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 0-23432
RIDGEWOOD ELECTRIC POWER TRUST III
(Exact Name of Registrant as Specified in Its Charter)
Delaware 22-3264565
(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 3 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
$39,034,440.
Exhibit Index is located on page_____.
<PAGE>
PART I
Item 1. Business.
Forward-looking statement advisory
This Annual Report on Form 10-K, as with some other
statements made by the Trust from time to time, has forward-
looking statements. These statements discuss business
trends and other matters relating to the Trust's future
results and the business climate and are found, among
other places, at Items 1(c)(3), 1(c)(4), 1(c)(6)(ii) and 7.
In order to make these statements, the Trust has had
to make assumptions as to the future. It has also had
to make estimates in some cases about events that have
already happened, and to rely on data that may be found
to be inaccurate at a later time. Because these
forward-looking statements are based on assumptions,
estimates and changeable data, and because any attempt to
predict the future is subject to other errors, what happens
to the Trust in the future may be materially different from
the Trust's statements here.
The Trust therefore warns readers of this document that they
should not rely on these forward-looking statements without
considering all of the things that could make them
inaccurate. The Trust's other filings with the Securities
and Exchange Commission and its Confidential Memorandum
discuss many (but not all) of the risks and uncertainties
that might affect these forward-looking statements.
Some of these are changes in political and economic
conditions, federal or state regulatory structures,
government taxation, spending and budgetary policies,
government mandates, demand for electricity and thermal
energy, the ability of customers to pay for energy received,
supplies of fuel and prices of fuels, operational status of
plant, mechanical breakdowns, availability of labor and the
willingness of electric utilities to perform existing power
purchase agreements in good faith. Some of these
cautionary factors that readers should consider are
described below at Item 1(c)(4) -- Trends in the
Electric Utility and Independent Power Industries.
By making these statements now, the Trust is not making any
commitment to revise these forward-looking statements to
reflect events that happen after the date of this document
or to reflect unanticipated future events.
<PAGE>
(a) General Development of Business.
Ridgewood Electric Power Trust III, the Registrant hereunder
(the "Trust"), was organized as a Delaware business trust on
December 6, 1993 to participate in the development, construction
and operation of independent power generating facilities
("Independent Power Projects" or "Projects"). Ridgewood Energy
Holding Corporation ("Ridgewood Holding"), a Delaware
corporation, is the Corporate Trustee of the Trust.
The Trust sold whole and fractional shares of beneficial
interest in the Trust ("Investor Shares") at $100,000 per
Investor Share, and terminated its private placement offering on
May 31, 1995, at which time it had raised approximately $39.2
million. Net of Offering fees, commissions and expenses, the
Offering provided approximately $32.9 million of net funds
available for investments in the development and acquisition of
Independent Power Projects and associated expenses. The Trust
has 764 record holders of Investor Shares (the "Investors"). As
described below in Item 1(c)(2), the Trust has invested
substantially all of its net funds in four sets of 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).
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 14, 1994, 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 16, 1994, 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.
(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). Utilities in past years have
done so under long-term power purchase contracts ("Power
Contracts") which typically are the crucial determinant of the
Qualifying Facility's success.
The Trust has invested its funds in five Projects: (i) a
5.7 megawatt cogeneration facility located in Byron, California
(the "Byron Project"); (ii) an 8.5 megawatt cogeneration facility
located in Atwater, California (the "San Joaquin Project"); (iii)
a portfolio of 31 cogeneration facilities located in California,
New York, Massachusetts, Connecticut and Rhode Island, purchased
from Eastern Utilities Associates, Inc. (the "On-site
Cogeneration Projects") and (iv) a 12.3 megawatt electric
generation plant fueled by gas drawn from a sanitary landfill
near Providence, Rhode Island (the "Providence Project").
As discussed below, the Trust is a "business development
company" under the 1940 Act. 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) San Joaquin Project.
On January 17, 1995, Ridgewood Electric Power Trust III (the
"Trust") and RW Central Valley, Inc., a newly formed California
corporation which is wholly owned by the Trust ("Central
Valley"), acquired 100% of the existing partnership interests of
JRW Associates, L.P. ("JRW"), a California limited partnership
which owns and operates an approximately 8.53 megawatt electric
cogeneration facility located in the City of Atwater, Merced
County, California. The partnership interests were purchased
from JRW Cogen, Inc. and NorCal Cogen, Inc., two corporations
which were affiliates of a privately held company. At the
closing, the JRW partnership agreement was amended and restated
so that Central Valley became the sole general partner of JRW
with a 1% general partnership interest and the Trust became the
sole limited partner of JRW with a 99% limited partnership
interest. Central Valley and the Trust plan to cause JRW to
continue the operations of the Project in substantially the same
manner as it has operated in the past.
The aggregate cash purchase price paid by Central Valley and
the Trust for 100% of the JRW partnership interests was
$5,300,000. Distributions from the Project to the Trust for 1996
totalled $779,000 (a 14.7% annual return), down from $982,000 in
1995. The decrease was caused by fuel cost increases and by
the withholding by Pacific Gas and Electric Company ("PG&E") of
approximately $121,000 of capacity payments for what the Trust
believes are spurious reasons based upon a disagreement over the
interpretation of hours allotted for maintenance under the power
purchase agreement with PG&E. The Trust has instituted
litigation against PG&E to recover the withheld payments. See
Item 3 -- Litigation.
(ii) Byron Project.
Also in January 1995, the Trust caused the formation of
Byron Power Partners, L.P., a California limited partnership (the
"Partnership") in which RW Byron, Inc., a newly formed California
corporation which is wholly owned by the Trust ("Byron") owns a
1% general partner interest and the Trust owns a 99% limited
partnership interest. On January 17, 1995, the Partnership
acquired through a merger all of the assets and business of
Altamont Cogeneration Corporation ("Altamont") a California
corporation which owns and operates an approximately 5.7 megawatt
electric cogeneration facility located near the city of Byron,
Alameda County, California. As a result of the merger, NorCal
Altamont, Inc., the parent of Altamont and an affiliate of a
privately held company, received a cash payment of $2,269,500
representing the purchase price for the assets and businesses of
Altamont acquired by the Partnership. The total purchase price
to the Trust was $3,138,000. The Trust has been operating the
Project in substantially the same manner as it has operated in
the past. Distributions to the Trust from the Byron Project in
1996 were $429,000, up from $335,000 in 1995. The increase
reflected reclassification of some maintenance expenses as
capital improvements, reductions in maintenance costs because of
capital improvements and reductions in operating expenses. The
increase was achieved despite the withholding by PG&E of $43,000
in capacity payments for the reasons it did so for the San
Joaquin Project.
(iii) On-site Cogeneration Projects
In September 1995, the Trust purchased the ownership
interests in the On-Site Cogeneration Projects, a portfolio of 35
"inside the fence" cogeneration Projects owned by affiliates of
Eastern Utilities Associates, Inc., for an aggregate purchase
price of approximately $11.3 million. The On-site Cogeneration
Projects use natural gas fired turbines or reciprocating engines
to provide electrical energy and/or heat for industrial uses or
air conditioning purposes under contracts with a variety of
industrial customers. The On-site Cogeneration Projects are
located on 31 sites in California (16 sites), Connecticut (five
sites), Massachusetts (two sites), New York (seven sites) and
Rhode Island (one site). The purchase agreement provided that
the acquisition would take place as of September 30, 1995, and
accordingly the Trust assumed the benefits and risks of the On-
site Cogeneration Projects accruing after that date.
Distributions from the On-site Cogeneration Projects began in
1996 and totalled $1,756,000 (a 14.7% annual return).
The On-Site Cogeneration Projects have been divided for
financial reporting purposes into four groups. The Massachusetts
Projects include a project located at a textile manufacturer in
Fall River, Massachusetts (a 3.5 Megawatt turbine with backup
diesel engines) and a project at a housing complex in Worcester,
Massachusetts (.25 Megawatts). The Trust is currently discussing
contract revisions with the textile manufacturer. The Rhode
Island Project is located at a textile manufacturer in
Centerdale, Rhode Island and has a rated capacity of 4.2
Megawatts from three natural-gas-fired engines. The host
manufacturer has for several years been significantly in arrears
in its payments and has continued to make sporadic payments to
the Trust. The Project's operations were suspended in October
1996, although the host agreed to continue making payments under
the lease agreement and to make up arrears. The Trust and the
host are currently negotiating terms for modifications to the
existing agreement and a restart of the Project; otherwise, the
Trust intends to file suit for payment of the arrears, in which
case it is likely the host will disavow the agreement.
