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, 1997
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 X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.[ X ]
There is no market for the Shares. The aggregate capital contributions
made for the Registrant's voting Shares held by non-affiliates of the
Registrant at March 21, 1998 was $39,034,440.
Exhibit Index is located on page 52.
<PAGE>
PART I
Item 1. Business.
Forward-looking statement advisory
This Annual Report on Form 10-K, as with some other statements
made by the Trust from time to time, has forward-looking
statements. These statements discuss business trends and other
matters relating to the Trust's future results and the business
climate and are found, among other places, at Items 1(c)(3),
1(c)(4), 1(c)(6)(ii) and 7. In order to make these statements,
the Trust has had to make assumptions as to the future. It has
also had to make estimates in some cases about events that have
already happened, and to rely on data that may be found to be
inaccurate at a later time. Because these forward-looking
statements are based on assumptions, estimates and changeable
data, and because any attempt to predict the future is subject to
other errors, what happens to the Trust in the future may be
materially different from the Trust's statements here.
The Trust therefore warns readers of this document that they
should not rely on these forward-looking statements without
considering all of the things that could make them inaccurate.
The Trust's other filings with the Securities and Exchange
Commission and its Confidential Memorandum discuss many (but not
all) of the risks and uncertainties that might affect these
forward-looking statements.
Some of these are changes in political and economic conditions,
federal or state regulatory structures, government taxation,
spending and budgetary policies, government mandates, demand for
electricity and thermal energy, the ability of customers to pay
for energy received, supplies of fuel and prices of fuels,
operational status of plant, mechanical breakdowns, availability
of labor and the willingness of electric utilities to perform
existing power purchase agreements in good faith. Some of these
cautionary factors that readers should consider are described
below at Item 1(c)(4) -- Trends in the Electric Utility and
Independent Power Industries.
By making these statements now, the Trust is not making any
commitment to revise these forward-looking statements to reflect
events that happen after the date of this document or to reflect
unanticipated future events.
(a) General Development of Business.
Ridgewood Electric Power Trust 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.
The Trust is organized similarly to a limited partnership.
Ridgewood Power Corporation (the "Managing Shareholder"), a
Delaware corporation, is the Managing Shareholder of the Trust.
In general, the Managing Shareholder has the powers of a general
partner of a limited partnership. It has complete control of the
day to day operation of the Trust and as to most acquisitions.
The Managing Shareholder is not regularly elected by the owners
of the Investor Shares (the "Investors"). The Managing
Shareholder and the Independent Trustees of the Trust meet
together as the Board of the Trust and take the actions that the
1940 Act requires a board of directors to take for a business
development company. The Board of the Trust also provides
general supervision and review of the Managing Shareholder but
does not have the power to take action on its own. The
Independent Trustees do not have any management or administrative
powers over the Trust or its property other than as expressly
authorized or required by the Declaration of Trust of the Trust
(the "Declaration") or the 1940 Act.
Ridgewood Energy Holding Corporation ("Ridgewood Holding"),
a Delaware corporation, is the Corporate Trustee of the Trust.
The Corporate Trustee acts on the instructions of the Managing
Shareholder and is not authorized to take independent
discretionary action on behalf of the Trust. See Item 10. -
Directors and Executive Officers of the Registrant below for a
further description of the management of the Trust.
The Trust made an election to be treated as a "business
development company" under the Investment Company Act of 1940, as
amended ( the "1940 Act"). On February 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. The Trust also may invest in facilities related
to those projects.
Historically, producers of electric power in the United
States consisted of regulated utilities and of industrial users
that produced electricity to satisfy their own needs. The
independent power industry in the United States was created by
federal legislation passed in response to the energy crises of
the 1970s. The Public Utility Regulatory Policies Act of 1978,
as amended ("PURPA"), requires utilities to purchase electric
power from "Qualifying Facilities" (as defined in PURPA),
including "cogeneration facilities" and "small power producers,"
and also exempts these Qualifying Facilities from most utility
regulatory requirements. Under PURPA, Projects that are
Qualifying Facilities are generally not subject to federal
regulation, including the Public Utility Holding Company Act of
1935, as amended, and state regulation. Furthermore, PURPA
generally requires electric utilities to purchase electricity
produced by Qualifying Facilities at the utility's avoided cost
of producing electricity (i.e., the incremental costs the utility
would otherwise face to generate electricity itself or purchase
electricity from another source). 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 four 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 35 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 13.8 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. Therefore, 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.
The San Joaquin Project, which is a Qualifying Facility, has
been operating since 1991 and uses natural-gas fired
reciprocating engines to generate electricity for sale to Pacific
Gas and Electric Company ("PG&E") under a long term contract
expiring in 2020(the "Power Contract"). The Project's electricity
output is sold at a formula price set by the California Public
Utilities Commission that approximates the utility's avoided
cost. Currently, the formula consists of a fixed payment for the
plant's capacity and a payment per unit of energy delivered that
is tied to 85% of the cost of natural gas, the fuel used at the
plant. The capacity payments vary seasonally and are
significantly higher during the April-October peak season.
Thermal energy from the San Joaquin Project is used to provide
steam to an adjacent food processing company under long term
contracts that also terminate in 2020.
Until 1997, the plant only operated during the six month peak
season during peak hours. In 1997, the California Public
Utilities Commission amended the rate structure to allocate more
of the capacity payments to operations during the non-peak months
from November to March. As a result, less of the capacity
payment could be earned during the peak season. The Trust
approached the food processor with a proposal to run the Project
and provide steam year-round to the processor. To do so, the
Trust made approximately $750,000 of improvements to the steam
transfer system and the processor waived certain increases in the
rent for the Project site. The parties are negotiating
modifications to the thermal host contracts under which the
Project would rent its site from the food processor and supply it
with steam for a net annual payment of $150,000 from the Project
to the food processor.
California is implementing a competitive power market
beginning April 1, 1998 in which generators will eventually
auction capacity and energy output that is not committed for sale
under long-term contracts. It is expected that eventually the
California Public Utilities Commission will change the payment
formula for many long-term contracts (including the San Joaquin
Project's) to use the auction prices for capacity and energy
output. This would have effects on the Project's revenues that
are not predictable at this time but that might result in a
reduction in the prices paid by PG&E for electricity during off-
peak periods.
Distributions from the Project to the Trust for 1997
totalled $1,152,000 (a 21.4% annual return), up from $779,000 in
1996. The increase resulted from operating the plant for three
additional months beginning in April 1997 and from moderating
fuel costs. Further, unlike 1996, there was no withholding by
PG&E of capacity payments. See Item 3 - Legal Proceedings.
(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 Byron Project, like the San Joaquin Project, is fueled
by natural gas and sells its electricity output to Pacific Gas &
Electric Company under agreements substantially identical to
those at the San Joaquin Project. The Power Contracts also
expire in 2020. The Project's heat output is used to evaporate
brine from oil and gas wells, with payments by the Project for
the site lease offsetting the thermal host's payments for heat.
The California Public Utilities Commission's changes to the
rate structure under the San Joaquin Power Contract, discussed
above, had identical impact on the Byron Project. No material
capital improvements were needed for the Byron Project to operate
on a year-round schedule and like the San Joaquin Project it
began that schedule in April 1997.
Distributions to the Trust from the Byron Project in 1997
were $572,000 (a 20.2% annual return), up from $429,000 in 1996.
The increase reflected the three months of additional operation
in 1997, moderating fuel costs and the lack of withholding of
payments by PG&E.
Please refer to the discussion of the San Joaquin Project
for further details on regulatory issues for the Byron 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. ("EUA"), for an aggregate
purchase price of approximately $11.3 million. The Trust has
invested an additional $1,369,934 for capital improvements in the
Projects and has expended additional amounts on remediation. 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 were located on 35 sites in California (18 sites),
Connecticut (six sites), Massachusetts (two sites), New York
(eight 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 in 1997 totalled $1,429,000 (a 11.9%
annual return), down from $1,755,000 in 1996.
Returns from the On-site Cogeneration Projects have
deteriorated since their purchase and beginning in the third
quarter of 1997 the Trust has closed the majority of the Projects
for unprofitability. As of April 1, 1998, only 15 of the
Projects are still in operation. In the future, the Trust may
decide to close additional Projects because of contract
expirations, unprofitability and other factors.
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 has successfully
resolved contract interpretation disputes with the textile
manufacturer and the Massachusetts Projects remain profitable.
The Rhode Island Project, which was sold in December 1997, was
located at a textile manufacturer in Centerdale, Rhode Island and
had a rated capacity of 4.2 Megawatts from three natural-gas-
fired engines. The host was obligated under an equipment lease
and maintenance agreement to make payments of approximately
$900,000 per year to the Trust, and according to projections
supplied by EUA, the Project should have earned cash flow of
$800,000 per year. The host manufacturer for several years had
been significantly in arrears in its payments and made only
sporadic payments to the Trust. The Project's operations were
suspended in October 1996, and were only briefly resumed in
spring 1997 after the host made a few payments. In May 1997 the
host's primary lender threatened to place the host textile
manufacturer into bankruptcy, which would have terminated the
host's contract with the Trust. After protracted negotiations,
the Trust sold the Project to the lender in December 1997 for
$900,000 and the Trust recorded a loss of $2,752,000.
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 Project is profitable but is not
meeting projections because the bottling plant's demand for heat
has decreased and because of design defects in the Project which
make it incapable of avoiding a large portion of the bottling
plant's charges from the local utility.
The remaining 31 On-site Cogeneration Projects, all of which
are or were natural-gas-fueled, were 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 in this group 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. In 1997 the Trust
discontinued operation of and wrote off 15 additional Projects in
this group, for a total of $1,992,000. The Trust is pursuing an
arbitration proceeding against EUA for damages, as described at
Item 3 - Legal Proceedings.
