego
Project. RPMC also provides accounting support for the Sunkist
Project. The Managing Shareholder believes that for these
Projects, where RPMC has necessary skills, having RPMC 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 Officers and Item 13 - Certain
Relationships and Related Transactions for further information
regarding RPMC and for the cost reimbursements received by RPMC.
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. Chilled
water produced by the San Diego Project and steam produced by the
Berkshire Project are conveyed directly to the user by pipeline
and the energy produced by the engines in the Sunkist 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.
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.
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
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.
Although the capital costs and other expenses of environmental
protection may constitute a significant portion of the costs of a
Project, the Trust believes that those costs as imposed by
current laws and regulations have been and will continue to be
largely incorporated into the prices of its investments and that
it accordingly has adjusted its investment program so as to
minimize material adverse effects. If future environmental
standards require that a Project spend increased amounts for
compliance, such increased expenditures could have an adverse
effect on the Trust to the extent it is a holder of such
Project's equity securities. See Item 1(c)(6) - Business -
Narrative Description of Business - Regulatory Matters.
(4) Trends in the Electric Utility and Independent Power
Industries
As a consequence of federal and state moves to deregulate
large areas of the electric power industry and the existence,
spurred by PURPA, of private competitors to electric utilities
in the market for generating electricity, a number of
interrelated trends are occurring. In accordance with industry
usage, sales of electricity by generators to utilities or other
marketers of electricity are referred to as "wholesale"
transactions and sales by generators, utilities or others to end
users of electricity are referred to as "retail" transactions.
Continued Deregulation of the Generating Market.
The Comprehensive Energy Policy Act of 1992 (the "1992
Energy Act") encourages electric utilities to expand their
wholesale generating capacity by removing some, but not all, of
the limitations on their ownership of new generating facilities
that qualify as "exempt wholesale generators" and on their
ability to participate in Independent Power Projects. See Item
1(c)(6)(ii) -- Energy Regulation -- the 1992 Energy Act. Many
state electric utility regulators are considering plans to
further encourage investment in wholesale generators and to
facilitate utility decisions to spin off or divest generating
capacity from the transmission or distribution businesses of the
utilities. As a result, Independent Power Projects in the future
will face competition not only from other Independent Power
Projects seeking to sell electricity on a wholesale basis but
also from exempt wholesale generators, electric utilities with
excess capacity and independent generators spun off or otherwise
separated from their parent utilities. Large-scale Projects that
can sell large amounts of electricity or that have excellent
reliability records or favorable locations may have competitive
advantages over small-scale Projects (such as the Trust's),
Projects that cannot commit to deliver power on a firm commitment
basis or Projects that are located in electricity surplus areas
with insufficient transmission capacity.
Wholesale-level Access to Transmission Capacity.
Without access to transmission capacity, an Independent
Power Project or other wholesale generator can only sell to the
local electric utility or to a facility on which it is located
(or, in some states, which adjoins its location). The most
important changes occurring in the electric power industry are
the efforts of FERC to compel utilities and power pools to
provide nationwide access to transmission facilities to all
wholesale power generators. When combined with the increased
competition in the generating area, this is likely to create an
electricity supply market that may profoundly change the
operations of electric utilities, consumers and Independent Power
Projects.
The 1992 Energy Act empowered FERC to require electric
utilities and power pools to transmit electric power generated by
other wholesale generators to wholesale customers. This process
is referred to as "wheeling" the electric power. Essentially,
the generator contributes power to a utility or power pool and is
credited with that contribution, and the utility or power pool
serving the wholesale customer makes available that amount of
electric power to the customer and debits the generator.
Wheeling is effected between power pools on a similar basis.
FERC initially dealt with wheeling requests on a case-by-
case basis as constrained by provisions of the 1992 Energy Act
that require all costs of the transmitting utility to be
recovered in the transmission charge and that prohibit wholesale
competitors from wheeling power to customers of an electric
utility under generating contracts or tariffs. On April 24, 1996
the Federal Energy Regulatory Commission adopted Order 888, which
requires electric utilities and power pools to provide wholesale
transmission facilities and information to all power producers on
the same terms, and endorses the recovery by utilities of
uneconomic capital costs from wholesale customers who change
suppliers. The utilities would also be required to furnish
ancillary services, such as scheduling, load dispatch, and system
protection, as needed. These rights, however, would apply only
to sales of new electric power over and above existing utility
supply arrangements. Initial trade estimates are that up to 6%
of the entire U.S. market for wholesale power would be available
to Independent Power Projects and other wholesale generators
under the proposal.
Numerous regulatory issues must be addressed under this
proposal of which one of the most contentious is the treatment of
utility so-called "stranded costs." Utilities that own
generating plants with relatively high costs of production would
be under severe competitive and regulatory pressure to purchase
cheaper wholesale electricity, but in that event the utilities
would not receive sufficient revenue to meet debt service
requirements or other capital costs (the stranded costs)
relating to the high-cost plants. This might significantly
impair utility cash flows and some utilities might be at risk of
insolvency in that event. The FERC order would require some
mitigation efforts on the utility's part, but primarily would
require wholesale customers who acquire electricity from a new
supplier to compensate their former utility supplier for revenue
lost. This might require a customer who changes suppliers to pay
a substantial additional fee to the prior utility supplier, thus
inhibiting changes of supplier.
The order takes no action to modify existing power purchase
contracts. The order intends to create a competitive national
market in electricity generation and thus may create additional
pressure on electric utilities to seek changes to long-term power
purchase contracts, as described further below. The Trust has
developed its business plan in anticipation of the order and will
pursue its investment program to take advantage of opportunities
as they arise in the changing industry. The Trust is unable to
predict the consequences of the order on its eventual operations
or on the independent power industry.
State public utility regulatory agencies must also review
and approve certain aspects of wholesale power deregulation, and
those agencies are currently holding proceedings and making
determinations.
In addition to the FERC order or other Congressional or
regulatory actions that may result in freer access to
transmission capacity, agreements with Canada, and to a lesser
extent with Mexico, are leading toward access for those
countries' generators to U.S. markets. In particular, certain
Canadian suppliers, such as HydroQuebec (the Quebec provincial
utility) are already offering substantial amounts of electricity
in the U.S., and more may be offered if sufficient transmission
capacity can be approved and built. These agreements may also
afford access to those countries' markets in the future for
Independent Power Projects. As a result, there is the
possibility that a North American wholesale market will develop
for electricity, with additional competitive pressures on U.S.
generators.
Conservation Initiatives.
In recent years many state regulators, at the urging of
citizens' groups and as contemplated by the 1992 Energy Act, have
required electric utilities to engage in least cost utility
planning, demand side management and other conservation programs.