The Coca-Cola Project is located at a bottling plant of
Coca-Cola Bottling Company of New York at Elmsford, New York and
has a rated capacity of 1.3 Megawatts with a .6 Megawatt standby
diesel generator set. The remaining 27 On-site Cogeneration
Projects, all of which are natural-gas-fueled, are located in
California and New York and had an aggregate rated capacity of
5.5 Megawatts. In 1996, the Trust discontinued operation of and
wrote off four small On-Site Cogeneration Projects with a total
rated capacity of .24 Megawatts of electricity, which had book
values totalling $113,000. The discontinued Projects had
produced nominal cash flow or losses.
The Trust is currently financing the acquisition of two or
more small cogeneration facilities in the New York metropolitan
area which will be managed by an independent operator. The Trust
will have a preferred right to annual distributions equal to 16%
of its investment before the independent operator is entitled to
any compensation or distribution rights. The total investment is
estimated to be less than $200,000.
In purchasing the On-site Cogeneration Projects, the
Managing Shareholder concluded that the costs of engaging third
party managers to operate many smaller Projects would
significantly reduce total returns to the Trust. The Managing
Shareholder, after reviewing the alternatives, elected to create
an in-house management capability as a means of limiting costs,
acquiring valuable operating and industry knowledge and
increasing efficiency. It accordingly organized an affiliate,
Ridgewood Power Management Company ("RPMC"). Management
responsibility for the On-site Cogeneration Projects was
substantially transferred to the Managing Shareholder and RPMC at
the end of 1995 and the Managing Shareholder and RPMC are
currently operating or supervising operation of all of the
Trust's Projects except 12 small On-Site Cogeneration Projects
located in New York and Connecticut, which are managed by an
independent operator. See Item 10 -- Directors and Executive
Officers of the Registrant.
(iv) Providence Project
The Trust and Ridgewood Electric Power Trust IV, a similar
program organized by the Managing Shareholder ("Ridgewood Power
IV"), acquired in April 1996 all of the equity interest in the
Providence State Landfill Power Plant, located near Providence,
Rhode Island. The Trust invested $7.1 million in the Project and
Ridgewood Power IV supplied the remainder of the $20 million
investment in the Project. The acquisition cost was
approximately $15.5 million (including a $3 million partial
prepayment of Project debt as a condition of obtaining the
lenders' consents and transaction costs)and the remainder of the
investment by the programs represents funds applied to operating
reserves, working capital and reserves for capital improvements
and expansion. The Project is encumbered by $6 million of debt
maturing in installments through 2004.
The Project burns methane gas (the major component of
natural gas) generated by the decomposition of garbage in the
landfill as fuel for a 12.3 Megawatt capacity electric generation
plant. The facility has been in operation since 1990 and has a
Power Contract for 12.0 Megawatts with New England Power Company
with a 23 year term remaining.
The Project leases the right to use the landfill site from
the Rhode Island Resource Recovery Corporation, a state agency,
for a royalty of 15% of net Project revenues (increasing to 15%
to 18% in 2006) until 2020. The Project in turn subleases those
rights to Central Gas Limited Partnership ("Gasco"). Gasco,
which is not affiliated with the Trust, operates and maintains
the piping system and other facilities to collect the methane gas
from the Landfill and supply it to the Project. Gasco pays a
fixed rent, computed on the basis of the Project's generating
capacity, to the Project under the sublease, and the Project in
turn buys its fuel from Gasco at a formula price per kilowatt-
hour generated by the Project.
Since the Trust purchased the Project in April 1996, average
output from the existing eight engine-generator sets has risen by
approximately 33% from 9.2 Megawatts in the first three months of
1996 to 12.2 Megawatts in December 1996. Recent sales have
approached the 12.0 Megawatt maximum under the Power Contract.
In order to increase output to the maximum and to allow engines
to be rotated off-line for preventative maintenance, an
additional engine and generator set have been ordered and should
be installed at the Project in April 1997. This will increase
Project capacity by approximately 1/8 and permit a more balanced
operating rotation of engines. The entire additional capacity
will be sold under the existing Power Contract. Distributions
from the Project for 1996 to the Trust totalled $562,000 (a 7.9%
annual return).
The Trust currently has approximately $2.9 million of
uninvested funds, some of which may be required for maintenance
or replacement purposes or working capital. The Trust is
actively seeking additional small-scale Projects for investment.
If the Trust and another program with similar investment
objectives have funds available at the same time for investment
in the same or similar Projects, and a conflict of interest thus
arises as to which program will make the investment, the Managing
Shareholder will review the investment portfolio of each program.
It will make the investment decision on the basis of such
factors, among others, as the effects of the investment on the
diversification of each program's portfolio, potential
alternative investments, the effects investment by either program
would have on the program's risk-return profile, the estimated
tax effects of the investment on each program, the amount of
funds available and the length of time those funds have been
available for investment. If more than one program has funds
available for investment and the factors discussed above and
other considerations indicate that the Project has approximately
equal benefit for each Program, the Managing Shareholder will
generally allocate the opportunity to each program in order of
its organization date. In that event, the Managing Shareholder
will cause the oldest program to commit all of its reasonably
available funds to that opportunity; if those funds are
insufficient, the remainder of the opportunity will be offered to
each successive program with reasonably available funds until the
investment opportunity is exhausted. A similar process would be
followed for divestiture opportunities or competitive electricity
sales.
An additional conflict could arise where the entities make
investments in different forms, which would be the case where one
entity's investment took the form of equity and the other's took
the form of debt. Although it anticipates that this situation is
unlikely to arise, the Managing Shareholder, if practicable,would
attempt to resolve any conflict of this type by reference to the
terms negotiated by other debt or equity participants in the
relevant Project or similar Projects. Although the Managing
Shareholder believes these practices may reduce potential
conflicts of interest of this type, there can be no assurance
that the interests of the entities will not diverge.
(3) Project Operation.
Revenue from the San Joaquin, Byron and Providence Projects
primarily comes from Power Contracts with the local electric
utilities. The pricing provisions of these Power Contracts
usually have 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. Until
April 1997, approximately 90% of the capacity payment for the
Byron and San Joaquin Projects was allocated to the peak demand
months of April through October, and accordingly it was most
economic to operate the Projects only in those months and to
close them for the remainder of the year. In 1997, the
California Public Utilities Commission reduced the allocations to
the peak months to approximately 78%. This would cause a
significant decrease in Project income if six-month operations
were continued. Accordingly, effective April 1, 1997, the Byron
and San Joaquin Projects will be operated on a year-round
schedule. The Trust currently believes that substantially all
of the incremental costs of full-year operation will be recovered
from the energy payments and that the change will result in a
nominal decrease or increase in Project income. However, in
order for the thermal user of the San Joaquin Project to use heat
provided by the Project year-round, it must make approximately
$400,000 of improvements. The Trust has noted that the
additional heat has substantial economic value to the user and
has offered to finance the improvements itself, with repayment to
be made through a reduction in land lease payments by the Trust
to the user.
The Power Contracts permit the purchasing utility to
dispatch the facility (i.e., direct it to deliver a reduced level
of electric output) in certain circumstances. In such cases,
payments under the Power Contract are structured so that, even
when dispatching occurs, the facility continues to receive
capacity payments (which are intended to cover fixed costs and
which often provide substantially all of the facility's profits,
if any) while it receives reduced energy payments (which
primarily cover the variable operating, maintenance and fuel
costs associated with operating the facility at lower or higher
levels).
The On-site Cogeneration Projects are "inside-the-fence"
cogeneration facilities that are located on the sites of host
businesses or organizations and that sell both their electrical
output and their heat output to their hosts. The long-term
contracts with the hosts generally provide that the Trust is
compensated on a "shared savings" basis, under which the net cost
of the output is compared to the cost of purchasing the energy
from utility suppliers under a predetermined formula and the
Trust is paid a percentage of the computed savings. The Trust's
return is thus linked to the reliability and efficiency of its
operations as well as the cost of alternate sources. The On-Site
Cogeneration Project located in Rhode Island is leased to the
host and the Trust supplies operating and maintenance support on
a contract basis.