The Trust is currently financing the acquisition of four
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 was
$135,000 at December 31, 1997.
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 8 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 $5.4 million of debt
maturing in installments through 2004. In 1997, as described
below, capital improvements were completed and the Trust's total
investment in the Project increased to $7,504,000.
The Project burns methane gas (the major component of
natural gas) generated by the decomposition of garbage in the
landfill as fuel for a 13.8 Megawatt capacity electric generation
plant. The facility has been in operation since 1990 and has a
Power Contract for 12.0 Megawatts with New England Power Company
with a 22 year term remaining.
The Project leases the right to use the landfill site from
the Rhode Island Resource Recovery Corporation, a state agency,
for a royalty of 15% of net Project revenues (increasing 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 25% from 9.2 Megawatts in the first three months of
1996 to 12.2 Megawatts in December 1996 and 11.5 Megawatts in
1997. Since August 1997, monthly sales have approached or
equalled the 12.0 Megawatt maximum under the Power Contract. In
order to increase output to the maximum and to allow engines to
be rotated off-line for preventative maintenance, an additional
engine and generator set were installed at the Project in spring
1997. Although this increased nominal Project capacity by
approximately 1/8, the actual benefit is the ability to have one
engine off-line at any time for maintenance and still produce the
entire 12.0 Megawatts that can be sold under the existing Power
Contract. Distributions from the Project for 1997 to the Trust
totalled $922,941 (a 12.3% annual return) up from $562,000 for
the period April 16-December 31, 1996.
The Trust currently has approximately $1.8 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 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 were operated on a year-round schedule. The Trust
believes that substantially all of the incremental costs of full-
year operation will be recovered from the energy payments. In
1997, the change resulted in material increases in the Projects'
income. The allocation of capacity payments to peak and non-peak
months may be changed at any time by action of the California
Public Utilities Commission, based on its own review or petitions
by purchasing utilities, and any change may materially and
adversely affect the two Projects.
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 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 8 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 would likely have a material adverse effect on the
Trust.
PG&E undertakes a monitoring program as required by the
California Public Utilities Commission for data on thermal
deliveries at the Byron and San Joaquin Projects. If a Project
were to fail to meet PURPA standards, PG&E would be able to
exclude a proportionate part of its purchases of electricity from
the long-term power contract and pay at substantially lower spot
rates for that part of its purchases. This would require the
Project to refund substantial amounts. To date PG&E has not been
able to establish any deficiency by the Projects and the Trust
believes that the San Joaquin and Byron Projects have
consistently exceeded PURPA requirements.
Customers of Projects that accounted for more than 10% of
annual distributions from operating sources to the Trust in each
of the last three fiscal years are:
<TABLE>
<CAPTION>
Calendar year
1997 1996 1995
<S> <C> <C> <C>
Pacific Gas & Electric Co. 42.3% 34.3% 100.0%
(San Joaquin & Byron Projects)
New England Electric System 22.6% 16.0% 0.0%
(Providence Project)
Globe Manufacturing Co. 18.3% 18.7% 0.0%
(Massachusetts Projects)
The Worcester Company 6.9% 16.3% 0.0%
(Rhode Island Project)
</TABLE>
Each On-Site Cogeneration Project sells all of its output to
a single customer and termination of those contracts would end
all revenue from a Project, 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. Such fluctuations directly affect the profitability
of Projects that use these fuels.
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
The Trust is somewhat insulated from recent deregulatory
trends in the electric industry because the San Joaquin, Byron
and Providence Projects are Qualifying Facilities with long-term
formula-price Power Contracts. Each Power Contract now provides
for rates in excess of current short-term rates for purchased
power. There has been much speculation that in the course of
deregulating the electric power industry, federal or state
regulators or utilities would attempt to invalidate these power
purchase contracts as a means of throwing some of the costs of
deregulation on the owners of independent power plants.
To date, the Federal Energy Regulatory Commission and
California authorities have ruled that existing Power Contracts
will not be affected by their deregulation initiatives. The
regulators have so far rejected the requests of a few utilities
to invalidate existing Power Contracts. Instead, most state plans
for deregulation of the electric power industry treat the value
of long-term Power Contracts that are above current and
anticipated market prices as "stranded costs" of the utilities.
The utilities are to be allowed to recover those costs during a
transition period. This is typically done by imposing a
transition fee or surcharge on rates that is paid to the utility.
This alternative is being implemented in California, may reduce
incentives to invalidate the Olinda Project's Power Contract. In
some states, utilities are being encouraged or ordered to issue
bonds or other financial instruments to retire stranded cost
assets or contracts, supported by transition charges.
No action has yet been taken by federal or state legislators
to date to impair Independent Power Projects' existing power
sales contracts, and there are federal constitutional provisions
restricting actions to impair existing contracts. There can not
be any assurance, however, that the rapid changes occurring in
the industry and the economy as a whole would not cause
regulators or legislative bodies to attempt to change the
regulatory structure in ways harmful to Independent Power
Projects or to attempt to impair existing contracts. In
particular, some regulatory agencies have urged utilities to
construe Power Contracts strictly and to police Independent Power
Projects compliance with those Power Contracts vigorously. See
the discussion of the San Joaquin Project, above, for regulatory
requirements in California for utility monitoring of Power
Contracts and potential effects on the San Joaquin and Byron
Projects.
Predicting the consequences of any legislative or regulatory
action is inherently speculative and the effects of any action
proposed or effected in the future may harm or help the Trust.
Because of the consistent position of the regulatory authorities
to date and the other factors discussed here, the Trust believes
that so long as it performs its obligations under the Power
Contracts, it will be entitled to the benefits of the contracts.
In recent years, many electric utilities have attempted to
exploit all possible means of terminating Power Contracts with
independent power projects, including requests to regulatory
agencies and alleging violations of even immaterial terms of the
Power Contracts as justification for terminating those contracts.
If such an attempt were to be made, the Trust might face material
costs in contesting those utility actions. Other utilities have
from time to time made offers to purchase and terminate Power
Contracts for lump sums. No such offer has been suggested or made
to the Trust, although the Trust would entertain such an offer.
Finally, the Power Contracts are subject to modification or
rejection in the event that the utility purchaser enters
bankruptcy. There can be no assurance that the utility purchaser
will stay out of bankruptcy.
After the Power Contracts for the San Joaquin, Byron and
Providence Projects expire in 2020 or those contracts terminate
for other reasons, those Projects under currently anticipated
conditions would be free to sell their output on the competitive
electric supply market, either in spot, auction or short-term
arrangements or under long-term contracts if those Power
Contracts could be obtained. There is no assurance that the
Projects could then sell their output or do so profitably.
Because the San Joaquin and Byron Projects are fueled by natural
gas purchased at market prices and because those Projects are
relatively small-scale, they might have cost disadvantages in
competing against larger competitors that would enjoy economies
of scale. While the Providence Project is not subject to natural
gas price fluctuations and it may benefit from environmental
requirements for utilities to purchase power from environmentally
favorable sources, the supply of fuel gas from the landfill is
not assured, and it may also have diseconomies of small scale.
The Trust is unable to anticipate whether thermal sales from
cogeneration from the San Joaquin and Byron Projects or
environmental subsidies at the Providence Project would offset
any possible cost disadvantages in electric generation or gas
supply deficiencies or whether in fact the Projects would have
cost disadvantages after the contracts end. It is thus
impossible to predict the profitability of those Projects after
termination of the Power Contracts.
The remaining On-site Cogeneration Projects, which have
"shared savings" contracts, are exposed to the changes in the
electric industry that are being caused by wholesale and retail
deregulation, as explained below. To date, these deregulation
efforts have not had material adverse effects on these Projects,
but there is the potential for some impact on revenues in 1998
and later years.
(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.
(iv) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including
but not limited to PURPA, the Holding Company Act, the 1992
Energy Act and the FPA, are subject to amendment or repeal.
Future legislation and regulation is uncertain, and could have
material effects on the Trust.
(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 (including the Providence Project), 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." Finally, PURPA requires electric
utilities to interconnect with Qualifying Facilities and provide
back-up power, which benefits the On-Site Cogeneration Projects.
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 had become more common for such contracts
to be negotiated until recent years.
The exemptions from extensive federal and state regulation
afforded by PURPA to Qualifying Facilities are important to the
Trust and its competitors. The Trust believes that the Byron,
San Joaquin and Providence Projects, which sell electricity to
public utilities, and the On-Site Cogeneration Projects, which do
not normally sell electricity but which are interconnected with
the local electric utilities, are Qualifying Facilities.
Maintaining the Qualified Facility status of an electric
generating Project that sells power to utilities 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 San Joaquin and Byron Projects'
electric output, aggressively use this data to press for
termination of Qualifying Facility status, and there is an
ongoing risk that the utility will assert that the Project does
not qualify for any given year. The Trust believes that those
Projects have qualified and will continue to qualify. The On-
site Cogeneration Projects do not sell material amounts
electricity to utilities or off-site customers; therefore, they
need not be Qualifying Facilities so long as state requirements
or market forces assure the ability of the On-Site Cogeneration
Projects to interconnect for back-up power.
(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 that sell to utilties failed to
be a Qualifying Facility, it would have to comply with the FPA.
(D) Fuel Use Act. Larger Projects may also be subject to the
Fuel Use Act, which limits the ability of power producers to burn
natural gas in new generation facilities unless such facilities
are also coal-capable within the meaning of the Fuel Use Act.
The Trust believes that the Byron and San Joaquin Projects are
coal-capable and thus qualify for exemption from the Fuel Use
Act.