These programs have the common effect of encouraging utilities
to look to conservation of electricity and the more efficient use
of existing capacity as means of meeting new demand, as well as
to purchases from Independent Power Projects or wholesale
generators and to building more generation capacity. There are
also reports that utilities are reducing their reserve capacity
levels to minimums and are more aggressively controlling dispatch
of power as a means of minimizing new power purchases.
Proposals to Modify PURPA and Existing Power Contracts.
The independent power industry remains a creature of PURPA
in most respects. The prospects of increased competition to
supply electricity, availability of wheeling of wholesale power,
supply alternatives through the conservation initiative described
above and reduced rates of increase in electricity demand have
caused many electric utilities to advocate repeal or modification
of PURPA and changes to existing long-term Power Contracts with
Independent Power Projects. These utilities have alleged that
PURPA requires them to purchase electricity at higher prices than
they could acquire new capacity themselves and that existing
Power Contracts, signed when utilities anticipated much higher
fuel and capital costs and higher demand, provide for prices
substantially above current wholesale prices. The independent
power industry has pointed out that PURPA does not require
utilities to purchase new supplies from Independent Power
Projects at rates above alternative sources' prices (although a
few state regulators have imposed such requirements from time to
time) and that existing long-term Power Contracts were generally
entered into on the basis of good faith estimates by the
utilities of future conditions with the expectation that sponsors
would rely upon them.
To date, FERC has rejected proposals to modify existing
Power Contracts (except for contracts entered into under state
regulations mandating payment of prices greater than utility
avoided costs at the time the contracts were executed), and
FERC's rulemaking proposals are expressly based on the principle
that existing Power Contracts that comply with current law should
not be modified by FERC. Although proposals have been introduced
in Congress to amend or repeal PURPA, no such proposal has yet
been reported. However, there can be no assurance that FERC or
the Congress will not take action to reduce or eliminate the
benefits or PURPA for Independent Power Projects or that they
would not take action purporting to change or cancel existing
Power Contracts or that they would not take action making
compliance with those contracts economically or practically
infeasible. If any such action were to be taken, the value of
existing Independent Power Projects might be significantly
impaired or even eliminated. If such action were to be proposed
with any significant prospect of adoption, the consequent
uncertainty might have similar effects.
In a related phenomenon, some electric utilities that are
parties to long-term Power Contracts with rates substantially
above current replacement costs have entered into buy-out
arrangements with the owners of those Independent Power Projects.
Under these agreements, the Power Contracts are terminated in
exchange for a payment by the utility to the Project. Typically,
these arrangements have been limited to Independent Power
Projects with high costs of production or other factors that have
impaired their profitability, even with a firm Power Contract.
The Trust does not anticipate investing in Projects with the
expectation of soliciting or receiving a buy-out arrangement, but
it will consider potential arrangements if conditions warrant.
In the absence of desired regulatory or legislative
changtes, many utilities have aggressivly taken action to
abrogate existing Power Contracts by alleging default by the
generator or Project deficiencies. Virginia Electric and Power
Company attempted to do so for a Project owned by another
business trust sponsored by the Managing Shareholder, alleging
immaterial, technical violations of the Power Contract. A
federal district court held that the utility did not have the
right to terminate the Power Contract on those grounds. While
the case was on appeal, that trust accepted an offer from the
utility to settle the case by paying $3.75 million to the Trust
in exchange for the cancellation of the Power Contract. The
settlement was concluded on January 17, 1997. The case had no
material effect on this Trust or its business.
Retail-level Competition
An even more radical prospect for the electric power
industry is retail-level competition, in which generators would
be allowed to sell directly to customers by using (and paying a
fee for) the local utility's distribution facilities. Retail-
level competition presupposes the ability to wheel power in the
appropriate amounts at economic costs from the generating Project
to the electric utility whose wires link to the retail customer
(typically a large industrial, commercial or governmental unit)
and the ability to use the local utility's facilities to deliver
the electricity to the customer. In addition to the business and
regulatory issues arising from wholesale wheeling, retail-level
competition raises fundamental concerns as to the ability of
utilities to recover stranded costs at the generating and
distribution levels, the possibility that smaller customers will
have less ability to demand pricing concessions, incentives for
governmental agencies to act as intermediaries for consumers and
the functions of state-level regulatory agencies in a price-
competitive environment which may be inconsistent with their
traditional price-setting and service-prescribing roles.
Many states are experimenting with retail wheeling,
including New Hampshire, whose three-year pilot program would
allow up to 3% of state peak loads to be subject to retail
competition, and Michigan, which is proposing to allow
incremental growth in load demand to be supplied competitively.
The New Hampshire program may be abrogated, because it proposes
to split the burden of utility stranded costs between ratepayers
and the utilities in opposition to FERC's position that utilities
should not bear those costs. Many larger states, including
California, New York, Massachusetts, Pennsylvania and Florida
among others, are implementing large scale movements toward
various forms of retail deregulation. It appears that most
states will do so by the year 2000. These proposals are
currently the subject of intensive debate and restructuring, and
any such proposal is likely to undergo judicial review.
Regulators and industry participants currently have extreme
uncertainty as to whether and how far retail-level competition
will be authorized, the treatment of stranded costs, the extent
to which FERC's actions in the wholesale market will practically
compel retail-level competition and the effects of any change.
As of the date of this Annual Report, however, no state authority
has proposed or implemented any plan that would abrogate or
impair existing long-term Power Contracts with Independent Power
Projects. Instead, to the extent that long-term Power Contracts
have rates above current avoided costs, the excess is being
treated by most states as a form of stranded cost. Many states
are providing that all or most of the stranded costs will be
borne by ratepayers rather than Independent Power Projects or
utilities. Typically, the state will require customers who
change electricity suppliers to make payments to a fund used to
reimburse utilities in part for the burden of stranded costs.
Although this may lessen pressures on utilities to contest long-
term Power Contracts, it may deter retail customers from
switching to independent power suppliers.
Initial Effects of Trends
Although, as mentioned above, it is impractical to predict
all the consequences of the rapidly evolving trends in the
electric power industry, certain patterns are beginning to
emerge. First, as noted before, investment in new Independent
Power Projects and in new utility generating capacity in the
United States has substantially decelerated since 1993, as the
larger participants in the development process (including
developers, utilities, lenders and equipment suppliers) reassess
their positions. Indeed, many of the largest participants have
announced their intentions to concentrate their resources in
developing countries in Europe and Asia. Similarly, lenders are
more reluctant currently to extend large amounts of non-recourse
financing for development of Projects and are insisting on larger
equity investments by owners of Projects. The Trust believes
that because it is focused on the independent power industry
without competing business interests and because it seeks to make
substantial equity investments in Projects, it has the ability to
invest in attractive smaller Projects under these conditions.