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 Trust, through the Managing Shareholder, operates most
of its Projects, and Project operating costs have been wholly
borne by the Trust as operating expenses and have not been borne
by the Managing Shareholder. Based on its experience with the
Trust's Projects and its experience managing other similar
investment programs, the Managing Shareholder believes that
contracting with third persons for the management of operating
Projects in many cases is not in the best interests of the Trust
because of the fragmentation of responsibility, the need for
extensive oversight of the managers, the loss in some cases of
economies of scale, the difficulty in some areas of obtaining
qualified managers and the generally high cost of management
contracts. These factors would be particularly burdensome in the
case of the On-site Cogeneration Projects, many of which are
small and located at multiple sites. Further, the use of third
persons to manage Projects deprives the Trust and other programs
of management experience and hands-on knowledge that otherwise
would be acquired by the Managing Shareholder or Affiliates.
The Managing Shareholder accordingly has organized RPMC to
provide operating management for facilities operated by its
investment programs, and has assigned day-to-day management of
all of its Projects, other than 12 small On-site Cogeneration
Projects located in New York and Connecticut, to RPMC. See Item
10 -- Directors and Executive Officers of the Registrant and Item
13 -- Certain Relationships and Related Transactions for further
information regarding the Operation Agreement and 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 or, in the
On-site Cogeneration Projects, by direct connections.
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. 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: under the shared savings
contracts, changes in demand directly and proportionately affect
the Trust's revenues.
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 their
status as a Qualifying Facility under PURPA, it is imperative
that each cogeneration Project continue to satisfy PURPA
cogeneration requirements as to the amount of thermal products
generated. Therefore, since the Byron and San Joaquin
cogeneration Projects have only two customers (the electric
energy purchaser and the thermal products purchaser), and because
it may be impractical to obtain replacement purchasers of either
the electrical or thermal output, loss of either of these
customers will likely have a material adverse effect on the
Project. The On-Site Cogeneration Projects sell all of their
output to a single customer and termination of those contracts
would end all revenue from those Projects, unless the engines and
other equipment could be economically moved to and installed on a
new host's site. The Providence Project burns methane gas
generated by the decomposition of garbage, which causes that
Project to be a "small power production facility" under PURPA.
This allows it to be a Qualifying Facility without the need to
sell thermal energy or to meet efficiency standards.
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.
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 changes,
many utilities have aggressively 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. It also will consider Projects selling power to retail
users rather than utilities.
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 make
attractive Projects available for investment by the Trust but may
also tend to depress the resale value of the Trust's projects.
The Byron, San Joaquin and Providence Projects have long-
term Power Contracts and the Trust intends to continue sales to
the local utilities under those contracts, with no current plans
to seek other customers. In the event that the Power Contracts
were terminated for any reason, the Trust might seek to sell
electricity to other customers, but its ability to do so
profitably cannot be assured.
The On-site Cogeneration Projects have output contracts with
their hosts that expire at various times from 1998 to 2005. The
Trust is reviewing each contract with a view towards
renegotiating or terminating it as the contract comes up for
renewal, or in some cases in advance of the renewal date. The
profitability of each contract to the Trust and the benefits to
the host depend upon the price of competing utility service and
the efficient operation of the Project. Accordingly, these
contracts are sensitive to outside market conditions.
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 to market its energy products is generally not a
factor in the current operations of the Trust since the major
Projects in which it invests and proposes to invest 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 seller of the On-site
Cogeneration Projects has warranted that each On-site
Cogeneration Project is a Qualifying Facility and the Trust
currently believes that all or substantially all of those
Projects are Qualifying Facilities. The Trust currently believes
that each of its other Projects is a Qualifying Facility.
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 PG&E, the
utility that purchases the electric output from the Byron and San
Joaquin Projects, 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 Projects do
not qualify for any given year. The Trust believes that those
Projects have qualified and will qualify.
(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 each of its Projects subject to the Act is coal
capable and thus qualifies for exemption from the Fuel Use Act.
(E) State Regulation. State public utility regulatory
commissions have broad jurisdiction over Independent Power
Projects which are not Qualifying Facilities under PURPA, and
which are considered public utilities in many states. In states
where the wholesale or retail electricity market remains
regulated, Projects that are not Qualifying Facilities may be
subject to state requirements to obtain certificates of public
convenience and necessity to construct a facility and
organizational, accounting, financial and other corporate matters
could be 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.
Certain states, including Rhode Island, also restrict the
ownership of inside-the-fence Projects by persons other than the
host, thus requiring the use of a lease structure or other
arrangements.
(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 14, 1994, 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 16, 1994, 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 the Managing Shareholder and two
individuals, Ralph O. Hellmold and Jonathan C. Kaledin, who also
serve as independent trustees of the Trust and who serve as
independent trustees of Ridgewood Electric Power II, and are
independent panel members of Ridgewood Electric Power Trust V,
each of which is a similar investment program organized by the
Managing Shareholder,, but who are not otherwise affiliated with
the Trust, the Managing Shareholder 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.
(d) Financial Information about Foreign and Domestic Operations
and Export Sales.
The Trust has invested in Projects located in California,
Connecticut, Massachusetts, New York and Rhode Island and has no
foreign operations.
(e) Employees.
The employees of the Byron and San Joaquin 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)), 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. The On-site
Cogeneration Projects are located on the hosts' sites and
generally do not occupy material amounts of space. 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
Byron Byron, Leased 2021 2 28,000 Gas-fired
California cogeneration
facility
San Joaquin Atwater, Leased 2021 1 25,000 Gas-fired
California cogeneration
facility
On-Site 31 sites Leased various n/a n/a Inside-the-
Cogeneration in CA, or fence,
CT, MA, licensed gas-fired
NY and RI or diesel-
fueled
cogeneration
engines and
generators
Providence Providence, Leased 2020 4 10,000 Landfill
Rhode Island gas-fired
generation
facility
Item 3. Legal Proceedings.
There are no legal proceedings involving the Trust. The
Trust's subsidiaries that own the San Joaquin and Byron Projects
filed suit in the Superior Court of California, City and County
of San Francisco, in February 1997 against PG&E, alleging breach
of the Power Contracts by PG&E's withholding a total of
approximately $164,000 as noted above. PG&E has answered the
complaint and has counterclaimed for all payments made to those
Projects.
The Trust's subsidiaries that own the On-site Cogeneration
Projects brought an arbitration proceeding in the amount of $4.1
million against the seller, a subsidiary of Eastern Utilities
Associates, Inc., before the American Arbitration Association in
Boston, Massachusetts in December 1996, alleging breaches of
representations and warranties made by the seller in the
agreements of sale. The seller has counterclaimed for
approximately $550,000 that it alleges it was owed for management
services during October, November and December 1995. The parties
are in the process of naming arbitrators.
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 1995.
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.
(a) Market Information.
The Trust sold 391.8444 Investor Shares of beneficial
interest in the Trust in its private placement offering of
Investor Shares which closed on May 31, 1995. 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. In addition, under federal laws regulating
securities the Investor Shares have restrictions on
transferability 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 (except for certain registrations that do not permit free
resale) in reliance upon what the Trust believes to be exemptions
from the registration requirements contained therein. Because
the Investor Shares have not been registered, they are
"restricted securities" as defined in Rule 144 under the 1933
Act.
(b) Holders
As of the date of this Form 10-K, there are 764 record
holders of Investor Shares.
(c) Dividends
The Trust made no distributions for the year 1994 and made
distributions as follows in the years 1995 and 1996:
Year ended Year ended
December 31, 1996 December 31, 1995
Total distributions
to Investors $3,694,661 $2,310,158
Distributions per
Investor Share 9,429 5,896
Distributions to
Managing Shareholder $37,312 17,522
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 14% 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 cash
released 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
Schedule for the for the for the
Selected Financial Data Year Ended Year Ended Period Ended
December 31, December 31, December 31,
1996 1995 1994
Total Fund Information:
Net revenue from
operating projects $3,525,613 $1,317,287 $0
Net income (loss) 2,541,686 1,440,550 (213,299)
Net assets (shareholders'
equity) 31,388,939 32,579,226 18,671,356
Investments in project
development and power
generation limited
partnerships 28,050,750 20,884,493 0
Total assets 31,430,075 32,651,668 18,405,145
Per Investor Share:
Revenues $9,630 $6,066 $1,178
Expenses 3,143 2,389 2,144
Net income (loss) 6,486 3,676 (966)
Net asset value 80,106 83,143 84,598
Distributions to Investors 9,429 5,896 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
Byron $428,540 $335,211
San Joaquin 779,409 982,076
On-site Cogeneration (total) 1,756,410 0
Massachusetts 660,201 0
Rhode Island 572,970 0
Coca-Cola 160,940 0
Others 362,299 0
Providence 562,427* 0
* April 16-December 31, 1996.