(E) State Regulation. State public utility regulatory
commissions have broad jurisdiction over Independent Power
Projects which are not Qualifying Facilities under PURPA, and
which are considered public utilities in many states. In states
where the wholesale or retail electricity market remains
regulated, Projects that are not Qualifying Facilities may be
subject to state requirements to obtain certificates of public
convenience and necessity to construct a facility and could have
their organizational, accounting, financial and other corporate
matters regulated on an ongoing basis. Although FERC generally
has exclusive jurisdiction over the rates charged by a non-
Qualifying Facility to its wholesale customers, state public
utility regulatory commissions have the practical ability to
influence the establishment of such rates by asserting
jurisdiction over the purchasing utility's ability to pass
through the resulting cost of purchased power to its retail
customers. In addition, states may assert jurisdiction over the
siting and construction of non-Qualifying Facilities and, among
other things, issuance of securities, related party transactions
and sale and transfer of assets. The actual scope of
jurisdiction over non-Qualifying Facilities by state public
utility regulatory commissions varies from state to state.
(ii) Environmental Regulation.
The construction and operation of Independent Power Projects
are subject to extensive federal, state and local laws and
regulations adopted for the protection of human health and the
environment and to regulate land use. The laws and regulations
applicable to the Trust and Projects in which it invests
primarily involve the discharge of emissions into the water and
air and the disposal of waste, but can also include wetlands
preservation and noise regulation. These laws and regulations in
many cases require a lengthy and complex process of renewing
licenses, permits and approvals from federal, state and local
agencies. Obtaining necessary approvals regarding the discharge
of emissions into the air is critical to the development of a
Project and can be time-consuming and difficult. Each Project
requires technology and facilities which comply with federal,
state and local requirements, which sometimes result in extensive
negotiations with regulatory agencies. Meeting the requirements
of each jurisdiction with authority over a Project may require
extensive modifications to existing Projects.
The Clean Air Act Amendments of 1990 contain provisions
which regulate the amount of sulfur dioxide and oxides of
nitrogen which may be emitted by a Project. These emissions may
be a cause of "acid rain." Qualifying Facilities are currently
exempt from the acid rain control program of the Clean Air Act
Amendments. However, non-Qualifying Facility Projects will
require "allowances" to emit sulfur dioxide after the year 2000.
Under the Amendments, these allowances may be purchased from
utility companies then emitting sulfur dioxide or from the
Environmental Protection Agency ("EPA"). Further, an Independent
Power Project subject to the requirements has a priority over
utilities in obtaining allowances directly from the EPA if (a) it
is a new facility or unit used to generate electricity; (b) 80%
or more of its output is sold at wholesale; (c) it does not
generate electricity sold to affiliates (as determined under the
Holding Company Act) of the owner or operator (unless the
affiliate cannot provide allowances in certain cases) and (d) it
is non-recourse project-financed. The market price of an
allowance cannot be predicted with certainty at this time. In
recent years, supply of allowances has tended to exceed demand,
primarily because of improved control technologies and the
increased use of natural gas.
Title V of the Clean Air Act Amendments added a new
permitting requirement for existing sources that requires all
significant sources of air pollution to submit new applications
to state agencies. Title V implementation by the states
generally does not impose significant additional restrictions on
the Trust's Projects, other than requirements to continually
monitor certain emissions and document compliance. The
permitting process is voluminous and protracted and the costs of
fees for Title V applications, of testing and of engineering
firms to prepare the necessary documentation have increased. The
Trust believes that all of its facilities will be in compliance
with Title V requirements with only minor modifications such as
the installation of an additional catalytic converter on some
engines.
In July 1997 the Environmental Protection Agency adopted
more stringent standards for levels of ozone and small
particulate matter (particles less than 25 microns in diameter)
in geographic areas. These new standards may cause some areas in
which Projects are located to be classified as non-attainment
areas. If so, states will be required to impose additional
requirements for industries to reduce emissions. It is uncertain
whether or how any reductions would be applied to small
facilities such as the Trust's Projects. If reductions were
required, the Trust might have to make significant capital
investments to install new control technology or might have to
reduce operations. In addition, many eastern states, including
Massachusetts and New York, have organized in the Ozone Transport
Assessment Group to require further restrictions on emissions of
nitrogen oxides. The Environmental Protection Agency is
considering the Group's recommendations as well as other
proposals to reduce emissions of nitrogen oxides and other ozone-
forming chemicals. If adopted, new regulations could required
the Trust to install additional equipment to reduce those
emissions or to change operations. Nitrogen oxide reductions can
be difficult to achieve with add-on equipment and often require
decreases in operating efficiency, both of which could cause
material cost to the Trust. It is not possible at this time to
estimate whether or not any potential regulatory changes would
materially affect the Trust.
The Clean Air Act Amendments empower states to impose annual
operating permit fees of at least $25 per ton of regulated
pollutants emitted up to $100,000 per pollutant. To date, no
state in which the Trust operates has done so. If a state were
to do so, such fees might have a material effect on the Trust's
costs of generation, in light of the relatively small size of the
Trust's facilities as opposed to large utility generation plants
that might benefit from the cap on fees.
The Trust's Projects must comply with many federal and state
laws and regulations governing wastewater and stormwater
discharges from the Projects. These are generally enforced by
states under "NPDES" permits for point sources of discharges and
by stormwater permits. Under the Clean Water Act, NPDES permits
must be renewed every five years and permit limits can be reduced
at that time or under re-opener clauses at any time. The
Projects have not had material difficulty in complying with their
permits or obtaining renewals. The Projects use closed-loop
engine cooling systems which do not require large discharges of
coolant except for periodic flushing to local sewer systems under
permit and do not make other material discharges to groundwaters
or streams.
In 1998, the Trust's Projects will become subject to the
reporting requirements of the Emergency Planning and Community
Right-to-Know Act that require the Projects to prepare toxic
release inventory release forms. These forms will list all toxic
substances on site that are used in excess of threshold levels so
as to allow governmental agencies and the public to learn about
the presence of those substances and to assess potential hazards
and hazard responses. The Trust does not anticipate that this
will result in any material adverse effect on it.
Based on current trends, the Managing Shareholder expects
that environmental and land use regulation will become more
stringent. The Trust and the Managing Shareholder have developed
limited expertise and experience in obtaining necessary licenses,
permits and approvals. The Trust will rely upon qualified
environmental consultants and environmental counsel retained by
it 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 Projects are operated by RPMC and accordingly the Trust
has no employees. The persons described below at Item 10.
Directors and executive officers of the Managing Shareholder and
RPMC 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).
<TABLE>
<CAPTION>
Approximate
Approx- Square Descrip-
Ownership Ground imate Footage of tion
Interests Lease Acreage Project (Actual of
Project Location in Land Expiration of Land or Projected) Project
<S> <C> <C> <C> <C> <C> <C>
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 15 sites Leased various n/a n/a Inside-the-
Cogen- in CA, or fence,
eration CT, MA, licensed gas-fired
and NY or diesel-
fueled
cogeneration
engines and
generators
Providence Providence, Leased 2020 4 10,000 Landfill
Rhode Island gas-fired
generation
facility
</TABLE>
Item 3. Legal Proceedings.
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 parties have conducted settlement negotiations
since October 1997 without coming to a final agreement. If
settlement is not reached by mid-April 1998, discovery will
resume and a trial is scheduled for August 1998.
On February 27, 1997, Michael Cutbirth, an individual, sued
the Managing Shareholder in the Superior Court of California,
Kern County, claiming damages for violation of an alleged
confidentiality agreement and for fraud relating to the
acquisition of the San Joaquin and Byron Projects. Mr. Cutbirth
claims that the Managing Shareholder agreed to deal with him
exclusively in connection with the Projects. The suit includes a
claim for an equity interest in the Projects and an management
contract for the Projects. The Managing Shareholder removed the
lawsuit to the United States District Court for the Eastern
District of California. Discovery has been completed and motions
for summary judgment are pending before the court. The Managing
Shareholder believes it has ample defenses and is vigorously
defending the case. If summary judgment is not obtained, the
case is scheduled for trial in June 1998. The Trust might be
obligated to indemnify the Managing Shareholder against any
liability if the Managing Shareholder acted in good faith and in
the Trust's best interests and the conduct was neither negligence
or misconduct.
The Trust's subsidiaries that own the On-site Cogeneration
Projects brought an arbitration proceeding against the seller, a
subsidiary of Eastern Utilities Associates, Inc., before the
American Arbitration Association in Boston, Massachusetts in
December 1996, alleging fraud and breaches of representations and
warranties made by the seller in the agreements of sale. The
Trust has requested damages including refund of some or all of
the purchase price, the costs of capital improvements and other
items and has requested that the damages be doubled or trebled
under applicable Massachusetts law. 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 conducting limited discovery in
preparation for arbitration hearings scheduled for June 1998.
See also Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations - Results of
Operations - The year ended December 31, 1997 . . . . for
information regarding the damages suffered by the Trust.
Item 4. Submission of Matters to a Vote of Security Holders.
The Trust did not submit any matters to a vote of the
Investors during the fourth quarter of 1997.
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 its 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.
The Managing Shareholder is considering the possibility of a
combination of the Trust and four other investment programs
sponsored by the Managing Shareholder (Ridgewood Electric Power
Trusts I, II, IV and V) into a publicly traded entity. This
would require the approval of the Investors in the Trust and the
other programs after proxy solicitations complying with
requirements of the Securities and Exchange Commission,
compliance with the "rollup" rules of the Securities and Exchange
Commission and other regulations, and a change in the federal
income tax status of the Trust from a partnership (which is not
subject to tax) to a corporation. The process of considering and
effecting a combination, if the decision is made to do so, will
be very lengthy. There is no assurance that the Managing
Shareholder will recommend a combination, that the Investors of
the Trust or other programs will approve it, that economic
conditions or the business results of the participants will be
favorable for a combination, that the combination will be
effected or that the economic results of a combination, if
effected, will be favorable to the Investors of the Trust or
other programs.