In response to the current perceived slowing of electricity
demand growth, the prospect of wholesale competition and the
relatively higher prices currently payable under some long-term
Power Contracts, many electric utilities have refrained from
entering into new, long-term Power Contracts with Independent
Power Projects and have instead proposed to purchase electricity
from Qualifying Facilities or other generators under short-term
contracts. Competitive bidding by utilities, governmental units
and in states where permitted, large industrial and commercial
users for electricity supplies is becoming common. In 1995 and
1996, these competitive solicitations typically attracted large
numbers of bids at prices substantially below prior utility
prices. Although these solicitations cover a minuscule part of
the wholesale market, they indicate that there is currently
intense competition to sell new capacity from Independent Power
Projects. Certain state regulators, in response to these
conditions, have proposed or approved auctions to generating
businesses of the rights to supply utilities. In response to
these developments, the Trust currently seeks to purchase
Projects with existing long-term Power Contracts so as to
minimize exposure to volatile short-term markets. There is no
assurance that it will be able to acquire those Projects or to do
so on favorable terms.
As a consequence of these trends and industry participants'
reactions to them, many observers, including utilities, believe
that there are temporary, regional surpluses of electric
generating capacity. For example, in the spring of 1995, the
California public utilities commission projected that the state's
three largest utilities would not need additional generating
capacity until 2004, and that there was a current small surplus
of capacity. It should be noted, however, that the projections
also foresaw a rapid increase of demand for capacity in the ten
years following 2004. Similarly, on a nationwide level a 1997
estimate forecasted that 71,000 Megawatts of capacity is
currently provided by fossil-fuel power plants that are over 30
years old and are approaching the ends of their expected useful
lives, that most nuclear power plants are facing relicensing
proceedings that normally require extensive reconstruction, and
that up to 10% of all U.S. generating capacity may be up for
replacement in the next 15 years. Accordingly, one of the most
important and difficult questions for determination is whether
the current reluctance to finance and build additional generating
capacity will lead to capacity shortages on a regional or
national basis in the next ten years. Further, as the supply
market becomes more fragmented and short-term, regulators and
customers are beginning to raise concerns as to the dependability
of supply.
Another consequence of the current industry reluctance to
commit to long-term increases in capacity and the perceived
existence of regional surplus capacity is a short-term
orientation on the part of many industry participants. Recently,
many companies, including affiliates of fuel suppliers and
utilities, have applied to FERC to act as electric power
marketers, because they anticipate that if wholesale wheeling
becomes significant there will be strong demand for brokers or
market makers in electric power. It is uncertain whether power
marketers will become significant factors in the electric power
market. A related development is the creation of derivative
contracts for hedging of and speculation in electricity supplies.
A few developers and utilities are also considering the
construction of "merchant power plants," which would be built
without firm Power Contracts in hopes of marketing their output
on the anticipated short-term, competitive wholesale or retail
markets.
With these conditions in mind, many observers see two
primary strategies for Independent Power Projects to succeed in
the United States: first, Projects that have existing, firm,
long-term Power Contracts may do well so long as regulatory or
legislative actions do not abrogate the contracts. Second,
Projects that are low-cost producers of electricity, either from
efficiencies or good management or as the result of successful
cogeneration technologies, will have advantages in the
competitive market. The Trust intends to focus on both
possibilities and to maintain a focus on medium-to-long-term
results.
Finally, there have been industry-wide moves toward
consolidation of participants and divestiture of Projects. A
number of utilities and equipment suppliers have proposed or
entered into joint ventures to reduce risks and mobilize
additional capital for the more competitive environment, while
many electric utilities are in the process of combining, either
as a means of reducing costs and capturing efficiencies, or as a
means of increasing size as an organizational survival tactic. A
number of large natural gas utilities have also acquired or are
considering acquiring electric utilities. Industry observers
have attributed this to the more entrepreneurial character of the
gas industry, which has already been deregulated, and to the fact
that natural gas is currently a preferred fuel for generating
plants, which may encourage the combination of the fuel suppliers
with fuel users to assure supply and reduce uncertainties. These
consolidations and acquisitions tend to create additional
competitive pressures in the electric power industry; however,
this trend is also encouraging the divestiture of smaller
Projects or Projects that are deemed less central to the
operations of large, consolidated businesses. This may tend to
depress the resale value of the Trust's Projects.
5. Competition
There are a large number of participants in the independent
power industry. Several large corporations specialize in
developing, building and operating Independent Power 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.
Competition in the energy market is generally not a factor
in the current operations of the Trust since its major Projects
have entered into long-term agreements to sell their output at
specified prices. However, a particular Project could be subject
to future competition to market its energy products 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 or because of the
failure of a Project to comply with the terms of the Power
Contract; regulatory changes; loss of a cogeneration facility's
status as a Qualifying Facility due to failure to meet minimum
steam output requirements; or other reasons. It is impossible at
this time to estimate the level of marketing competition that the
Trust would face in any such event.
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, and the San
Diego Project, which does not normally sell electricity but which
is interconnected with the local electric utility, are Qualifying
Facilities. Maintaining the Qualified Facility status of a
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, and there is an ongoing risk that the utility will assert
that the Project does not qualify for any given year. The Trust
believes that the Monterey Project has qualified and will
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 San Diego and Monterey Projects are coal
capable and thus qualify 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 and there is no assurance that a market
for such allowances will develop. Projects fueled by natural gas
are not expected to be materially burdened by the acid rain
provisions of the Clean Air Act Amendments.
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.
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 not
developed expertise and experience in obtaining necessary
licenses, permits and approvals, which will be the responsibility
of each Project's managers and Project Sponsors. The Trust will
rely upon qualified environmental consultants and environmental
counsel retained by it or by Project Sponsors to assist in
evaluating the status of Projects regarding such matters.
(iii) The 1940 Act
Since its Shares are registered under the 1934 Act, the
Trust is required to file with the Commission certain periodic
reports (such as Forms 10-K (annual report), 10-Q (quarterly
report) and 8-K (current reports of significant events) and to be
subject to the proxy rules and other regulatory requirements of
that act that are applicable to the Trust. The Trust has no
intention to and will not permit the creation of any form of a
trading market in the Shares in connection with this
registration.
On 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 employees of the Monterey and Sunkist Projects have been
transferred to RPMC 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 the
City of 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).