12 months ended December 31, 1996 versus 12 months ended
December 31, 1995.
Net income for 1996 was $2,542,000, a $1,101,000 increase
(76.4%) from the 1995 net income of $1,441,000. Revenues
increased $1,042,000 to $3,773,000 (38.2%), while Trust-level
expenses rose to $1,232,000 in 1996 from $936,000 in the prior
year, a $295,000 (31.5%) increase.
With the On-site Cogeneration Projects and the Providence
Project making their first distributions to the Trust in 1996,
income from power generation projects increased by 167.6%
($2,208,000) to $3,526,000, and concurrently, as funds were
invested in Projects, interest and dividend income decreased to
$248,000 in 1996 from $1,060,000 in 1995, an $812,000 (76.6%)
decrease. Distributions from the On-site Cogeneration Projects
were substantially below expectations (a 14.1% annual return in
1996), resulting from poor maintenance and operation and in some
cases a pattern of overbilling under prior ownership. These
Projects also suffered temporarily in late 1996 from sharp
increases in natural gas prices. Most of these Projects are
"shared savings" projects under which the Projects' billings are
computed with reference to utilities' retail electricity and gas
rates. Because utility rates to retail customers in many cases
did not rise as fast as the gas prices paid by the Projects,
margins were severely impacted in 1996. The high natural gas
prices began to abate in February 1997 and the Trust is taking
action to obtain longer-term gas supplies (where its customers
will cooperate) to reduce exposure to gas price fluctuations.
Distributions from the Providence Project were low (an 11.1%
annualized return) but within expectations. At the time the
Project was purchased its profitability was low and the Trust
planned to make significant investments and changes to operations
to increase the Project's efficiency and profitability. As
discussed above, output has increased by an average of 33% in the
8 1/2 months of ownership by the Trust.
Trust-level expenses increased by 31.5% from 1995 to 1996,
but the nature of those expenses changed significantly as the
Trust ended the major portion of its investment program. The
investment fee, which is charged in the year capital
contributions are made and which is paid to the Managing
Shareholder to compensate it for investment advice and
evaluation, was $344,000 in 1995 but was not charged in 1996,
reflecting the conclusion of the offering of Investor Shares in
1995. The management fee, which is charged on the basis of the
Trust's net assets, increased from $482,000 in 1995 to $794,000
in 1996, a $312,000 (64.6%) increase. The management fee is
expected to remain at that level.
The investment process caused significant increases in due
diligence and project investigation expenses payable to third
parties, which increased to $258,000 in 1996 from $8,000 in 1995.
These expenses are not expected to recur at those levels. The
Trust also incurred writeoffs of $113,000 for the four small
discontinued On-site Cogeneration Projects.
Other Trust-level operating expenses included accounting and
legal fees, which decreased $42,000 (46.4%) from $90,000 in 1995
to $48,000 in 1996, as the start-up period ended, and other
expenses, which rose from $12,000 to $18,000 (50.5%).
12 months ended December 31, 1995 versus period ended
December 31, 1994.
Net income for calendar 1995 was $1,440,550 as compared to a
net loss of $231,299 for 1994 (January 3, 1994 through December
31, 1994). The 1995 results reflect the ending of the Trust's
offering of Investor Shares and the beginning of operations.
Revenues increased by 814.5% from 1994, as two Projects were
acquired and began to distribute cash flow to the Trust, and
interest revenue increased because of the larger amount of
offering proceeds received and awaiting investment.
Expenses increased by 97.9% to $936,000; however, $344,000
of this amount reflects payment of the investment fee on sales of
Investor Shares made during 1995. This fee will not recur. The
remainder of the increase is attributable to the annual
management fee paid for the first time in 1995 to the Managing
Shareholder, and to increases in accounting and legal expenses as
a consequence of beginning operations.
Trends affecting the independent power industry generally
are described at Item 1 -- Business.
Liquidity and Capital Resources.
The Trust currently intends to apply up to $400,000 of its
$2.9 million of uninvested funds to modifications to the host's
facilities at the San Joaquin Project to allow year-round
operation. It anticipates that demands in 1997 for maintenance
and improvement funds and working capital over and above cash
flow generated by the Projects will not be significant.
Therefore, the Trust will attempt to invest the remaining funds
in a small-scale Project or Projects, such as the small
cogeneration Projects described above at Item 1(c)(2) -- Business
- -- Narrative Description of Business -- The Trust's Investments.
The Trust anticipates that its cash flow during 1997 and
unexpended offering proceeds 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 certain of the On-Site Cogeneration Projects,
although prices began to fall toward prior levels in February
1997. As the Byron and San Joaquin Projects move to 12 month
operation, they will become exposed to wintertime fluctuations in
gas prices. The Managing Shareholder is considering entering
into long-term gas supply arrangements to reduce exposure to the
gas price fluctuations, but the relatively small size of the
Projects as customers may limit its ability to do so. The
Providence Project, which burns landfill gas, has no exposure to
gas price fluctuations.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Statement of Operations for Years
ended December 31, 1996 and
1995 and Period from Commencement of
Share Offering (January 4, 1994)
through December 31, 1994 F-3
Balance Sheet at December 31, 1996 and 1995 F-4
Statement of Changes in Shareholders'
Equity for Years ended
December 31, 1996 and 1995 and
Period from Commencement of Share
Offering through December 31, 1994 F-5
Statement of Cash Flows for Years
ended December 31, 1996 and 1995
and Period from Commencement of Share
Offering through December 31, 1995 F-6 -F-7
Notes to Financial Statements F-8 to F-13
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, 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 II ("Ridgewood Power II"), 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 II, 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, the Trust, Ridgewood Power
I, Ridgewood Power II, 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 sponsored by the Managing Shareholder and RPMC
in November 1996. Under a consulting arrangement, Mr. Quinn
devoted a majority of his time to the business of Ridgewood Power
and RPMC while continuing his other activities, which concluded
on March 31, 1997. On that date, he became a full-time officer
of Ridgewood Power 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, the Trust, RPMC, Ridgewood Power I,
Ridgewood Power II 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.
Donald C. Stewart, age 52, serves as an advisor and
consultant to the Trust and is expected to be actively involved
in reviewing the Trust's acquisitions and operations. Mr.
Stewart has 25 years of expertise in the field of independent
power generation, fuel procurement, engineering and finance. Mr.
Stewart spent the first ten years of his business career as a
certified public accountant with a major international firm. He
has been the Chairman of Vermont Gas Systems, a regulated public
utility, President of Consolidated Power Company, a developer of
large scale cogeneration projects and President of Hercules
Engines, Inc., a manufacturer of industrial engines and
electrical generation equipment. Mr. Stewart has a Bachelor of
Science degree from Lehigh University.
Douglas R. Wilson, age 36, joined Mr. Stewart in October
1996 to provide financial advisory services for evaluating,
structuring and overseeing the Trust's investments. He has over
13 years of capital markets experience, including specialization
in complex lease and project financings and in energy-related
businesses. From January 1993 until October 1996, he was
associated with BTM Capital Corporation, the structured finance
unit of the Bank of Tokyo-Mitsubishi. Before that he earned a
Master's degree in Business Administration from the Wharton
School of the University of Pennsylvania from September 1990
through May 1992. He has a Bachelor of Business Administration
degree from the University of Texas.
(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 II, an independent power
program sponsored by Ridgewood Power. Neither Mr. Hellmold nor
Mr. Kaledin is otherwise affiliated with the Trust, any of the
Trust's officers or agents, Ridgewood Power, any other Trustee,
any affiliates of the Managing Shareholder and any other
Trustees, or any director, officer or agent of any of the
foregoing.
Ralph O. Hellmold, age 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. Mr. Hellmold is also a
director of Core Materials Corp., Columbus, Ohio.
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 each in Ridgewood Power I and Ridgewood
Power II, 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.