(b) Holders
As of the date of this Form 10-K, there are 759 record
holders of Investor Shares.
(c) Dividends
The Trust made distributions as follows in the years 1996
and 1997:
Year ended Year ended
December 31, 1997 December 31, 1996
Total distributions
to Investors $3,045,001 $3,694,661
Distributions per
Investor Share 7,771 9,429
Distributions to
Managing Shareholder 30,758 37,312
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. The Trust's cash flow comes primarily from
distributions from Projects. Those distributions are from cash
flow of the Projects, which includes income of Projects plus
funds representing depreciation and amortization charges taken by
the Projects. Because the Trust's objective is to distribute net
cash flow, a substantial portion of many distributions by the
Trust will include cash flow derived from 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. Investors should be aware that the Trust is organized
to return net cash flow rather than accounting income to
Investors.
Item 6. Selected Financial Data.
The following data is qualified in its entirety by the
financial statements presented elsewhere in this Annual Report on
Form 10-K.
<TABLE>
<CAPTION>
Supplemental Information As of and As of and As of and As of and
Schedule for the for the for the for the
Selected Financial Data Year Ended Year Ended Year Ended Period Ended
December 31, December 31, December 31, December 31,
1997 1996 1995 1994
Total Fund Information:
<S> <C> <C> <C> <C>
Net revenue from
operating projects $4,075,390 $3,525,613 $1,317,287 $0
Net income (loss) (1,355,866)(A) 2,541,686 1,440,550 (213,299)
Net assets
(shareholders' equity) 26,957,314 31,388,939 32,579,226 18,671,356
Investments in project
development and power
generation limited
partnerships 24,613,978 28,050,750 20,884,493 0
Total assets 27,336,224 31,430,075 32,651,668 18,405,145
Per Investor Share:
Revenues $10,788 $9,630 $6,066 $1,178
Expenses 14,249(A) 3,143 2,389 2,144
Net income (loss) (3,460) 6,486 3,676 (966)
Net asset value 68,796 80,106 83,143 84,598
Distributions to Investors 7,771 9,429 5,896 0
</TABLE>
(A) After writedowns of investments of $4,743,631 ($12,106 per
Investor Share).
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Introduction
The following discussion and analysis should be read in
conjunction with the Trust's financial statements and the notes
thereto, found at the end of this Annual Report. The Trust
carries its investment in the Projects it owns at fair value and
does not consolidate its financial statements with the financial
statements of the Projects. Revenue is recorded by the Trust as
cash distributions are declared by the Projects. Trust revenues
may fluctuate from period to period depending on the operating
cash flow generated by the Projects and the amount of cash
retained to fund capital expenditures. Dollar amounts in this
discussion are generally rounded to the nearest $1,000, except
per share data.
Outlook
The U.S. electricity markets are being restructured and
there is a trend away from regulated electricity systems towards
deregulated, competitive market structures. The States that the
Trust's Projects operate in have passed or are considering new
legislation that permits utility customers to choose their
electricity supplier in a competitive electricity market. The
Providence, San Joaquin and Byron Projects are "Qualified
Facilities" as defined under the Public Utility Regulatory
Policies Act of 1978 and currently sell their electric output to
utilities under long-term contracts expiring in 2020, 2021 and
2020, respectively. During the term of the contracts, the
utilities may or may not attempt to buy out the contracts prior
to expiration. At the end of the contracts, the Projects will
become merchant plants and may be able to sell the electric
output at then current market prices. There can be no assurance
that future market prices will be sufficient to allow the
Projects to operate profitably.
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. 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 natural gas prices began to fall in late 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.
Results of Operations
The year ended December 31, 1997 compared to the year ended
December 31, 1996.
In 1997, the Trust's net loss was $1,356,000. The loss
resulted from third and fourth quarter 1997 charges to earnings
totaling $4,744,000 relating to the write-down to net realizable
value of the Trust's investment in 16 terminated On-site
Cogeneration Projects acquired from affiliates of Eastern
Utilities Associates in 1995. In 1996, the Trust wrote-down four
On-site Cogeneration Projects totaling $113,000. The 1997 and
1996 results from operations for the On-site Cogeneration
Projects were substantially below expectations; resulting from
the prior owner's poor maintenance and operation, design defects,
defaults by a customer; in some cases, a pattern of overbilling
of customers; and other breaches of the purchase agreement.
These Projects also suffered temporarily in early 1997 and 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 the
winter of 1996-1997.
Without the write-downs of the On-site Cogeneration
Projects, net income for 1997 would have been $3,388,000 as
compared to net income of $2,655,000 for 1996, an increase of
$733,000 (27.6%). This increase reflects a $549,000 increase in
income received from Projects in which the Trust has invested, a
decrease of $96,000 (38.7%) in interest income and a decrease of
$280,000 (25.0%) in other Trust expenses. In 1997, interest
income decreased by $96,000 from 1996, as a result of the
increase of the amount of cash invested in Projects, which
decreased the cash invested in short-term securities. For 1997,
the Trust's expenses (excluding investment write-downs) decreased
by $280,000 from 1996, principally due to a $254,000 decrease in
Project due diligence costs because the Trust evaluated fewer
acquisition targets in 1997. There were no material changes in
the other expense categories.
As summarized below, income from power generation projects
increased 15.6% to $4,075,000 in 1997 compared to $3,526,000 in
1996:
Project 1997 1996 1995
On-site Cogeneration:
Massachusetts $ 745,000 $ 660,000 0
Rhode Island 283,000 573,000 0
New York 293,000 161,000 0
Others 108,000 362,000 0
Subtotal 1,429,000 1,756,000 0
San Joaquin 1,152,000 779,000 982,000
Providence 923,000 562,000* 0
Byron 571,000 429,000 335,000
Total $4,075,000 $3,526,000 $1,317,000
* Represents a partial year April 16 to December 31, 1996.
In 1997, income from the San Joaquin, Providence and the
Byron Projects increased by $373,000 (47.9%), $361,000 (64.2%),
and $142,000 (33.1%), respectively. As a result of changes made
in the calculation of capacity payments received under their
electricity sales contracts, the San Joaquin and Byron Projects
improved profitability by operating for nine months in 1997, as
compared to six months in 1996. It is expected that these
Projects will operate for twelve months in 1998. The Trust
acquired its interest in the Providence Project in mid-April
1996. Accordingly, 1996 results only include eight and one half
months of activity. Additionally, 1997 operating profitability
improved by adding a ninth engine and increasing sales to the
utility. In 1997, income from the On-Site Cogeneration Projects
decreased by $327,000 (18.6%) as a result of the problems
discussed above.
The year ended December 31, 1996 compared to the year 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 $1,397,000 to $3,773,000 (58.8%), 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 167.5%
($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 the factors discussed above. These
Projects also suffered temporarily in late 1996 from sharp
increases in natural gas prices.
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. Output
increased by an average of 33% in the first 8 1/2 months of
ownership by the Trust.
Trust-level expenses increased by 31.6% 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 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.
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%).
Liquidity and Capital Resources
For 1997, net cash provided by operating activities of
$2,804,000 included $594,000 of cash which was transferred to the
Trust when the Trust changed its cash management procedures and
consolidated all significant cash balances at the Trust level.
In 1997, net cash provided by operating activities include
deductions of $1,370,000 and $664,000 for cash advances to
various projects to fund capital expenditures and working
capital, respectively. Cash distributions to shareholders were
$3,076,000 in 1997 as compared to $3,732,000 in 1996. As a
result of lower earnings from the On-site Cogeneration Projects,
monthly cash distributions were reduced to $500 per share in July
1997 from an average of $800 per share during the first six
months of the year.
During the fourth quarter of 1997, the Trust and Fleet Bank,
N.A. (the "Bank") entered into a revolving line of credit
agreement, whereby the Bank provides a three year committed line
of credit facility of $750,000. Outstanding borrowings bear
interest at the Bank's prime rate or, at the Trust's choice, at
LIBOR plus 2.5%. The credit agreement requires the Trust to
maintain a ratio of total debt to tangible net worth of no more
than 1 to 1 and a minimum debt service coverage ratio of 2 to 1.
The credit facility was obtained in order to allow the Trust to
operate using a minimum amount of cash, maximize the amount
invested in Projects and maximize cash distributions to
shareholders. There were no borrowings under the line of credit
in 1997.
Other than investments of available cash in power generation
Projects, obligations of the Trust are generally limited to
payment of the management fee to the Managing Shareholder,
payments for certain accounting and legal services to third
persons and distributions to shareholders of available operating
cash flow generated by the Trust's investments. The Trust's
policy is to distribute as much cash as is prudent to
shareholders. Accordingly, the Trust has not found it necessary
to retain a material amount of working capital. The need to
retain working capital is further reduced by the availability of
the line of credit facility. The Trust anticipates that its cash
flow from operations during 1998, unexpended offering proceeds
and line of credit facility will be adequate to fund its
obligations.
Financial instruments
The Trust's investments in financial instruments are short-
term investments of working capital or excess cash. Those short-
term investments are limited by its Declaration of Trust to
investments in United States government and agency securities or
to obligations of banks having at least $5 billion in assets.
Currently the Trust invests only in bank obligations of Fleet
Bank, N.A. Because the Trust invests only in short-term
instruments for cash management, its exposure to interest rate
changes is low.
Year 2000 Remediation.
The Managing Shareholder and its affiliates began year 2000
review and planning in early 1997. After initial remediation was
completed, a more intensive review discovered additional issues
and the Managing Shareholder began a formal remediation program
in late 1997. The Managing Shareholder has assessed problems,
has a written plan for remediation and is implementing the plan
on schedule.