Approximate
Square
Ownership Ground Approximate Footage of Description
Interests Lease Acreage Project (Actual of
Project Location in Land Expiration of Land or Projected) Project
Berkshire Pittsfield,
Massachusetts Leased 2004 5 30,000 Waste-to-
energy facility
in operation
San Diego San Diego,
California Leased 2023 .3 12,000 Gas-fired
power facility
in operation
which produces
chilled water
for customers'
office building
central air
conditioning
systems
Columbia Columbia,
New York Owned __ 44 25,000 Municipal
waste
transfer
station in
operation
Monterey Monterey,
California Leased 2021 2 10,000 Gas-fired
cogeneration
facility
Sunkist Ventura Leased N/A N/A N/A Natural
County, or gas fired
California licensed engines
powering
irrigation
pumps located
on various
farms
Item 3. Legal Proceedings.
There are no legal proceedings involving the Trust.
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 1996.
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.
(b) Holders
As of the date of this Form 10-K, there are 479 record
holders of Investor Shares.
(c) Dividends
The Trust made distributions as follows for the years 1994
through 1996:
Year ended Year ended Year ended
December 31, December 31, December 31,
1996 1995 1994
Total distributions
to Investors $2,082,754 $2,457,231 $1,243,907
Distributions per
Investor Share 8,924 10,450 5,285
Distributions to
Managing Shareholder $21,037 24,807 11,626
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.
Subject to the other factors described in this Annual Report
on Form 10-K, the Trust's goal is to provide Investors with
annual distributions of net cash flow, as defined in the
Declaration of Trust, of 15% of their Capital Contributions to
the Trust. Because the Trust's objective is to distribute net
cash flow, a substantial portion of many distributions will
include cash flow that represents depreciation and amortization
charges against assets at the Project level. 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, Trust-level depreciation or
amortization, or other non-cash charges against earnings. For
purposes of generally accepted accounting principles, amounts of
distributions in excess of accounting income may be considered to
be capital in nature. Investors should be aware that the Trust
is organized to return net cash flow rather than accounting
income to Investors.
Item 6. Selected Financial Data.
The following data is qualified in its entirety by the
financial statements presented elsewhere in this Annual Report on
Form 10-K.
Supplemental Information As of and As of and As of and As of and
Schedule for the for the for the for the
Selected Financial Data Year Ended Year Ended Year Ended Year Ended
December 31, December 31, December 31, December 31,
1996 1995 1994 1993
Total Fund Information:
Net revenue from
operating projects $2,371,208 $2,696,578 $916,588 $0
Net income (loss) 1,970,401 2,149,184 (1,698,844) (444,284)
Net assets
(shareholders'
equity) 16,353,759 16,477,149 16,760,003 15,163,680
Investments in
Project development
and power
generation limited
partnerships 16,116,582 16,056,151 9,236,653 1,443,119
Total assets 16,466,241 16,521,944 16,791,571 15,792,506
Per Investor Share:
Revenues $10,076 $11,456 $3,894 $397
Expenses 1,705 2,473 12,368 (2,285)
Net income (loss) 8,371 9,131 $(7,218) $(1,888)
Net asset value 69,639 70,158 $71,345 $64,380
Distributions to
Investors $8,849 $10,440 $5,285 $0
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
The following discussion and analysis should be read in
conjunction with the Trust's financial statements and the notes
thereto presented elsewhere herein.
Results of Operations.
Income of the Trust from Projects was as follows:
Project 1996 1995 1994
Berkshire $351,451 $446,888 $481,588
Columbia 515,000 510,000 0
San Diego 618,080 1,027,412 435,000
Monterey 757,498 606,536 0
Sunkist 129,179 105,742 0
12 months ended December 31, 1996 versus 12 months ended
December 31, 1995
Net income for 1996 was $1,970,000, which was $179,000
(8.3%) less than the $2,149,000 recorded in 1995. There was a
$360,000 decline in revenues (13.2%) from 1995 to 1996, which was
partially offset by a $181,000 (31.1%) decrease in Trust expenses
from 1996 to 1995.
The decline in revenues was primarily the result of a
$409,000 (39.8%) decrease in distributions from the San Diego
Project. A major customer, the old San Diego County Courthouse
was closed in early 1996 and replacement customers have not been
obtained, although the Project is in active discussions with
several office building owners and developers. Cool summer
weather also reduced demand. The Trust's other Projects had
mixed results. The Berkshire Project's distributions declined
$95,000, reflecting its management's decision to retain cash flow
at the Project level to fund capital expenditures, while
increases in operating efficiencies and preventative maintenance
caused the Monterey Project's distributions to increase by
$51,000. The Columbia and Sunkist Projects' distributions
remained approximately level. Because substantially all Trust
cash flow was distributed, interest and dividend income was
nominal in 1996.
The major element of the decline in Trust expenses was a
$165,000 (33.4%) decrease in the management fee caused by the
Managing Shareholder's decision to waive a portion of its fees.
Accounting and legal expenses fell by $27,000 (45.6%), although
adoption of a comprehensive insurance program caused insurance
expenses to increase by $22,000 (608.4%).
12 months ended December 31, 1995 versus 12 months ended
December 31, 1994.
Net income for calendar 1995 was $2,149,000 as compared to a
net loss of $1,699,000 for 1994. The improvement came from both
revenue and expense items. Gross revenue increased $1,520,000
(125.3%) as Trust investments were acquired and began earning
income, while operating expenses decreased by $2,329,000 (80.0%)
as expenditures for project due diligence ended and no additional
writedowns of Trust assets were incurred.
Income from Projects rose by 194.2% from 1994 to 1995, as
the Trust enjoyed a full year of income from the Columbia and San
Diego Projects (which were acquired in 1994) and the Monterey and
Sunkist Projects were acquired. Interest and dividend revenues
in 1995 decreased by 93.8%, attributable to the application of
the Trust's remaining uninvested funds to purchasing the Monterey
and Sunkist Projects.
The 80.0% decrease in operating expenses was primarily
caused by a $510,000 decrease (97.5%) in due diligence expenses
for Project investments, which reflects the conclusion of the
Trust's investment program. No writedowns were recorded in 1995,
as opposed to $1,697,000 in 1994. No investment fee was charged
in 1995 because the Trust's offering had concluded, which
resulted in a $59,000 decrease in expenses. Equipment storage
also decreased by $55,000 as purchased equipment was installed
and left storage, and insurance costs decreased by $9,000 as the
result of a consolidation of coverage.
Liquidity and Capital Resources.
The Trust has completed the investment of its funds and does
not contemplate that it will make any significant capital
investments from Trust-level funds in 1997. However, significant
capital improvements, which are being financed from Project cash
flow, are underway at the Berkshire Project to improve ash
handling and allow use of ash as aggregate for concrete block
production. The Trust is also considering expansions to the San
Diego Project in order to extend its lines to additional
customers and possibly to increase capacity, but no decision has
been made to do so. The Trust may also undertake additional
repairs to and improvements to the Monterey Project as may be
determined by an engineering study in progress, and routine
maintenance expenses for the San Diego Project. The Trust
expects to fund these from cash reserves or current operating
cash flow.