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 Energy
Holding Corporation. Legal title to Trust Property is now and in
the future will be in the name of the Trust, if possible, or
Ridgewood Energy Holding Corporation as trustee. Ridgewood
Energy Holding Corporation is also a trustee of Ridgewood Power
I, Ridgewood Power II, Ridgewood Power IV and of an oil and gas
business trust sponsored by Ridgewood and is expected to be a
trustee of other similar entities that may be organized by the
Managing Shareholder and Ridgewood Energy. The President, sole
director and sole stockholder of Ridgewood Energy Holding
Corporation is Robert E. Swanson; its other executive officers
are identical to those of the Managing Shareholder. The principal
office of Ridgewood Energy Holding Corporation 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
Each of the Independent Trustees and executive officers of
the Trust 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. Mr. Quinn and Mr. Brown each made one late filing of
Form 3 in December 1996 and each of the others made one late
filing in April 1997. 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 all of the Trust's
Projects, effective January 1, 1996. 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 as operating
expenses, as well as billing, payment and other Project-level
accounting and service costs. 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 principal 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 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 1995 and following years, the
Trust paid each Independent Trustee $5,000 for his services. The
Board of the Trust is entitled to review the compensation payable
to the Independent Trustees annually and increase or decrease it
as the Board sees reasonable. The Trust is not entitled to pay
the Independent Trustees compensation for consulting services
rendered to the Trust outside the scope of their duties to the
Trust without prior Board approval.
Ridgewood Energy Holding Corporation, 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 391.8444 Investor Shares (approximately $39.2
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
May 31, 1995. Further details concerning the offering are set
forth above at Item 1 -- Business.
The Managing Shareholder purchased for cash in the offering
one full Investor Share. 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 purchase 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 the
Managing Shareholder (excluding its interest in the Trust
attributable to Investor Shares it acquired in the offering).
The management rights of the Managing Shareholder are described
in further detail above at Item 1 -- Business and in Item 10 -
Directors and Executive Officers of the Registrant. Its
beneficial interest in cash distributions of the Trust and its
allocable share of the Trust's net profits and net losses and
other items attributable to the Management Share are described in
further detail below at Item 13 -- Certain Relationships and
Related Transactions..
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less
reasonable reserves which the Trust deems necessary to cover
anticipated Trust expenses, is to be distributed to the Investors
and the Managing Shareholder (collectively, the "Shareholders"),
from time to time as the Trust deems appropriate. Prior to
Payout (the point at which Investors have received cumulative
distributions equal to the amount of their capital
contributions), each year all distributions from the Trust, other
than distributions of the revenues from dispositions of Trust
Property, are to be allocated 99% to the Investors and 1% to the
Managing Shareholder until Investors have been distributed during
the year an amount equal to 14% of their total capital
contributions (a "14% Priority Distribution"), and thereafter all
remaining distributions from the Trust during the year, other
than distributions of the revenues from dispositions of Trust
Property, are to be allocated 80% to Investors and 20% to the
Managing Shareholder. Revenues from dispositions of Trust
Property are to be distributed 99% to Investors and 1% to the
Managing Shareholder until Payout. In all cases, after Payout,
Investors are to be allocated 80% of all distributions and the
Managing Shareholder 20%.
For any fiscal period, the Trust's net profits, if any,
other than those derived from dispositions of Trust Property, are
allocated 99% to the Investors and 1% to the Managing Shareholder
until the profits so allocated offset (1) the aggregate 14%
Priority Distribution to all Investors and (2) any net losses
from prior periods that had been allocated to the Shareholders.
Any remaining net profits, other than those derived from
dispositions of Trust Property, are allocated 80% to the
Investors and 20% to the Managing Shareholder. If the Trust
realizes net losses for the period, the losses are allocated 80%
to the Investors and 20% to the Managing Shareholder until the
losses so allocated offset any net profits from prior periods
allocated to the Shareholders. Any remaining net losses are
allocated 99% to the Investors and 1% to the Managing
Shareholder. Revenues from dispositions of Trust Property are
allocated in the same manner as distributions from such
dispositions. Amounts allocated to the Investors are apportioned
among them in proportion to their capital contributions.
On liquidation of the Trust, the remaining assets of the
Trust after discharge of its obligations, including any loans
owed by the Trust to the Shareholders, will be distributed,
first, 99% to the Investors and the remaining 1% to the Managing
Shareholder, until Payout, and any remainder will be distributed
to the Shareholders in proportion to their capital accounts.
The Trust did not make any distributions in 1994 to the
Managing Shareholder (which is a member of the Board of the
Trust) or any other person and made distributions in 1995 and
1996 as stated at Item 5 -- Market for Registrant's Common Equity
and Related Stockholder Matters. The Trust paid fees to the
Managing Shareholder and its affiliates as follows:
Fee Paid to 1996 1995 1994
Management Managing $794,026 $482,000 $0
fee Shareholder
Cost
reimbursements* RPMC 11,566,400 0 0
Investment Managing 0 343,779 421,011
fee Shareholder
Placement Ridgewood 0 147,950 188,847
agent fee Securities
and sales Corporation
commissions
Organizational, Managing 0 860,195 1,088,727
distribution Shareholder
and offering
fee
* Prior to 1996, these costs were either paid by the Trust or by the Projects
directly. These include all payroll, parts, routine maintenance and other
expenses (except for royalties for landfill gas) of operating Projects that
are not operated by non-affiliated managers, and an allocation of RPMC's
overhead.
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 1995 for
payroll and other costs of operation of the Trust's Projects.
Beginning in 1996, these reimbursements were paid to RPMC. The
reimbursements to RPMC, which do not exceed its actual costs, 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 of Registrant's
Registration Statement filed with the Commission on
February 15, 1994.
3B. Declaration of Trust of the Registrant is incorporated
by reference to Exhibit 3B of Registrant's
Registration Statement filed with the Commission on
February 19, 1994.
10A. Management Agreement dated as of January 3, 1994
between the Registrant and Ridgewood Power Corporation
is incorporated by reference to Exhibit 10A of
Registrant's Registration Statement filed with the
Commission on February 15, 1994.
10B. Acquisition Agreement dated as of January 9, 1995
among JRW Cogen, Inc., and NorCal Cogen, Inc., as
Sellers, and RW Central Valley, Inc., and Ridgewood
Electric Power Trust III, as Purchasers, is
incorporated by reference to Exhibit 2(i) to
Registrant's Form 8K filed with the Commission on
February 16, 1995.
10C. Agreement of Merger dated as of January 9, 1995 among
Altamont Cogeneration Corporation, NorCal Altamont,
Inc., and Byron Power Partners, L.P. is incorporated
by reference to Exhibit 2(ii) to Registrant's Form 8K
filed with the Commission on February 16, 1995.
10.D Asset Acquisition Agreement by and
among Northeast Landfill Power Joint Venture,
Northeast Landfill Power Company, Johnson
Natural Power Corporation and Ridgewood
Providence Power Partners, L.P. , is incorporated by
reference to Exhibit 2 of the Registrant's Current
Report on Form 8-K filed with the Commission on
May 2, 1996.
10.E Operation Agreement, dated as of April 16,
1996, among Ridgewood/Providence Corporation,
Ridgewood/Providence Power Partners, L.P. and
Ridgewood Power Management Corporation Page 75
The Registrant agrees to furnish supplementally a copy of
any omitted exhibit or schedule to agreements filed as exhibits
to the Commission upon request.
21. Subsidiaries of the Registrant. Incorporated by
reference to Exhibit 21 of the Registrant's Annual
Report on Form 10-K for the year ended December 31,
1995.
24. Powers of Attorney Page 81
27. Financial Data Schedule Page 82
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
Signature Title Date
RIDGEWOOD ELECTRIC POWER TRUST III
(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 and
Martin V. Quinn Chief Financial Officer April 15, 1997
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
* As attorney-in-fact for the Independent Trustee
<PAGE>
Ridgewood Electric Power Trust III
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 III
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 III at
December 31, 1996 and 1995, and the results of its operations and
its cash flows for each of the two years in the period ended
December 31, 1996 and the period January 3, 1994 (commencement of
share offering) through December 31, 1994, in conformity with
generally accepted accounting principles. These financial
statements are the responsibility of the Trust's management; our
responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these
statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the
opinion expressed above.
As explained in Note 3, the financial statements include
investments, valued at $28,050,750 and %20,884,493 (89% and 64%
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 III
Statement of Operations
Commencement
of Share
Offering
(January 3, 1994)
Year Ended Year Ended Through
December 31, December 31, December 31,
1996 1995 1994
Revenue:
Income from power
generation projects $ 3,525,613 $ 1,317,287 $ ---
Interest and dividend
income 247,762 1,059,570 259,911
3,773,375 2,376,857 259,911
Expenses:
Investment fee --- 343,779 421,011
Project due diligence
costs 258,378 8,210 25,105
Management fee 794,026 482,309 ---
Accounting and legal fees 48,231 90,043 16,199
Miscellaneous 18,012 11,966 10,895
Writedown of limited
partnership investments 113,042 --- ---
1,231,689 936,307 473,210
Net income (loss) $ 2,541,686 $ 1,440,550 $ (213,299)
Allocation to:
Shareholders $ 2,516,269 $ 1,426,145 $ (211,166)
Managing shareholder 25,417 14,405 (2,133)
$ 2,541,686 $ 1,440,550 $ (213,299)
See accompanying notes to financial statements.