The accounting, network and financial packages for the
Ridgewood companies are basically off-the-shelf packages that
will be remediated, where necessary, by obtaining patches or
updated versions. The Managing Shareholder expects that updating
will be complete before the end of 1998 with ample time for
implementation, testing and custom changes to some modifications
made by Ridgewood to those programs.
The marketing and investor relations functions rely on
custom-written software and the Managing Shareholder has hired a
specialist to remedy that software. The year 2000 changes in the
distribution system, which is used to send checks to Investors,
have been completed and are being tested. The effort is on
schedule to complete remediation and testing by December 31, 1998
and the Managing Shareholder believes that all material systems
will be year 2000 compliant by early 1999. Some systems are
being remediated using the "sliding window" technique. Although
this will allow compliance for several years beyond the year
2000, eventually those systems will have to be rewritten again or
replaced.
The Managing Shareholder and its affiliates do not
significantly rely on computer input from suppliers and customers
and thus are not directly affected by other companies' year 2000
compliance. However, if customers' payment systems or suppliers'
systems were adversely affected by year 2000 problems, the Trust
could be affected. Because the Trust and the Managing
Shareholder are extremely small relative to the size of their
material customers and suppliers and are paid or supplied using
the same systems as larger companies, requests for written
assurances of compliance from those customers or suppliers are
not cost-effective.
Although the total cost associated with year 2000 compliance
is not yet determined, the Trust does not believe that the costs
will be material to its financial position or results of
operation.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Balance Sheet at December 31, 1997 and 1996 F-3
Statement of Operations for Three Years
ended December 31, 1997 F-4
Statement of Changes in Shareholders'
Equity for Three Years ended December 31,
1997 F-5
Statement of Cash Flows for Three Years
ended December 31, 1997 F-6 -F-7
Notes to Financial Statements F-8 to F-14
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
or on a consolidated basis.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
Neither the Trust nor the Managing Shareholder has had an
independent accountant resign or decline to continue providing
services since their respective inceptions and neither has
dismissed an independent accountant during that period. During
that period of time no new independent accountant has been
engaged by the Trust or the Managing Shareholder, and the
Managing Shareholder's current accountants, Price Waterhouse LLP,
have been engaged by the Trust.
PART III
Item 10. Directors and Executive Officers of the Registrant.
(a) General.
As Managing Shareholder of the Trust, Ridgewood Power
Corporation has direct and exclusive discretion in management and
control of the affairs of the Trust (subject to the general
supervision and review of the Independent Trustees and the
Managing Shareholder acting together as the Board of the Trust).
The Managing Shareholder will be entitled to resign as Managing
Shareholder of the Trust only (i) with cause (which cause does
not include the fact or determination that continued service
would be unprofitable to the Managing Shareholder) or (ii)
without cause with the consent of a majority in interest of the
Investors. It may be removed from its capacity as Managing
Shareholder as provided in the Declaration.
Ridgewood Energy Holding Corporation ("Ridgewood Holding"),
a Delaware corporation incorporated in April 1992, is the
Corporate Trustee of the Trust.
(b) Managing Shareholder.
The Managing Shareholder was incorporated in February 1991
as a Delaware corporation for the primary purpose of acting as a
managing shareholder of business trusts and as a managing general
partner of limited partnerships which are organized to
participate in the development, construction and ownership of
Independent Power Projects.
The Managing Shareholder has also organized Ridgewood
Electric Power Trust I ("Ridgewood Power I"), Ridgewood Electric
Power Trust II ("Ridgewood Power II"), Ridgewood Electric Power
Trust IV ("Ridgewood Power IV"), Ridgewood Electric Power Trust V
("Ridgewood Power V") and The Ridgewood Power Growth Fund (the
"Growth Fund") as Delaware business trusts to participate in the
independent power industry. 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 16 years (of which 25 have terminated) and which had
total capital contributions in excess of $190 million. The
programs operated by Ridgewood Energy have invested in oil and
natural gas drilling and completion and other related activities.
Other affiliates of the Managing Shareholder include Ridgewood
Securities Corporation ("Ridgewood Securities"), an NASD member
which has been the placement agent for the private placement
offerings of the six trusts sponsored by the Managing Shareholder
and the funds sponsored by Ridgewood Energy; Ridgewood Power
Capital Corporation ("Ridgewood Capital"), organized in 1998,
which assists in offerings made by the Managing Shareholder; and
Ridgewood Power VI Corporation ("Power VI Corp."), which is a
managing shareholder of the Growth Fund and RPMC. Each of these
corporations is wholly owned by Robert E. Swanson, who is their
sole director.
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 51, 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, Ridgewood Power V and the Growth Fund, since their respective
inceptions. Mr. Swanson has been President and registered
principal of Ridgewood Securities and became the Chairman of the
Board of Ridgewood Capital on its organization in 1998. In
addition, he has been President and sole stockholder of Ridgewood
Energy since its inception in October 1982. Prior to forming
Ridgewood Energy in 1982, Mr. Swanson was a tax partner at the
former New York and Los Angeles law firm of Fulop & Hardee and an
officer in the Trust and Investment Division of Morgan Guaranty
Trust Company. His specialty is in personal tax and financial
planning, including income, estate and gift tax. Mr. Swanson is
a member of the New York State and New Jersey bars, the
Association of the Bar of the City of New York and the New York
State Bar Association. He is a graduate of Amherst College and
Fordham University Law School.
Robert L. Gold, age 39, has served as Executive Vice
President of the Managing Shareholder, RPMC, Ridgewood Power I,
the Trust, Ridgewood Power II, Ridgewood Power IV, Ridgewood
Power V and the Growth Fund since their respective inceptions,
with primary responsibility for marketing and acquisitions. He
has been President of Ridgewood Power Capital Corporation since
its organization in 1998. 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 43, 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 Ridgewood Power
I through V trusts in October 1996, and is the Chief Operating
Officer of the Growth Fund. Mr. Brown has over 20 years'
experience in the development and operation of power and
industrial projects. From 1992 until joining the Managing
Shareholder he was employed by Tampella Services, Inc., an
affiliate of Tampella, Inc., one of the world's largest
manufacturers of boilers and related equipment for the power
industry. Mr. Brown was Project Manager for Tampella's Piney
Creek project, a $100 million bituminous waste coal fired
circulating fluidized bed power plant. Between 1990 and 1992 Mr.
Brown was Deputy Project Manager at Inter-Power of Pennsylvania,
where he successfully developed a 106 megawatt coal fired
facility. Between 1982 and 1990 Mr. Brown was employed by
Pennsylvania Electric Company, an integrated utility, as a Senior
Thermal Performance Engineer. Prior to that, Mr. Brown was an
Engineer with Bethlehem Steel Corporation. He has an Bachelor of
Science degree in Mechanical Engineering from Pennsylvania State
University and an MBA in Finance from the University of
Pennsylvania. Mr. Brown satisfied all requirements to earn the
Professional Engineer designation in 1985.
Martin V. Quinn, age 50, assumed the duties of Chief
Financial Officer of the Managing Shareholder, the Trust, the
other four trusts organized by the Managing Shareholder and RPMC
in November 1996 under a consulting arrangement. He became a
full-time officer of the Managing Shareholder and RPMC in April
1997 and is now also Chief Financial Officer of the Growth Fund.
Mr. Quinn has 29 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 45, has served as Vice President of the
Managing Shareholder, RPMC, Ridgewood Capital, the Trust,
Ridgewood Power I, Ridgewood Power II, Ridgewood Power IV,
Ridgewood Power V and the Growth Fund since their respective
inceptions. She has also served as Vice President of Ridgewood
Energy since October 1984, when she joined the firm. Her primary
areas of responsibility are investor relations, communications
and administration. Prior to her employment at Ridgewood Energy,
Ms. Olin was a Regional Administrator at McGraw-Hill Training
Systems where she was employed for two years. Prior to that, she
was employed by RCA Corporation. Ms. Olin has a Bachelor of Arts
degree from Queens College.
(c) Management Agreement.
The Trust has entered into a Management Agreement with the
Managing Shareholder detailing how the Managing Shareholder will
render management, administrative and investment advisory
services to the Trust. Specifically, the Managing Shareholder
will perform (or arrange for the performance of) the management
and administrative services required for the operation of the
Trust. Among other services, it will administer the accounts and
handle relations with the Investors, provide the Trust with
office space, equipment and facilities and other services
necessary for its operation and conduct the Trust's relations
with custodians, depositories, accountants, attorneys, brokers
and dealers, corporate fiduciaries, insurers, banks and others,
as required. The Managing Shareholder will also be responsible
for making investment and divestment decisions, subject to the
provisions of the Declaration.
The Managing Shareholder will be obligated to pay the
compensation of the personnel and all administrative and service
expenses necessary to perform the foregoing obligations. The
Trust will pay all other expenses of the Trust, including
transaction expenses, valuation costs, expenses of preparing and
printing periodic reports for Investors and the Commission,
postage for Trust mailings, Commission fees, interest, taxes,
legal, accounting and consulting fees, litigation expenses and
other expenses properly payable by the Trust. The Trust will
reimburse the Managing Shareholder for all such Trust expenses
paid by it.
As compensation for the Managing Shareholder's performance
under the Management Agreement, the Trust is obligated to pay the
Managing Shareholder an annual management fee described below at
Item 13 -- Certain Relationships and Related Transactions.