The Trust anticipates that its cash flow during 1997 will be
adequate to fund its obligations. In the event that there is an
unanticipated need for working capital or for repairs or
replacement of equipment, the Managing Shareholder has also
obtained a credit line of $500,000 from a bank, which it intends
to make available for those purposes to the Trust or other
programs the Managing Shareholder is sponsoring. The Managing
Shareholder will not impose charges for use of that line in
excess of those charged to it by the bank.
Trends affecting Results of Operations.
In addition to the industry trends discussed above at Item
1(c)(4) - Business --Trends in the Electric Utility and
Independent Power Industries, as described above several of the
Trust's Projects are experiencing significant pressures on their
profitability and operations. Recent increases in natural gas
prices during the winter months of 1996 and early 1997 impaired
profitability at the Monterey, Sunkist and San Diego Projects,
although prices began to fall toward prior levels in February
1997. The Managing Shareholder is considering entering into
long-term gas supply arrangements to reduce exposure to these
fluctuations, but the relatively small size of each Project may
limit its ability to do so.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Statement of Operations For
the Three Years Ended December 31, 1996 F-3
Balance Sheet at December 31, 1996 and 1995 F-4
Statement of Changes in Shareholders'
Equity For the Three Years
Ended December 31, 1996 F-5
Statement of Cash Flows For the
Three Years Ended December 31, 1996 F-6
Notes to Financial Statements F-7 to F-10
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, Price Waterhouse 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 Energy Holding Corporation ("Ridgewood Holding"),
a Delaware corporation incorporated in April 1992, is the
Corporate Trustee of the Trust.
(b) Managing Shareholder.
The Managing Shareholder 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.
The Managing Shareholder has 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") and Ridgewood Electric Power
Trust V ("Ridgewood Power V") as Delaware business trusts to
participate in the independent power industry. The business
objectives of these four trusts are similar to those of the
Trust.
The Managing Shareholder is an affiliate of Ridgewood Energy
Corporation ("Ridgewood Energy"), which has organized and
operated 46 limited partnership funds and one business trust over
the last 12 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.
Robert E. Swanson has been the President, sole director and
sole stockholder of the Managing Shareholder 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 50, has also served as President of
the Trust since its inception in November 1992 and as President
of RPMC, Ridgewood Power I, Ridgewood Power III, Ridgewood Power
IV and Ridgewood Power V, since their respective inceptions. Mr.
Swanson has been President, registered principal, sole director
and sole stockholder of Ridgewood Securities Corporation, the
Placement Agent for the private placement offerings of those four
trusts. In addition, he has been President, sole director 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 38, has served as Executive Vice
President of the Managing Shareholder, RPMC, Ridgewood Power I,
the Trust, Ridgewood Power III, Ridgewood Power IV and Ridgewood
Power V since their respective inceptions, with primary
responsibility for marketing and acquisitions. He has served as
Vice President and General Counsel of Ridgewood Securities
Corporation since he joined the firm in December 1987. Mr. Gold
has also served as Executive Vice President of Ridgewood Energy
since October 1990. He served as Vice President of Ridgewood
Energy from December 1987 through September 1990. For the two
years prior to joining Ridgewood Energy and Ridgewood Securities
Corporation, Mr. Gold was a corporate attorney in the law firm of
Cleary, Gottlieb, Steen & Hamilton in New York City where his
experience included mortgage finance, mergers and acquisitions,
public offerings, tender offers, and other business legal
matters. Mr. Gold is a member of the New York State bar. He is a
graduate of Colgate University and New York University School of
Law.
Thomas R. Brown, age 42, joined the Managing Shareholder in
November 1994 as Senior Vice President and holds the same
position with the Trust, RPMC and each of the other trusts
sponsored by the Managing Shareholder. He became Chief Operating
Officer of the Managing Shareholder, RPMC and the five trusts in
October 1996. Mr. Brown has over 19 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 48, assumed the duties of Chief
Financial Officer of the Managing Shareholder, the Trust, the
other four trusts organized by the Managing Shareholder and RPMC
in November 1996. Under a consulting arrangement, Mr. Quinn will
devote a majority of his time to the business of the Managing
Shareholder and RPMC while continuing his other activities, which
are expected to conclude in the spring of 1997. Thereafter, he
expects to become a full-time officer of the Managing Shareholder
and RPMC.
Mr. Quinn has 27 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 44, has served as Vice President of the
Managing Shareholder, RPMC, the Trust, Ridgewood Power I,
Ridgewood Power III and Ridgewood Power IV since their respective
inceptions. She has also served as Vice President of Ridgewood
Energy since October 1984, when she joined the firm. Her primary
areas of responsibility are investor relations, communications
and administration. Prior to her employment at Ridgewood Energy,
Ms. Olin was a Regional Administrator at McGraw-Hill Training
Systems where she was employed for two years. Prior to that, she
was employed by RCA Corporation. Ms. Olin has a Bachelor of Arts
degree from Queens College.
(c) Management Agreement.
The Trust has entered into a Management Agreement with the
Managing Shareholder detailing how the Managing Shareholder will
render management, administrative and investment advisory
services to the Trust. Specifically, the Managing Shareholder
will perform (or arrange for the performance of) the management
and administrative services required for the operation of the
Trust. Among other services, it will administer the accounts and
handle relations with the Investors, provide the Trust with
office space, equipment and facilities and other services
necessary for its operation and conduct the Trust's relations
with custodians, depositories, accountants, attorneys, brokers
and dealers, corporate fiduciaries, insurers, banks and others,
as required. The Managing Shareholder will also be responsible
for making investment and divestment decisions, subject to the
provisions of the Declaration.
The Managing Shareholder will be obligated to pay the
compensation of the personnel and all administrative and service
expenses necessary to perform the foregoing obligations. The
Trust will pay all other expenses of the Trust, including
transaction expenses, valuation costs, expenses of preparing and
printing periodic reports for Investors and the Commission,
postage for Trust mailings, Commission fees, interest, taxes,
legal, accounting and consulting fees, litigation expenses and
other expenses properly payable by the Trust. The Trust will
reimburse the Managing Shareholder for all such Trust expenses
paid by it.
As compensation for the Managing Shareholder's performance
under the Management Agreement, the Trust is obligated to pay the
Managing Shareholder an annual management fee described below at
Item 13 -- Certain Relationships and Related Transactions.