-F3-
<PAGE>
Ridgewood Electric Power Trust III
Balance Sheet
December 31,
1996 1995
Assets:
Investments in power generation projects $ 28,050,750 $ 20,884,493
Cash and cash equivalents 2,959,240 10,972,576
Due from affiliates 109,085 299,194
Deferred due diligence costs 30,000 303,213
Interest receivable --- 51,233
Other assets 281,000 140,959
Total assets $ 31,430,075 $ 32,651,668
Liabilities and Shareholders' Equity:
Accounts payable and accrued expenses $ 41,136 $ 72,442
Shareholders' equity:
Shareholders' equity
(391.8444 shares issued
and outstanding) 31,406,084 32,584,476
Managing shareholder's
accumulated deficit (17,145) (5,250)
Total shareholders' equity 31,388,939 32,579,226
Total liabilities and
shareholders' equity $ 31,430,075 $ 32,651,668
See accompanying notes to financial statements.
-F4-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Changes in Shareholders' Equity
Managing
Shareholders Shareholder Total
Initial capital
contributions, net
(220.7053 shares) $ 18,484,655 $ --- $ 18,484,655
Net loss for the period (211,166) (2,133) (213,299)
Shareholders' equity,
December 31, 1994
(220.7053 shares) 18,273,489 (2,133) 18,271,356
Capital contributions,
net (171.1391 shares) 15,195,000 --- 15,195,000
Cash distributions (2,310,158) (17,522) (2,327,680)
Net income for the year 1,426,145 14,405 1,440,550
Shareholders' equity,
December 31, 1995
(391.8444 shares) 32,584,476 (5,250) 32,579,226
Cash distributions (3,694,661) (37,312) (3,731,973)
Net income for the year 2,516,269 25,417 2,541,686
Shareholders' equity,
December 31, 1996
(391.8444 shares) $ 31,406,084 $ (17,145) $ 31,388,939
See accompanying notes to financial statements.
-F5-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Cash Flows
Commencement
of Share
Offering
(January 3, 1994)
Year Ended Year Ended Through
December 31, December 31, December 31,
1996 1995 1994
Cash flows from
operating activities:
Net income (loss) $ 2,541,686 $ 1,440,550 $ (213,299)
Adjustment to reconcile
net income (loss) to net
cash used in operating
activities:
Writedown of limited
partnership investments 113,042 --- ---
Purchase of investments
in power generation
projects (7,279,299) (20,884,493) ---
Proceeds from transfer of
investment 353,619 --- ---
Changes in assets
and liabilities:
Increase in
due from affiliates (109,085) (299,194) ---
Decrease (increase) in
deferred due diligence costs 273,213 (140,683) (162,530)
Decrease (increase) in
interest receivable 51,233 (51,233) ---
Increase in other assets (140,041) (135,959) (5,000)
(Decrease) increase in
accounts payable and
accrued expenses (85,731) (61,347) 133,789
Total adjustments (6,823,049) (21,572,909) (33,741)
Net cash used in operating
activities (4,281,363) (20,132,359) (247,040)
Cash flows provided by
financing activities:
Proceeds from shareholders'
contributions --- 17,527,545 21,499,170
Selling commissions and
distribution and offering
costs paid --- (2,332,545) (3,014,515)
Cash distributions to
shareholders (3,731,973) (2,327,680) ---
-F6-
<PAGE>
Net cash provided by
(used in) financing
activities (3,731,973) 12,867,320 18,484,655
Net (decrease) increase in
cash and cash equivalents (8,013,336) (7,265,039) 18,237,615
Cash and cash equivalents,
beginning of period 10,972,576 18,237,615 ---
Cash and cash equivalents,
end of period $ 2,959,240 $ 10,972,576 $ 18,237,615
See accompanying notes to financial statements.
-F7-
<PAGE
Ridgewood Electric Power Trust III
Notes to Financial Statements
1. Organization and Purpose
Nature of business
Ridgewood Electric Power Trust III (the "Trust") was formed
as a Delaware business trust on December 6, 1993, 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 3, 1994. The Trust
commenced operations on April 16, 1994, and discontinued its
offering of Trust shares on May 31, 1995.
The Trust has been 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 both electricity and
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 16, 1994, 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 power generation projects
The Trust holds investments in power generating 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
original maturities of three months or less as cash and cash
equivalents.
-F8-
<PAGE>
Ridgewood Electric Power Trust III
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 as 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. Investments in Power Generation Projects
The Trust had the following investments in power generation
projects:
Fair values as of December
31,
1996 1995
Power generation projects:
JRW Associates, L.P. $ 5,305,298 $ 5,305,298
Byron Power Partners, L.P. 3,138,072 2,958,072
Ridgewood Providence Power
Partners, L.P. 7,130,000 ---
On-site Cogeneration Projects:
Ridgewood/Rhode Island PPLP 3,722,618 3,722,618
Ridgewood/Mass. PPLP 3,223,881 3,223,881
Ridgewood/Elmsford PPLP 1,430,136 1,430,136
Other On-site Cogeneration
Project Partnerships 4,100,745 4,244,488
$ 28,050,750 $ 20,884,493
JRW Associates, L.P. (known as San Joaquin Power Company)
On January 17, 1995, the Trust acquired 100% of the existing
partnership interests of JRW Associates, L.P., which owns and
operates an 8.5 megawatt electric cogeneration facility, located
in Atwater, California. The aggregate cost of the investment was
$5,305,298. The Trust received distributions of $779,409 and
$982,076 from the project in 1996 and 1995, respectively.
Byron Power Partners, L.P. (known as Byron Power Company)
In January 1995, the Trust caused the formation of Byron
Power Partners, L.P. in which the Trust owns 100% of the existing
partnership interests. On January 17, 1995, Byron Power
Partners, L.P. acquired a 5.7 megawatt electric cogeneration
facility, located in Byron, California. As of December 31, 1996
and 1995, the Trust's investment in the partnership was
$3,138,072 and $2,958,072, respectively. The Trust received
distributions of $428,540 and $335,211 from the project in 1996
and 1995, respectively.
-F9-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
Providence Project
In 1996, Ridgewood Providence Power Partners, L.P. was
formed as a Delaware limited partnership ("Providence Power").
The Trust invested $7,058,700 and owns a 35.7% limited
partnership interest in Providence Power. In addition, Ridgewood
Providence Power Corporation was formed as a Delaware corporation
("RPPCorp."). The Trust invested $71,300 and owns 35.7% of the
outstanding common stock of RPPCorp., which is the sole general
partner of Providence Power.
On April 16, 1996, Providence Power purchased substantially
all of the net assets of Northeastern Landfill Power Joint
Venture. The assets acquired include a 12.3 megawatt ("MW")
capacity electrical generating station, located at the Central
Landfill in Johnston, Rhode Island (the "Providence Project").
The Providence Project includes eight reciprocating electric
generator engines, which are fueled by methane gas produced and
collected from the landfill. The electricity generated is sold
to New England Power Corporation under a long-term contract. The
purchase price was $15,533,021 cash, including transaction costs
and repayment of $3,000,000 of principal on senior secured non-
recourse notes payable. In addition, Providence Power assumed
the obligation to repay the remaining principal outstanding of
$6,310,404 on the senior secured non-recourse notes payable.
Through ownership in RPPCorp. and Providence Power, the
Trust owns 35.7% of the Providence Project. The remaining 64.3%
is owned by Ridgewood Electric Power Trust IV ("Trust IV").
Ridgewood Power Corporation is the managing partner of the Trust
and Trust IV. In 1996, the Trust received distributions of
$562,427 from the Providence Project.
On-site Cogeneration Projects
On September 29, 1995, the Trust acquired a portfolio of 35
projects from affiliates of Eastern Utilities Associates ("EUA"),
which sell electricity and thermal energy to industrial and
commercial customers. The projects are held in eight limited
partnerships of which the Trust is the sole limited partner and
is the sole owner of each of the general partners. In the
aggregate, the projects have 13.7 MW of base load and 5.7 MW of
backup and standby capacity. The Trust paid a total of
$11,300,000 for the projects and has invested additional amounts
in working capital. EUA operated the projects under a transition
agreement until January 1, 1996, at which time Ridgewood Power
Management Corporation, an affiliate of the Trust, assumed
operational control. No distributions were made by these
projects in 1995. The Trust received distributions of $1,756,410
from these projects in 1996.