The Board of the Trust (including both initial Independent
Trustees) have approved the initial Management Agreement and its
renewals. Each Investor consented to the terms and conditions of
the initial Management Agreement by subscribing to acquire
Investor Shares in the Trust. The Management Agreement will
remain in effect until January 4, 1999 and year to year
thereafter as long as it is approved at least annually by (i)
either the Board of the Trust or a majority in interest of the
Investors and (ii) a majority of the Independent Trustees. The
agreement is subject to termination at any time on 60 days' prior
notice by the Board, a majority in interest of the Investors or
the Managing Shareholder. The agreement is subject to amendment
by the parties with the approval of (i) either the Board or a
majority in interest of the Investors and (ii) a majority of the
Independent Trustees.
(d) Executive Officers of the Trust.
Pursuant to the Declaration, the Managing Shareholder has
appointed officers of the Trust to act on behalf of the Trust and
sign documents on behalf of the Trust as authorized by the
Managing Shareholder. Mr. Swanson has been named the President
of the Trust and the other executive officers of the Trust are
identical to those of the Managing Shareholder, with the addition
of Joseph A. Heyison, Senior Vice President and General Counsel.
Mr. Heyison, age 43, 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.
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 and as independent
panel members of Ridgewood Power V. Both are independent power
programs sponsored by Ridgewood Power. Independent panel members
must approve transactions between their program and the Managing
Shareholder or companies affiliated with the Managing
Shareholder, but have no other responsibilities. Neither Mr.
Hellmold nor Mr. Kaledin is otherwise affiliated with the Trust,
any of the Trust's officers or agents, the Managing Shareholder,
any other Trustee, any affiliates of the Managing Shareholder and
any other Trustees, or any director, officer or agent of any of
the foregoing.
Ralph O. Hellmold, age 57, is founder, sole shareholder and
President of Hellmold Associates, Inc., an investment banking
firm, broker-dealer and investment adviser specializing in
working with troubled companies or their creditors to raise
capital, divest businesses and restructure liabilities, whether
in or outside bankruptcy. Other financial advisory services
provided by Hellmold Associates, Inc. include mergers and
acquisitions advice, valuations, fairness opinions and expert
witness testimony. In addition to working with troubled
companies or their creditors, Hellmold Associates, Inc. also acts
as general partner of funds which invest in the securities of
financially distressed companies.
From 1987 to 1990, when he formed Hellmold Associates, Inc.,
Mr. Hellmold was a Managing Director at Prudential-Bache Capital
Funding, where he served as co-head of the Corporate Finance
Group, co-head of the Investment Banking Committee and head of
the Financial Restructuring Group. From 1974 to 1987, Mr.
Hellmold was a partner at Lehman Brothers and its successors,
where he worked in the General Corporate Finance Group and co-
founded the Financial Restructuring Group. Prior thereto, he was
a research analyst at Lehman Brothers and at Francis I. du Pont &
Company. He received his undergraduate degree magna cum laude
from Harvard College and an M.I.A. from Columbia University. He
is a Chartered Financial Analyst and a member of the New York
Society of Security Analysts. Mr. Hellmold is the holder of one-
half share in each of Ridgewood Power I and Ridgewood Power III,
a shareholder of one-half Share in the Trust and a limited
partner or shareholder in numerous limited partnerships and a
business trust sponsored by Ridgewood Energy to invest in oil and
gas development and related businesses. Mr. Hellmold is a
director of Core Materials Corporation, Columbus, Ohio.
Jonathan C. Kaledin, age 39, has been New York Regional
Counsel of The Nature Conservancy, the international land
conservation organization, since September 1995. From 1990 to
June 1995, he was founder and Executive Director of the National
Water Funding Council ("NWFC"), an advocacy and public affairs
organization representing municipalities, businesses, financial
institutions and others on federal Clean Water Act and Safe
Drinking Water Act funding issues. Prior to forming the NWFC in
1990, Mr. Kaledin was an attorney with the Boston law firm of
Wright & Moehrke. There he specialized in wetlands, water,
environmental review, zoning and hazardous and solid waste
matters, representing clients in state and federal court and
before state and federal agencies and local boards and
commissions. From 1987 through 1990, Mr. Kaledin was Assistant
Regional Counsel for the New England office of the Environmental
Protection Agency ("EPA"). His responsibilities at the EPA
included administrative and judicial environmental enforcement
under the Clean Water Act and other federal water protection
legislation. Mr. Kaledin received his undergraduate degree magna
cum laude from Harvard College and a law degree from New York
University.
The Corporate Trustee of the Trust is Ridgewood Holding.
Legal title to Trust Property is now and in the future will be in
the name of the Trust, if possible, or Ridgewood Holding as
trustee. Ridgewood Holding is also a trustee of Ridgewood Power
I, Ridgewood Power II, Ridgewood Power IV and Ridgewood Power V
and of an oil and gas business trust sponsored by Ridgewood
Energy and is expected to be a trustee of other similar entities
that may be organized by the Managing Shareholder and Ridgewood
Energy. The President, sole director and sole stockholder of
Ridgewood Holding is Robert E. Swanson; its other executive
officers are identical to those of the Managing Shareholder. See
- -- Managing Shareholder. The principal office of Ridgewood
Holding is at 1105 North Market Street, Suite 1300, Wilmington,
Delaware 19899.
The Trustees are not liable to persons other than
Shareholders for the obligations of the Trust.
The Trust has relied and will continue to rely on the
Managing Shareholder and engineering, legal, investment banking
and other professional consultants (as needed) and to monitor and
report to the Trust concerning the operations of Projects in
which it invests, to review proposals for additional development
or financing, and to represent the Trust's interests. The Trust
will rely on such persons to review proposals to sell its
interests in Projects in the future.
(f) Section 16(a) Beneficial Ownership Reporting Compliance
To the knowledge of the Trust, there were no violations of
the reporting requirements of section 16(a) of the 1934 Act by
officers and directors of the Trust in the last fiscal year.
(g) RPMC.
As discussed above at Item 1 - Business, RPMC assumed day-
to-day management responsibility for the San Joaquin, Byron, On-
site Cogeneration and Providence Projects in 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 or
Projects as operating expenses. To the extent that those
services were provided by the Managing Shareholder and related
directly to the operation of the Project, RPMC will charge the
Trust at its cost for these services and for the Trust's
allocable amount of certain overhead items. RPMC will share space
and facilities with the Managing Shareholder and its Affiliates.
To the extent that common expenses can be reasonably allocated to
RPMC, the Managing Shareholder may, but is not required to,
charge RPMC at cost for the allocated amounts and such allocated
amounts will be borne by the Trust and other programs. Common
expenses that are not so allocated will be borne by the Managing
Shareholder.
Initially, the Managing Shareholder does not anticipate
charging RPMC for the full amount of rent, utility supplies and
office expenses allocable to RPMC. As a result, both initially
and on an ongoing basis the Managing Shareholder believes that
RPMC's charges for its services to the Trust are likely to be
materially less than its economic costs and the costs of engaging
comparable third persons as managers. RPMC will not receive any
compensation in excess of its costs.
Allocations of costs will be made either on the basis of
identifiable direct costs, time records or in proportion to each
program's investments in Projects managed by RPMC; and
allocations will be made in a manner consistent with generally
accepted accounting principles.
RPMC will not provide any services related to the
administration of the Trust, such as investment, accounting, tax,
investor communication or regulatory services, nor will it
participate in identifying, acquiring or disposing of Projects.
RPMC will not have the power to act in the Trust's name or to
bind the Trust, which will be exercised by the Managing
Shareholder or the Trust's officers, although it may be
authorized to act on behalf of the subsidiaries that own
Projects.
The Operation Agreement does not have a fixed term and is
terminable by RPMC, by the Managing Shareholder or by vote of a
majority of interest of Investors, on 60 days' prior notice. The
Operation Agreement may be amended by agreement of the Managing
Shareholder and RPMC; however, no amendment that materially
increases the obligations of the Trust or that materially
decreases the obligations of RPMC shall become effective until
at least 45 days after notice of the amendment, together wi
th the text thereof, has been given to all Investors.
The executive 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), Mr. Heyison (Senior Vice President and General
Counsel). Douglas V. Liebschner, Vice President - Operations,
is a key employee.
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. Since 1996 the Managing
Shareholder has compensated these persons without additional
payments by the Trust and will be reimbursed by Ridgewood Energy
for costs related to Ridgewood Energy's business. The Trust will
reimburse RPMC at allocable cost for services provided by RPMC's
employees; no such reimbursement per employee exceeded $60,000 in
1996 or 1997. 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 1998 the Trust paid each
Independent Trustee $5,000 for his services. The Board of the
Trust is entitled to review the compensation payable to the
Independent Trustees annually and increase or decrease it as the
Board sees reasonable. The Trust is not entitled to pay the
Independent Trustees compensation for consulting services
rendered to the Trust outside the scope of their duties to the
Trust without prior Board approval.
Ridgewood Holding, the Corporate Trustee of the Trust, is
not entitled to compensation for serving in such capacity, but is
entitled to be reimbursed for Trust expenses incurred by it which
are properly reimbursable under the Declaration.
Item 12. Security Ownership of Certain Beneficial Owners and
Management.
The Trust sold 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 and its subsidiaries
paid fees or reimbursements to the Managing Shareholder and its
affiliates as follows:
<TABLE>
<CAPTION>
Fee Paid to 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
Management Managing $ 766,866 $794,026 $482,000 $0
fee Shareholder
Cost
reimbursements* RPMC 14,308,444 11,566,400 0 0
Investment Managing 0 0 343,779 421,011
fee Shareholder
Placement Ridgewood 0 0 147,950 188,847
agent fee Securities
and sales Corporation
commissions
Organizational, Managing 0 0 860,195 1,088,727
distribution Shareholder
and offering fee
</TABLE>
* 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. These
costs are almost exclusively paid by the Projects and do not
appear in the Trust's financial statements.