The Board of the Trust (including both initial Independent
Trustees) have approved the initial Management Agreement and its
renewals. Each Investor consented to the terms and conditions of
the initial Management Agreement by subscribing to acquire
Investor Shares in the Trust. The Management Agreement will
remain in effect until January 4, 1998 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 principal 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. Mr. Hellmold made a late filing in March 1997
under Section 16 of the 1934 Act to report director status and
beneficial ownership of Investor Shares.
Ralph O. Hellmold, age 56, is founder, sole shareholder and
President of Hellmold Associates, Inc., an investment banking
firm, broker-dealer 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.I.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.
Jonathan C. Kaledin, age 38, 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 founder and Executive Director of the National
Water Funding Council ("NWFC"), an advocacy and public affairs
organization representing municipalities, businesses, financial
institutions and others on federal Clean Water Act and Safe
Drinking Water Act funding issues. Prior to forming the NWFC in
1990, Mr. Kaledin was an attorney with the Boston law firm of
Wright & Moehrke. There he specialized in wetlands, water,
environmental review, zoning and hazardous and solid waste
matters, representing clients in state and federal court and
before state and federal agencies and local boards and
commissions. From 1987 through 1990, Mr. Kaledin was Assistant
Regional Counsel for the New England office of the Environmental
Protection Agency ("EPA"). His responsibilities at the EPA
included administrative and judicial environmental enforcement
under the Clean Water Act and other federal water protection
legislation. 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
Mr. Brown and Mr. Quinn did not file on a timely basis as
required by section 16(a) of the 1934 Act Forms 3 reporting their
status as officers or directors of the Trust and their beneficial
ownership. Each person made one late filing of Form 3 in
December 1996. The number of transactions that were not reported
on a timely basis by each of these persons was zero.
(g) RPMC.
As discussed above at Item 1 - Business, RPMC has assumed
day-to-day management responsibility for the Monterey and Sunkist
Projects, effective January 1, 1996 and has assumed certain
responsibilities for the San Diego Project. Like the Managing
Shareholder, RPMC is wholly owned by Robert E. Swanson. It has
entered into an "Operation Agreement" with certain of the Trust's
subsidiaries, effective January 1, 1996, under which RPMC, under
the supervision of the Managing Shareholder, will provide 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, RPMC will charge the Trust at its cost
for these services and for the Trust's allocable amount of
certain overhead items. RPMC will share space and facilities with
the Managing Shareholder and its Affiliates. To the extent that
common expenses can be reasonably allocated to RPMC, the Managing
Shareholder may, but is not required to, charge RPMC at cost for
the allocated amounts and such allocated amounts will be borne by
the Trust and other programs. Common expenses that are not so
allocated will be borne by the Managing Shareholder.
Initially, the Managing Shareholder does not anticipate
charging RPMC for the full amount of rent, utility supplies and
office expenses allocable to RPMC. As a result, both initially
and on an ongoing basis the Managing Shareholder believes that
RPMC'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. RPMC 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 RPMC; and
allocations will be made in a manner consistent with generally
accepted accounting principles.
RPMC 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.
RPMC 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 RPMC, 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 RPMC; however, no amendment that materially
increases the obligations of the Trust or that materially
decreases the obligations of RPMC 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 officers of RPMC 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), Ms. Olin (Vice President), Joseph A.
Heyison, General Counsel, and Douglas V. Liebschner, Vice
President - Operations. Mr. Heyison, age 42, joined RPMC in
January 1996. He was previously of counsel to the law firm of De
Forest & Duer, concentrating in corporate finance, banking,
environmental law and securities. He is a member of the bars of
New Jersey, New York and Ohio and was graduated from the
University of Pennsylvania Law School in 1979.
Douglas V. Liebschner, age 50, joined RPMC in June 1996 as
Vice President of Operations. He has over 27 years of experience
in the operation and maintenance of power plants. From 1992
until joining RPMC, 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 RPMC at allocable cost for
services provided by RPMC's employees. 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). Addtional 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 1995, 1994 and 1993, the Trust made distributions to the
Managing Shareholder (which is a member of the Board of the
Trust) as stated at Item 5 - Market for Registrant's Common
Equity and Related Stockholder Matters. In addition, the Trust
paid fees to the Managing Shareholder and its affiliates as
follows:
Fee Paid to 1996 1995 1994 1993
Management Managing
fee Shareholder $328,952 $494,000 $495,000 $0
Cost
reimburse-
ments* RPMC 1,207,252 0 0 0
Investment Managing
fee Shareholder 0 0 59,000 388,000
Placement Ridgewood
agent fee Securities
and sales Corporation
commissions 0 0 4,000 245,000
Organizational, Managing
distribution Shareholder
and offering
fee 0 0 149,000 1,014,000
* 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 RPMC's overhead costs.
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.
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 Sunkist Projects. In 1996,
these reimbursements were paid to RPMC. The reimbursements to
RPMC, which do not exceed its actual costs and allocable
overhead, are described at Item 10(f) - Directors and Executive
Officers of the Registrant -- RPMC.
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, 1996.
(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.
10H. Asset Purchase Agreement dated as of December 15, 1993
between San Diego Central Cooling Company ("SDCCC")
and RSD Power Partners, L.P. is incorporated by
reference to Exhibit 10M to the Form 10K of Registrant
filed with the Commission on March 30, 1994.
10I. RSD Power Partners, L.P. Agreement of Limited
Partnership dated as of January 7, 1994 is
incorporated by reference to Exhibit 10N to the form
10K of Registrant filed with the Commission on March
30, 1994.
10J. Lease dated June 7, 1983 between San Diego Gas &
Electric Company ("SDG&E") and Applied Energy,
Incorporated ("AEI") is incorporated by reference to
Exhibit 10O to the Form 10K of Registrant filed with
the Commission on March 30, 1994.
10K. Assignment and Consent among AEI, Energy Factors,
Incorporated, SDCCC and SDG&E is incorporated by
reference to Exhibit 10P to the form 10K of Registrant
filed with the Commission on March 30, 1994.
10L. Memorandum and Lease and Assignment of Lease dated as
of July 3, 1989 among SDG&E, AEI and SDCCC is
incorporated by reference to Exhibit 10Q to the form
10K of Registrant filed with the Commission on March
30, 1994.
10M. Letter Agreement dated July 7, 1989 between Energy
Factors Incorporated and SDG&E is incorporated by
reference to Exhibit 10R to the form 10K of Registrant
filed with the Commission on March 30, 1994.
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.
21. Subsidiaries of the Registrant. Incorporated by
reference to Exhibit 21 to the Annual Report on Form
10-K of the Registrant for the year ended December 31,
1996.