Ridgewood/Rhode Island Power Partners L.P.
Ridgewood/Rhode Island Power Partners Limited Partnership
(the "Partnership") leases three 1,400 kilowatt Cooper Superior
gas fired generator sets with heat recovery to a Rhode Island
manufacturing company under a lease expiring in 2006. Two
engines are in regular use and one engine is on standby. The
partnership receives a monthly fixed lease payment and a
maintenance payment, which escalates over the term of the lease.
The Partnership is responsible for maintaining the engines and
related equipment. At the expiration of the lease, the lessee
may purchase the equipment from the partnership for its fair
market value. The Trust and customer are currently in
negotiations to revise the lease. As of December 31, 1996 and
1995, the total cost of the Trust's investment in the partnership
was $3,722,618. The Trust received distributions of $572,970
from the project in 1996.
-F10
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
Ridgewood/Mass. Power Partners L.P.
Ridgewood/Mass. Power Partners L.P. (the "Partnership") owns
two projects. The first is a 3.5 MW base load, simple cycle,
dual-fuel, combustion turbine powered plant with a heat recovery
steam generator which sells electric power and steam to a
manufacturing facility on whose site the plant is located. The
project includes two 1.6 MW Caterpillar diesel engine generator
sets to provide backup power. The project sells electric and
thermal energy to the manufacturing facility at the project's
production cost (as defined in the Energy Service Agreement) plus
a share of the savings (the difference between what the electric
and thermal energy would have cost the company absent the
cogeneration plant). The Energy Service Agreement expires at the
end of 2005. As of December 31, 1996 and 1995, the total cost
of the Trust's investment in the partnership was $3,223,881. The
Trust received distributions of $660,201 from the project in
1996. The Partnership also owns a smaller group of four
cogeneration generator sets totaling 255 kilowatt ("KW") serving
a residential complex in Worcester, Massachusetts. The energy
services agreement ("ESA") provides that the partnership receives
from the customer the cost to purchase electricity and natural
gas from the local utility, less a guaranteed savings based on
the utility's current rates. The ESA expires in 2004.
Ridgewood/Elmsford Power Partners, L.P.
Ridgewood/Elmsford Power Partners, L.P. (the "Partnership")
owns one cogeneration project consisting of two 665 KW (1,330 KW
total) dual-fuel Cooper Superior engine generator sets with heat
recovery and a Caterpillar 600 kilowatt standby diesel generator
set. The Energy Services Agreement ("ESA") expires in 2005 and
provides that the Partnership receives its production costs (as
defined in the ESA) plus a share of the excess of the customer's
avoided cost over production costs. As of December 31, 1996 and
1995, the total cost of the Trust's investment in the partnership
was $1,430,136. The Trust received distributions of $160,940
from the project in 1996.
The "Other On-site Cogeneration Project Partnerships"
The "other on-site cogeneration project partnerships"
consist of five partnerships, which own 30 of the 35 projects
acquired from Eastern Utilities Associates. These 30 projects
represent approximately one-third of the Trust's investment in
the on-site cogeneration projects. All thirty are gas-fired
cogeneration projects, located in California, Connecticut or New
York. Their energy service agreements have terms expiring
between September 1996 and 2011. The projects represent 5.5 MW
of base load capacity. The largest project is 660 KW or 12% of
the capacity. The projects range in size from 30 KW to 660 KW.
As of December 31, 1996 and 1995, the total cost of the Trust's
investment in the partnerships was $4,100,745 and $4,244,488,
respectively. In 1996, the Trust wrote-off four small projects
amounting to $113,042. The Trust received distributions of
$362,299 from the projects in 1996.
California Pumping Project
During 1995, the Trust acquired 11 natural gas fueled diesel
engines, which drive deep irrigation well pumps in Ventura
County, California. The aggregate purchase price was $353,619.
On December 31, 1995, the engines were sold to an affiliate at
book value and no gain or loss was recognized on the transaction.
-F11-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
4. Transactions With Managing Shareholder And Affiliates
The Trust also pays to the managing shareholder a
distribution and offering fee up to 5% of each capital
contribution made to the Trust. The fee is intended to cover
legal, accounting, consulting, filing, printing, distribution,
selling and closing costs for the offering of the Trust. For the
periods ended December 31, 1996, 1995 and 1994, the Trust paid
fees for these services to the managing shareholder totaling
zero, $860,195 and $1,088,727, respectively. These fees were
recorded as a reduction in shareholders' capital contributions.
The Trust pays to the managing shareholder an investment fee
up to 2% of each capital contribution made to the Trust. The fee
is payable to the managing shareholder for its services in
investigating and evaluating investment opportunities and
effecting transactions for investing the capital of the Trust.
For the periods ended December 31, 1996, 1995 and 1994, the Trust
paid investment fees to the managing shareholder of zero,
$343,779 and $421,011, respectively.
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 and 1995,
the Trust paid management fees to the managing shareholder of
$794,026 and $482,309, respectively.
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 that
year an amount equal to 14% of their equity contribution.
Thereafter, the managing shareholder is entitled to receive 20%
of the distributions for the remainder of the year. The managing
shareholder is entitled to receive 1% of the proceeds from
dispositions of Trust properties until the shareholders have
received cumulative distributions equal to their original
investment ("Payout"). 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 one share of the Trust
for $84,000. Through the closing of the Trust's offering on May
31, 1995, commissions and placement fees of $390,844 were earned
by Ridgewood Securities Corporation, an affiliate of the managing
shareholder.
-F12-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
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 projects
operated by the Trust. Ridgewood Management charges the projects
at its cost for these services and for the allocable amount of
certain overhead items. Allocations of costs are on the basis of
identifiable direct costs, time records or in proportion to
amounts invested in projects managed by Ridgewood Management.
5. Arbitration and Litigation
The Trust's subsidiaries that own the on-site cogeneration
projects brought an arbitration proceeding in the amount of
$4,100,000 against Eastern Utilities Associates, Inc., the former
owner. The Trust claims breaches of representations and
warranties made by the former owner at the time the on-site
cogeneration projects were acquired. The former owner has
counterclaimed for approximately $550,000 for alleged unpaid
management services. The Trust has not reflected the amounts
claimed in its financial statements pending the outcome of the
arbitration proceeding.
In February 1997, the Trust's subsidiaries that own the San
Joaquin and Byron projects filed suit in the Superior Court of
California against Pacific Gas and Electric Company ("PG & E")
for breach of the power sales contracts. The Trust argues PG & E
has improperly withheld approximately $200,000 of capacity
payments. The Trust has not reflected the withheld capacity
payments in its financial statements pending the outcome of the
suit.
6. Subsequent Event
Ridgewood AES Power Partners, L.L.C.
The Trust, in conjunction with its managing shareholder, has
accepted a proposal to invest in a cogeneration project at the
North Shore University Hospital, located on Long Island in Nassau
County, New York. The Trust is to receive a 16% preferred return
and 50 % of the net cash flow in excess of the preferred return.
As of December 31, 1996, the Trust's investment in the project
was $30,000. The Trust's total purchase price is estimated to be
$60,000.
-F13-
OPERATION AGREEMENT
This Operation Agreement (the "Agreement") is made as
of the 16th day of April, 1996, by and among
Ridgewood/Providence Power Partners,, L.P., a Delaware
limited partnership ("Owner"), Ridgewood/Providence
Corporation, a Delaware corporation ("General Partner"), and
Ridgewood Power Management Corporation, a Delaware
corporation ("RPMC").
RECITALS
Some of the facts and circumstances surrounding this
Agreement are the following:
The Owner owns an independent power project. The
General Partner is responsible for the operation and
management of the Owner's project. The Owner and the
General Partner are beneficially owned by one or more
business trusts organized and managed by Ridgewood Power
Corporation.
Ridgewood Power Corporation ("Ridgewood Power") has
caused RPMC to be created in order to provide centralized
operation, management and other services for projects
beneficially owned by the business trusts, and has caused
the parties to enter into this Agreement. The project or
projects for which RPMC will provide services (the
"Projects") are listed on Exhibit A to this Agreement.
Section 1. Services of RPMC.
1.1. General. The Owner employs RPMC to provide the
services described below and RPMC agrees to do so.