The investment fee equaled 2% of the proceeds of the
offering of Investor Shares and was payable for the Managing
Shareholder's services in investigating and evaluating investment
opportunities and effecting investment transactions. The
placement agent fee (1% of the offering proceeds) and sales
commissions were also paid from proceeds of the offering, as was
the organizational, distribution and offering fee (5% of offering
proceeds) for legal, accounting, consulting, filing, printing,
distribution, selling, closing and organization costs of the
offering.
The management fee, payable monthly under the Management
Agreement at the annual rate of 2.5% of the Trust's net asset
value, began on the date the first Project was acquired and
compensates the Managing Shareholder for certain management,
administrative and advisory services for the Trust. 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(g) -- 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, 1997.
(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. Incorporated by
reference to Exhibit 10E to Registrant's Annual Report on Form
10-K for the year ended December 31, 1996.
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 69
27. Financial Data Schedule Page 72
<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 15, 1998
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 15, 1998
Robert E. Swanson Executive Officer
By:/s/ Martin V. Quinn Senior Vice President and
Martin V. Quinn Chief Financial Officer April 15, 1998
By:/s/ Kathleen P. McSherry Controller April 15, 1998
Kathleen P. McSherry
RIDGEWOOD POWER CORPORATION Managing Shareholder April 15, 1998
By:/s/ Robert E. Swanson President
Robert E. Swanson
/s/ Robert E. Swanson * Independent Trustee April 15, 1998
Ralph O. Hellmold
/s/ Robert E. Swanson Independent Trustee April 15, 1998
Jonathan C. Kaledin
* As attorney-in-fact for the Independent Trustee
<PAGE>
Ridgewood Electric Power Trust III
Financial Statements
December 31, 1997, 1996 and 1995
-F1-
<PAGE>
Price Waterhouse LLP 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
April 2, 1998
To the Shareholders and Trustees of
Ridgewood Electric Power Trust III
In our opinion, the accompanying balance sheets and the related statements of
operations, changes in shareholders' equity and of cash flows present fairly,
in all material respects, the financial position of Ridgewood Electric Power
Trust III at December 31, 1997 and 1996, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1997, 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 $24,613,978 and $28,158,835 (91% and 90% of shareholders' equity,
respectively) as of December 31, 1997, and 1996, respectively, whose values
have been estimated by management in the absence of readily ascertainable
market values. We have reviewed the procedures used by management in arriving
at their estimate of value and have inspected underlying documentation, and,
in the circumstances, we believe the procedures are reasonable and the
documentation appropriate. However, those estimated values may differ
significantly from the values that would have been used had a ready market
for the investments existed, and the differences could be material to the
financial statements.
/s/ Price Waterhouse LLP
-F2-
<PAGE>
Ridgewood Electric Power Trust III
Balance Sheet
December 31,
1997 1996
Assets:
Investments in power generation projects $ 24,613,978 $ 28,158,835
Cash and cash equivalents 2,687,626 2,959,240
Due from affiliates 20,458 1,000
Deferred due diligence costs --- 30,000
Other assets 14,162 281,000
Total assets $ 27,336,224 $ 31,430,075
Liabilities and Shareholders' Equity:
Accounts payable and accrued expenses $ 38,537 $ 41,136
Due to affiliates 340,373 ---
Total liabilities 378,910 41,136
Commitments and Contingencies
Shareholders' equity:
Shareholders' equity
(391.8444 shares issued
and outstanding) 27,018,776 31,406,084
Managing shareholder's
accumulated deficit (61,462) (17,145)
Total shareholders' equity 26,957,314 31,388,939
Total liability and
shareholders' equity $27,336,224 $ 31,430,075
See accompanying notes to financial statements.
-F3-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Operations
Year Ended December 31,
1997 1996 1995
Revenue:
Income from power
generation projects $ 4,075,390 $ 3,525,613 $ 1,317,287
Interest and dividend
income 152,005 247,762 1,059,570
Total revenue 4,227,395 3,773,375 2,376,857
Expenses:
Investment fee --- --- 343,779
Project due diligence
costs 3,692 258,378 8,210
Management fee 766,866 794,026 482,309
Accounting and legal fees 46,869 48,231 90,043
Miscellaneous 22,203 18,012 11,966
Writedown of investments in
power generation projects 4,743,631 113,042 ---
Total expenses 5,583,261 1,231,689 936,307
Net income (loss) $ (1,355,866) $ 2,541,686 $ 1,440,550
See accompanying notes to financial statements.
-F4-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 1997, 1996 and 1995
Managing
Shareholders Shareholder Total
Shareholders' equity,
January 1, 1995
(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
Cash distributions (3,045,001) (30,758) (3,075,759)
Net loss for the year (1,342,307) (13,559) (1,355,866)
Shareholders' equity,
December 31, 1997
(391.8444 shares) $27,018,776 $(61,462) $26,957,314
See accompanying notes to financial statements.
-F5-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Cash Flows
Year Ended December 31,
1997 1996 1995
Cash flows from
operating activities:
Net income (loss) $ (1,355,866) $ 2,541,686 $ 1,440,550
Adjustment to reconcile
net income (loss) to net
cash provided by (used in)
operating activities:
Writedown of power
generation project
investments 4,743,631 113,042 ---
Investment in working
capital of power
generation projects, net (593,840) --- ---
Capital expenditures for
power generation projects (1,369,934) --- ---
Purchase of investments
in power generation
projects (135,000) (7,279,299) (20,884,493)
Proceeds from sale or
transfer of investment 900,000 353,619 ---
Changes in assets
and liabilities:
Decrease (increase) in
due to from affiliates 320,915 (109,085) (299,194)
Decrease (increase) in
deferred due diligence costs 30,000 273,213 (140,683)
Decrease (increase) in
interest receivable --- 51,233 (51,233)
Decrease (increase) in
other assets 266,838 (140,041) (135,959)
Increase in accounts payable
and accrued expenses $ (2,599) $ (85,731) $ (61,347)
Total adjustments 4,160,011 (6,823,049) (21,572,909)
Net cash provided by (used in)
operating activities 2,804,145 (4,281,363) (20,132,359)
Cash flows from financing
activities:
Proceeds from shareholders'
contributions --- --- 17,527,545
Selling commissions and
offering costs paid --- --- (2,332,545)
Cash distributions to
shareholders (3,075,759) (3,731,973) (2,327,680)
Net cash provided by
(used in) financing
activities (3,075,759) (3,731,973) 12,867,320
-F6-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Cash Flows (continued)
Year Ended December 31,
1997 1996 1995
Net decrease in
cash and cash equivalents (271,614) (8,013,336) (7,265,039)
Cash and cash equivalents,
beginning of year 2,959,240 10,972,576 18,237,615
Cash and cash equivalents,
end of year $ 2,687,626 $ 2,959,240 $ 10,972,576
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 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, in some
cases, 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.
Summary of Significant Accounting Policies
Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from the estimates.
Investments in power generation projects
The Trust holds investments in power generation projects which are stated
at fair value. Due to the illiquid nature of the investments, the fair values
of the investments are assumed to equal cost, unless current available
information provides a basis for adjusting the carrying value of the
investments.
Revenue recognition
Income from investments is recorded when distributions are declared.
Interest income is recorded as earned.
Offering costs
Costs associated with offering Trust shares (selling commissions,
distribution and offering costs) are recorded as a reduction of the
shareholders' capital contributions.
-F8-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
Cash and cash equivalents
The Trust considers all highly liquid investments with original
maturities of three months or less as cash and cash equivalents.
Due diligence costs relating to potential power project investments
Costs relating to the due diligence performed on potential power project
investments, are initially deferred, until such time 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 Trust.
Reclassifications
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,
1997 1996
JRW Associates, L.P. $5,391,361 $5,305,298
Byron Power Partners, L.P. 2,824,156 3,138,072
Ridgewood Providence Power
Partners, L.P. 7,504,792 7,167,242
On-site Cogeneration Projects:
Ridgewood/Rhode Island PPLP --- 3,722,618
Ridgewood/Mass PPLP 3,731,067 3,223,881
Ridgewood/Elmsford PPLP 1,756,416 1,430,136
Other On-site Cogeneration
Project Partnerships 3,406,186 4,171,588
$24,613,978 $28,158,835
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
("MW") electric cogeneration facility, located in Atwater, California. The
aggregate cost of the investment was $5,391,361 and $5,305,298 at December 31,
1997 and 1996, respectively. The Trust received distributions of $1,152,013,
$779,409 and $982,076 from the project in 1997, 1996 and 1995, respectively.
-F9-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
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 MW electric
cogeneration facility, located in Byron, California. As of December 31, 1997
and 1996, the aggregate cost of the Trust's investment in the partnership was
$2,824,156 and $3,138,072, respectively. The Trust received distributions of
$571,576, $428,540 and $335,211 from the project in 1997, 1996 and 1995,
respectively.
Ridgewood Providence Power Partners, L.P. (known as the Providence Project)
In 1996, Ridgewood Providence Power Partners, L.P. was formed as a
Delaware limited partnership ("Providence Power"). The Trust owns a 35.7%
limited partnership interest in Providence Power. In addition, Ridgewood
Providence Power Corporation was formed as a Delaware corporation ("RPPCorp.")
and the Trust owns 35.7% of the outstanding common stock of RPPCorp., which is
the sole general partner of Providence Power. At December 31, 1997 and 1996,
the total cost of the Trust's investment was $7,504,792 and $7,167,242,
respectively.
On April 16, 1996, Providence Power purchased substantially all of the
net assets of Northeastern Landfill Power Joint Venture. The assets acquired
included a 12.3 MW capacity electrical generating station, located at the
Central Landfill in Johnston, Rhode Island (the "Providence Project"). In
1997, the capacity was increased to 13.8 MW.