24. Powers of Attorney Page 72
27. Financial Data Schedule Page 73
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, 1997
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, 1997
Robert E. Swanson Executive Officer
By: /s/Martin V. Quinn Senior Vice President April 15, 1997
Martin V. Quinn and Chief Financial Officer
By: /s/Kathleen P. McSherry Controller April 15, 1997
Kathleen P. McSherry
RIDGEWOOD POWER CORPORATION Managing Shareholder April 14, 1997
By: /s/Robert E. Swanson President
Robert E. Swanson
/s/Robert E. Swanson * Independent Trustee April 14, 1997
Ralph O. Hellmold
/s/Robert E. Swanson * Independent Trustee April 14, 1997
Jonathan C. Kaledin
* Robert E. Swanson, as attorney-in-fact for the Independent
Trustee
<PAGE>
Ridgewood Electric Power Trust II
Financial Statements
December 31, 1996, 1995 and 1994
-F1-
<PAGE>
1177 Avenue of the Americas Telephone 212 596 7000
New York, NY 10036 Facsimile 212 596 8910
[Letterhead of Price Waterhouse LLP]
Report of Independent Accountants
March 24, 1997
To the Shareholders and Trustees of
Ridgewood Electric Power Trust II
In our opinion, the accompanying balance sheet 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 at
December 31, 1996 and 1995, and the results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1996, 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 4, the financial statements include
investments, valued at $16,116,582 and $16,056,151 (99% and 97%
of shareholders' equity, respectively) as of December 31, 1996
and 1995, 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, because of the inherent uncertainty of valuation, 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/ Price Waterhouse LLP
-F2-
<PAGE>
Ridgewood Electric Power Trust II
Statement of Operations
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1996 1995 1994
Revenue:
Income from power
generating projects $ 2,371,208 $ 2,696,578 $ 916,588
Interest and dividend
income 540 18,401 295,623
Other income --- 16,325 ---
2,371,748 2,731,304 1,212,211
Expenses:
Investment fee --- --- 59,400
Project due diligence
costs --- 13,068 523,104
Management fee 328,952 494,023 494,820
Equipment storage costs --- 1,755 56,700
Accounting and legal fees 31,750 58,331 54,698
Insurance 25,501 3,600 12,450
Writedown of limited
partnership investments --- --- 1,397,350
Writedown of electric
power equipment --- --- 299,940
Miscellaneous 15,144 11,343 12,593
401,347 582,120 2,911,055
Net income (loss) $ 1,970,401 $ 2,149,184 $ (1,698,844)
Allocation to:
Shareholders $ 1,950,697 $ 2,127,692 $ (1,681,856)
Managing shareholder 19,704 21,492 (16,988)
$ 1,970,401 $ 2,149,184 $ (1,698,844)
See accompanying notes to financial statements.
-F3
<PAGE>
Ridgewood Electric Power Trust II
Balance Sheet
Year Ended December 31,
1996 1995
Assets:
Investments in project development
and power generation projects $ 16,116,582 $ 16,056,151
Cash and cash equivalents --- 101,975
Electric power equipment 331,018 331,018
Other assets 18,641 32,800
Total assets $ 16,466,241 $ 16,521,944
Liabilities and Shareholders' Equity:
Accounts payable and accrued
expenses $ 112,482 $ 44,795
Shareholders' equity:
Shareholders' equity (235.3775 shares
issued and outstanding) 16,391,464 16,513,521
Managing shareholder's accumulated deficit (37,705) (36,372)
Total shareholders' equity 16,353,759 16,477,149
Total liabilities and shareholders'
equity $ 16,466,241 $ 16,521,944
See accompanying notes to financial statements.
-F4-
<PAGE
Ridgewood Electric Power Trust II
Statement of Changes in Shareholders' Equity
Managing
Shareholders Shareholder Total
Shareholders' equity,
December 31, 1993 $ 15,158,123 $ (4,443) $ 15,153,680
Capital contributions,
net (29.9 shares) 4,560,700 --- 4,560,700
Cash distributions (1,243,907) (11,626) (1,255,533)
Net loss for the year (1,681,856) (16,988) (1,698,844)
Shareholders' equity,
December 31, 1994
(235.3775 shares) 16,793,060 (33,057) 16,760,003
Capital contributions,
net 50,000 --- 50,000
Cash distributions (2,457,231) (24,807) (2,482,038)
Net income for the year 2,127,692 21,492 2,149,184
Shareholders' equity,
December 31, 1995
(235.3775 shares) 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 for the year 1,950,697 19,704 1,970,401
Shareholders' equity,
December 31, 1996
(235.3775 shares) $ 16,391,464 $ (37,705) $ 16,353,759
See accompanying notes to financial statements.
-F5-
<PAGE>
Ridgewood Electric Power Trust II
Statement of Cash Flows
Year Ended December 31,
1996 1995 1994
Cash flows from operating activities:
Net income (loss) $ 1,970,401 $ (2,149,184) $ (1,698,844)
Adjustments to reconcile
net income (loss) to
net cash (provided by)
used in operating activities:
Proceeds from sale of
electric power
equipment --- 438,855 ---
Purchase of electric
power equipment --- --- (1,738,855)
Writedown of limited
partnership investments --- --- 1,397,350
Purchase of investments
in electric power projects (60,431) (5,519,498) (9,190,884)
Changes in assets and
liabilities:
Decrease in cash held
in escrow for project
purchase --- --- 2,343,000
Decrease in deferred
due diligence costs --- 14,570 181,243
(Increase) decrease in
other assets 14,159 (30,757) 18,826
Increase (decrease) in
accounts payable and
accrued expenses 67,687 13,227 (607,258)
Total adjustments 21,415 (5,083,603) (7,596,578)
Net cash provided by
(used in) operating
activities 1,991,816 (2,934,419) (9,295,422)
Cash flows provided by
(used in) financing activities:
Proceeds from shareholders'
contributions 10,000 50,000 4,962,600
Selling commissions and
distribution and offering
fees paid --- --- (401,900)
Cash distributions to
shareholders (2,103,791) (2,482,038) (1,255,533)
Net cash provided by
(used in) financing
activities (2,093,791) (2,432,038) 3,305,167
Net decrease in cash
and cash equivalents (101,975) (5,366,457) (5,990,255)
Cash and cash equivalents,
beginning of period 101,975 5,468,432 11,458,687
Cash and cash equivalents,
end of period $ --- $ 101,975 $ 5,468,432
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. The Trust
commenced operations on April 29, 1993 and discontinued its
offering of Trust 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, thermal energy
and other power plants that use various fuel sources (except
nuclear). The power plants sell electricity and 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 the 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 project development and power generation limited
projects
The Trust holds investments in power generation projects,
which are stated at fair value. Due to the non-liquid 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 received. Interest
and dividend income are recorded as earned.
Offering costs
Costs associated with offering Trust shares (selling
commissions, distribution and offering costs) are recorded as a
reduction of the shareholders' capital contributions.