RPMC shall provide operating personnel for the
Projects and will be responsible for all day-to-day
operations of the Projects. The services provided
by RPMC include, without limitation, management,
purchasing, engineering, planning, maintenance,
administrative, legal, financial, and regulatory
services, as well as any other services Owner
(through the General Partner) may need or request.
1.2. Responsibility. RPMC shall act on behalf of and
under the general direction of the General
Partner. Although the General Partner is
empowered to specify the responsibilities of RPMC,
to oversee RPMC and to direct RPMC to take action,
the General Partner shall not specify how RPMC is
to perform its obligations. RPMC is an
independent contractor and not an agent of the
General Partner or the Owner. Ridgewood Power is
authorized to act on behalf of the General Partner
in supervising RPMC.
Section 2. Reimbursement of RPMC.
RPMC shall charge Owner for all direct costs incurred
in connection with the Projects and shall also charge Owner
an allocable amount of RPMC's indirect costs and overhead as
described below.
2.1. Direct Costs. Costs and expenses paid by RPMC that
relate to a single Project shall be allocated to
that Project.
2.2. Multiple Project Costs and Other Indirect Costs.
Costs and expenses paid by RPMC that relate to more
than one Project or to Projects and to facilities
owned by other persons shall be allocated among the
Projects and facilities affected on the basis of
time records, comparative value of the work to each
Project or facility, size of each Project or
facility, number of employees affected, asset value
of Project or facility, investment in each Project
or facility or another reasonable basis approved
by RPMC and the General Partner. A share of
overhead and other indirect costs that do not
relate to identifiable Projects shall be allocated
to Owner on the basis of investment in each
Project or another reasonable basis approved by
RPMC and the General Partner. All allocations of
costs under this Section 2.2 shall be made
consistently with generally accepted accounting
principles, consistently applied.
2.3. Payment. RPMC shall be reimbursed by Owner for all
costs incurred by it and allocable to Projects
under Sections 2.1 and 2.2. RPMC may operate or
participate in a centralized cash management system
with Owner, Ridgewood Power and other entities
affiliated with Ridgewood Power and payments may be
made through that system without the need for Owner
to reimburse RPMC directly. If payments are not
made through that system, Owner shall reimburse
RPMC at least monthly and not later than 15 days
after receipt of a statement from RPMC.
2.4. Common Expenses with Ridgewood Power. If Ridgewood
Power provides space, facilities, personnel, goods
or services to RPMC that are used by RPMC in
performing its responsibilities under this
Agreement, RPMC shall not charge or allocate
charges to Projects or to other facilities that
RPMC manages in excess of the amounts, if any,
charged to RPMC by Ridgewood Power for those
items.
2.5. General Limitation. RPMC shall not be
reimbursed for any amount in excess of the actual
or properly allocated cost of the goods and
services it provides to the Projects.
Section 3. Indemnification.
3.1. Indemnification of Owner. RPMC shall indemnify and
hold Owner harmless from and against any claim,
liability, damage, expense, legal action, lien,
loss or other obligation arising out of the actions
or omissions of RPMC taken under this Agreement or
in connection with this Agreement or the Projects.
RPMC shall indemnify the partners of the Owner and
their directors, officers, employees, agents,
affiliates, successors and assigns on the same
basis as the Owner.
3.2. Waivers of Subrogation and Contribution. RPMC
waives any right of subrogation or contribution
against the Owner or other persons indemnified
under Section 3.1 in connection with any liability
or obligation satisfied by RPMC and relating to
RPMC's responsibilities under this Agreement.
Section 4. Term of Agreement.
This Agreement may be terminated at any time without
penalty by either the Owner or RPMC on 60 days' prior
written notice to the other parties. This Agreement may
also be terminated by action of any trust or investment
program that is a beneficial owner of equity securities of
the Owner if (a) the managing shareholder, general partner
or board of directors of the trust or program so decides or
(b) a majority in interest of the holders of equity
securities of the trust or program (excluding any management
share or other special equity security owned solely by a
managing shareholder or general partner) vote to terminate
this Agreement. In that case, this Agreement terminates 60
days after all parties are given written notice of the
decision to terminate.
Section 5. Other Matters.
5.1. Non-exclusivity. RPMC may perform services for
other persons affiliated or not affiliated with
Ridgewood Power. Owner and the General Partner
waive any objection to (a) the fact that now or in
the future Robert E. Swanson and other persons who
are directors, officers, employees or affiliates of
Ridgewood Power may have similar positions with
RPMC and may have a financial interest in RPMC and
(b) the fact that RPMC and its directors, officers
and employees may be employed by or have financial
interests in Ridgewood Power and its affiliates.
5.2. Assignment. This Agreement may not be assigned by
either party. Notwithstanding the foregoing, in
the event of an unapproved assignment, the
assignee shall also be responsible for performance
of assignor's responsibilities and both assignor
and assignee shall be liable to the other parties
for breach of this covenant.
5.3. Amendments. This Agreement can be amended only by
a writing signed by all parties. In addition, no
amendment that materially increases the obligations
of the Owner or the General Partner or that
materially decreases the obligations of RPMC shall
become effective until 45 days after notice of the
amendment together with the text thereof has been
given to all holders of equity securities of the
trusts or other investment programs that
beneficially own the securities of the Owner and
the General Partner.
5.4. Governing Law. This Agreement is governed by the
laws of New Jersey applying to contracts having
their most significant contacts with New Jersey.
5.5. Entire Agreement. This Agreement is the entire
agreement among the parties as to its subject
matter and supersedes all prior agreements among
them.
5.6. Captions and Counterparts. The captions of this
Agreement are for reference only and shall not be
used in construing its meaning. This Agreement may
be executed in counterparts, each of which shall be
an original and all of which shall be considered
to be a single document.
5.7. Jurisdiction and Venue. ALL LAWSUITS IN CONNECTION
WITH THIS AGREEMENT SHALL BE BROUGHT ONLY IN THE
STATE OR FEDERAL COURTS SITTING IN OR FOR THE COUNTY
OF BERGEN, STATE OF NEW JERSEY. THE PARTIES AGREE
THAT THOSE COURTS SHALL HAVE PERSONAL JURISDICTION
AND AGREE TO VENUE IN THOSE COURTS. PROCESS MAY BE
SERVED IN ANY MANNER PERMITTED BY THE RULES OF THE
COURT DESCRIBED IN THIS SECTION IN WHICH AN ACTION
IS BROUGHT.
IN WITNESS WHEREOF, the parties have signed this
Agreement as of the date first stated above.
RIDGEWOOD PROVIDENCE POWER PARTNERS, L.P., Owner
By: RIDGEWOOD/PROVIDENCE CORPORATION, General Partner
By:/s/ Thomas R. Brown
Name: Thomas R. Brown
Title: Senior Vice President
RIDGEWOOD/PROVIDENCE CORPORATION, General Partner
By: /s/ Thomas R. Brown
Name: Thomas R. Brown
Title: Senior Vice President
RIDGEWOOD POWER MANAGEMENT CORPORATION
By: /s/ Thomas R. Brown
Name: Thomas R. Brown
Title: Senior Vice President
EXHIBIT A
PROJECTS SUBJECT TO AGREEMENT
Providence Project at the Rhode Island State Central
Landfill
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the
undersigned, Ralph O. Hellmold, appoints Robert
E. Swanson and Martin V. Quinn, and each of them,
as his true and lawful attorneys-in-fact with full power
to act and do all things necessary, advisable or appropriate,
in 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 year ended December 31, 1996 and
is qualified in its entirety by reference to those financial
statements.
</LEGEND>
<CIK> 0000917032
<NAME> RIDGEWOOD ELECTRIC POWER TRUST III
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 2,959,240
<SECURITIES> 28,050,750<F1>
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,068,325
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 31,430,075
<CURRENT-LIABILITIES> 41,136
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 31,388,939<F2>
<TOTAL-LIABILITY-AND-EQUITY> 31,430,075
<SALES> 0
<TOTAL-REVENUES> 3,773,375
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 1,231,689
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 2,541,686
<INCOME-TAX> 0
<INCOME-CONTINUING> 2,541,686
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,541,686
<EPS-PRIMARY> 6,486
<EPS-DILUTED> 6,486
<FN>
<F1>Investments in power project partnerships.
<F2>Represents Investor Shares of beneficial interest
in Trust with capital accounts of $31,406,084 less
managing shareholder's accumulated deficit of $17,145.
</FN>
</TABLE>