The Providence Project includes nine reciprocating electric generator
engines which are fueled by methane gas produced and collected from the
landfill. The electricity generated is sold to New England Power Corporation
under a long-term contract. The purchase price was $15,533,021 in cash,
including transaction costs and repayment of $3,000,000 of principal on 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 1997 and 1996, the Trust received
distributions of $922,941 and $562,427, respectively, 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 had 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
-F10-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
additional amounts for rehabilitation, capital improvements and working
capital. EUA operated the projects under a transition agreement until January
1, 1996, at which time Ridgewood Power Management Corporation ("RPMC"), an
affiliate of the Trust, assumed operational control. No distributions were
made by these projects in 1995. The Trust received distributions of
$1,428,860 and $1,755,237 from these projects in 1997 and 1996, respectively.
Ridgewood/Rhode Island Power Partners L.P.
Ridgewood/ Rhode Island Power Partners Limited Partnership (the
"Partnership") leased three 1.4 MW Cooper Superior gas fired generator sets
with heat recovery to a Rhode Island manufacturing company under a lease
expiring in 2006. Two engines were in regular use and one engine was on
standby. The partnership received a monthly fixed lease payment and a
maintenance payment, which escalated over the term of the lease. The
Partnership was responsible for maintaining the engines and related equipment.
At the expiration of the lease, the lessee had the right to purchase the
equipment from the partnership for its fair market value. As of December 31,
1996, the total cost of the Trust's investment in the partnership was
$3,722,618. The Trust received distributions of $282,943 and $572,970 from
the project in 1997 and 1996, respectively.
During 1997, the lessee experienced severe financial difficulties and
repeatedly defaulted on its payment obligations. In response, the lessee
alleged violations by the Partnership of the lease and requested renegotiation
of the lease. In the course of the negotiations, the lessee's principal
creditor threatened to place the lessee in Chapter 11 bankruptcy, which would
result in a cancellation of the lease. In December 1997, the lessee purchased
the facility (the "Worcester Project") and terminated the lease in exchange
for a single cash payment of $900,000. Accordingly, the Trust wrote down its
investment in the Partnership and recorded a loss of $2,752,168. See Note 6 -
Arbitration and Litigation, for additional information relating to arbitration
proceedings against EUA.
Ridgewood/Massachusetts Power Partners L.P.
Ridgewood/ Massachusetts Power Partners L.P. (the "Partnership") owns two
projects. The first is a 3.5 MW base load, single 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, 1997 and 1996, the total cost of the
Trust's investment in the partnership was $3,731,065 and $3,223,881
respectively. The Trust received distributions of $745,005 and $660,201 from
the project in 1997 and 1996, respectively. The Partnership also owns a
smaller group of four cogeneration generator sets totaling 255 kilowatt ("KW")
-F11-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
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 Location 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, 1997 and
1996, the total cost of the Trust's investment in the partnership was
$1,756,416 and $1,430,136, respectively. The Trust received distributions of
$292,543 and $160,940 from the project in 1997 and 1996, respectively.
The "Other On-site Cogeneration Project Partnerships"
The "other on-site cogeneration project partnerships" include five
partnerships, which owned 31 of the 35 projects acquired from Eastern
Utilities Associates. These 31 projects represented approximately one-third
of the Trust's original investment in the on-site cogeneration projects. All
thirty-one were gas-fired cogeneration projects, located in California,
Connecticut or New York. Their energy service agreements had terms expiring
between September 1996 and 2011. The projects represented 5.5 MW of base load
capacity. The largest project was 660 KW or 12% of the capacity. The
projects ranged in size from 30 KW to 660 KW. In 1996, the Trust wrote-off
four small projects amounting to $113,042. In 1997, the Trust wrote-off an
additional fifteen projects with 2.1 MW of base load capacity amounting to
$1,991,463. The Trust received distributions of $108,369 and $361,126 from
the projects in 1997 and 1996. In September 1997, the Trust entered into an
agreement with Alternate Energy Systems, Inc. ("AES") to invest in three co-
generation facilities operated by AES. All three facilities are located in
New York. As of December 31, 1997 and 1996, the total cost of the Trust's
investment in the other On-site Cogeneration Partnerships was $3,406,184 and
$4,171,588, respectively.
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.
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.
-F12-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
For the year ended December 31, 1995, the Trust paid fees for these
services to the managing shareholder totaling $860,195. 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 year ended December 31, 1995, the Trust paid investment
fees to the managing shareholder of $343,779.
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, 1997, 1996 and 1995, the Trust paid
management fees to the managing shareholder of $766,866, $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"). After Payout the managing
shareholder is entitled to receive 20% of all remaining distributions of the
Trust.
Where permitted, in the event the managing shareholder or an affiliate
performs brokering services in respect of an investment acquisition or
disposition opportunity for the Trust, the managing shareholder or such
affiliate may charge the Trust a brokerage fee. Such fee may not exceed 2% of
the gross proceeds of any such acquisition or disposition. No such fees have
been paid through December 31, 1997.
The managing shareholder owns one share of the Trust with a cost of
$84,000. In conjunction with the offering of the Trust shares, commissions
and placement fees of $390,844 were earned by Ridgewood Securities
Corporation, an affiliate of the managing shareholder.
Effective from January 1, 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.
-F13-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
5. Line of Credit Facility
During the fourth quarter of 1997, the Trust and the Trust's principal
bank executed a revolving line of credit agreement, whereby the bank will
provide a three year committed line of credit facility of $750,000. At
December 31, 1997, there were no borrowing outstanding under the credit
facility. Outstanding borrowings bear interest at the bank's prime rate or,
at the Trust's choice, at LIBOR plus 2.5%. The credit agreement will require
the Trust to maintain a ratio of total debt to tangible net worth of no more
than 1 to 1 and a minimum debt service coverage ratio of 2 to 1.
6. Arbitration and Litigation
The Trust's subsidiaries that own the on-site cogeneration projects have
brought an arbitration proceeding against Eastern Utilities Associates, Inc.,
the former owner. The Trust has claimed that the former owner defrauded the
Trust by misrepresenting the financial status of the Worcester Project and its
customer and by making other material misrepresentations. The Trust also has
claimed that the former owner breached numerous representations and warranties
in the acquisition agreement and violated fair trade practice laws. The trust
has demanded the return of the entire $11.5 million paid for the On-Site
Cogeneration Projects and additional compensatory damages. The former owner
has counterclaimed for approximately $550,000 for alleged unpaid management
services. The parties have selected arbitrators, limited discovery is
underway and the arbitration hearing is scheduled for June 1998. 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 $164,000 of
capacity payments and also has asked for declaratory relief to require PG&E to
conform to the contracts' terms in the future. PG&E has answered the
complaint and has counterclaimed for all payments made to these projects. The
parties are in settlement negotiations which contemplate the payment to the
Trust of most of its claims. The Trust has not reflected the withheld
capacity payments in its financial statements pending the outcome of the suit.
On February 28, 1997 Michael Cutbirth, an individual, sued the Managing
Shareholder in the Superior Court of California, Kern County, claiming
unspecified damages (including a claim to an equity interest) for breach of an
alleged confidentiality agreement relating to the acquisition of the San
Joaquin and Byron Projects. The Managing Shareholder has successfully removed
the lawsuit to the United States District Court for the Eastern District of
California. Discovery has concluded and motions for summary judgment are
pending. The Managing Shareholder believes that it has ample defenses to Mr.
Cutbirth's claims and it will defend the action vigorously. If the Managing
Shareholder were held liable to Mr. Cutbirth, the Trust might be obligated to
indemmify the Managing Shareholder if the Managing Shareholder had acted in
good faith and in the Trust's best interests and the conduct was neither
negligence or misconduct.
-F14-
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned,
Ralph O. Hellmold, appoints Robert E. Swanson and Martin V.
Quinn, and each of them, as his true and lawful attorneys-in-fact
with full power to act and do all things necessary, advisable or
appropriate, in their discretion, to execute on his behalf as an
Independent Trustee of Ridgewood Electric Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form
10-K for the year ended December 31, 1997 for each of the above-
named trusts, and all amendments or documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power
of Attorney this 30th day of March, 1998, at Fort Lauderdale,
Florida.
/s/Ralph O. Hellmold
Ralph O. Hellmold
<PAGE>
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned,
Jonathan C. Kaledin, appoints Robert E. Swanson and Martin V.
Quinn, and each of them, as his true and lawful attorneys-in-fact
with full power to act and do all things necessary, advisable or
appropriate, in their discretion, to execute on his behalf as an
Independent Trustee of Ridgewood Electric Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form
10-K for the year ended December 31, 1997 for each of the above-
named trusts, and all amendments or documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power
of Attorney this 30th day of March, 1998, at Fort Lauderdale,
Florida.
/s/Jonathan C. Kaledin
Jonathan C. Kaledin
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>This schedule contains summary financial information
extracted from the Registrant's audited financial statements for
the year ended December 31, 1997 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-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 2,687,626
<SECURITIES> 24,613,978<F1>
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,708,084<F2>
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 27,336,224
<CURRENT-LIABILITIES> 378,910<F3>
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 26,957,314<F4>
<TOTAL-LIABILITY-AND-EQUITY> 27,336,224
<SALES> 0
<TOTAL-REVENUES> 4,227,395
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 4,743,631<F5>
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (1,355,866)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,355,866)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,355,866)
<EPS-PRIMARY> (3,460)
<EPS-DILUTED> (3,460)
<FN>
<F1>Investments in power project partnerships.
<F2>Includes $20,458 due from subsidiaries.
<F3>Includes $340,373 due to subsidiaries.
<F4>Represents Investor Shares of beneficial interest in Trust
with capital accounts of $31,406,084 less managing shareholder's
accumulated deficit of $17,145.
<F5>Includes writedowns of investments of $4,743,631.
</FN>
</TABLE>