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.
-F7-
<PAGE>
Ridgewood Electric Power Trust II
Notes to Financial Statements
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 respective 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 items in previously issued financial statements have
been reclassified for comparative purposes.
3. Electric Power Equipment
The Trust purchased various used electric power generation
equipment to be used in potential power generation projects. In
January 1995, power generating equipment with a fair value of
$1,300,000 was transferred to the Sunnyside (Monterey) project as
part of its purchase price. In October 1995, the Trust sold to a
related party power generating equipment with a cost of $438,855
for $455,182. The remaining equipment is held in storage and
depreciation is not recorded. As of December 31, 1996, the cost
of the remaining equipment was $331,018.
4. Investments in Project Development and Power Generation
Limited Projects
The Trust had the following investments in power generation
and waste transfer projects:
Fair values as of December 31,
1996 1995
Power generation and waste transfer projects:
Pittsfield Investors Limited Partnership $ 2,347,330 $ 2,347,330
RSD Power Partners, L.P. 3,507,275 3,507,275
B-3 Limited Partnership 4,001,843 3,941,412
Sunnyside Cogeneration Partners, L.P. 5,308,467 5,308,467
California Pumping Project 951,667 951,667
$ 16,116,582 $ 16,056,151
Investments in power generation limited partnerships
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 expires in November 2004.
-F8-
<PAGE>
Ridgewood Electric Power Trust II
Notes to Financial Statements
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 cover 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
be entitled to receive additional distributions from any
additional net cash flow. As of December 31, 1996 and 1995, the
total cost of the Trust's investment in the partnership was
$2,347,330. The Trust received distributions of $351,451,
$446,888 and $481,588 from the project in 1996, 1995 and 1994,
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 13 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 is entitled to
receive annually the greater of either 80% of net profits from
the project or a preferred minimum return of 25% on its total
investment. In the event in any given year all net profits from
the project do not cover the amount of the preferred minimum
return, the amount of such shortfall is payable on a priority
basis out of any net profits in subsequent years. As of December
31, 1996 and 1995, the total cost of the Trust's investment in
the partnership was $3,507,275. The Trust received distributions
of $618,080, $1,027,412 and $435,000 from the project in 1996,
1995 and 1994, respectively.
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.
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 in any given year available net cash flow from the project
does not cover 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
be entitled to receive additional distributions from any
additional net cash flow. As of December 31, 1996 and 1995, the
total cost of the Trust's investment in the partnership was
$4,001,843 and $3,941,412, respectively. The Trust received
distributions of $515,000 and $510,000 from the project in 1996
and 1995, 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. 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 original
cost of the equipment contributed by the Trust was $1,599,940.
In 1994, the Trust wrote down the value of the equipment by
$299,940. The Trust received distributions of $757,498 and
$606,536 from the project in 1996 and 1995, respectively.
-F9-
<PAGE>
Ridgewood Electric Power Trust II
Notes to Financial Statements
California Pumping Project
On March 31, 1995, the Trust acquired a package of natural
gas fueled 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. The Trust receives 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. Total investment at December 31, 1996 and
1995, was $951,667 for an equivalent of 299.8 kilowatts of power.
The operator pays for fuel, maintenance, repair and replacement.
The Trust received distributions of $129,179 and $105,742 from
the project in 1996 and 1995, respectively.
Investments in project development limited partnerships
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 partnerhsips of $1,065,798.
RE Power Partners, L.P. (known as the Blue Ridge project)
In 1993, the Trust entered into a limited partnership
agreement to provide construction funding of a 3 megawatt natural
gas-fueled cogeneration project. During 1994, after further
review of the project the Trust decided not to proceed with the
construction funding. Total costs, excluding equipment written
down separately and transferred to the Sunnyside Cogeneration
Partners, L.P., incurred by the Trust and subsequently written
off in 1994 totaled $331,552.
5. Transactions With Managing Shareholder And Affiliates
The Trust also 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. For the year ended December 31, 1994, the Trust paid fees
for these services to the managing shareholder of $148,500.
These fees were recorded as a reduction in shareholders' capital
contributions.
The Trust 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.
For the year ended December 31, 1994, the Trust paid investment
fees to the managing shareholder of $59,400.
The Trust entered into a management agreement with the
managing shareholder, under which the managing shareholder
renders certain management, administrative and advisory services
and provides office space and other facilities to the Trust. As
compensation to the managing shareholder, the Trust pays the
managing shareholder an annual management fee equal to 2.5% of
the net asset value of the Trust payable monthly upon the closing
of the Trust. For the years ended December 31, 1996, 1995 and
1994, the Trust paid management fees to the managing shareholder
of $328,952, $494,023 and $494,820, respectively.
-F10-
<PAGE>
Ridgewood Electric Power Trust II
Notes to Financial Statements
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 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"). In all cases, 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 were paid
through December 31, 1996.
The managing shareholder purchased 1.45 shares of the Trust
for $121,800. Through the closing of the Trust's offering on
January 3, 1994, 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, 1996, Ridgewood Management
charged the Monterey project $60,139 for overhead items allocated
in proportion to the amount invested in projects managed, and
charged the Monterey project for all of the remaining direct
operating and non-operating expenses incurred during the period.
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the
undersigned, Ralph O. Hellmold, appoints Robert
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 his or their sole discretion, to execute on his behalf
as an Independent Trustee of Ridgewood Electric Power
Trust I and Ridgewood Electric Power Trust IV the Annual
Reports on Form 10-K for the year ended December 31, 1996
for each of the above-named trusts, and any amendments
thereto.
IN WITNESS WHEREOF, the undersigned has executged this
Power of Attorney this 27th day of March, 1997.
/s/Ralph O. Hellmold
Ralph O. Hellmold
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information
extracted from the Registrant's audited financial
statements for the quarter ended December 31, 1996 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-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 0
<SECURITIES> 16,118,582<F1>
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 331,018
<DEPRECIATION> 0
<TOTAL-ASSETS> 16,466,241
<CURRENT-LIABILITIES> 112,482
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 16,353,759<F2>
<TOTAL-LIABILITY-AND-EQUITY> 16,466,241
<SALES> 0
<TOTAL-REVENUES> 2,371,748
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 401,347
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 1,970,401
<INCOME-TAX> 0
<INCOME-CONTINUING> 1,970,401
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,970,401
<EPS-PRIMARY> 8,371
<EPS-DILUTED> 8,371
<FN>
<F1>Investments in power project partnerships.
<F2>Represents Investor Shares of beneficial interest
in Trust with capital accounts of $16,391,464 less
managing shareholder's accumulated deficit of $37,705.
</FN>
</TABLE>
