SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996

Commission file number   0-23432     

RIDGEWOOD ELECTRIC POWER TRUST III
(Exact Name of Registrant as Specified in Its Charter)

               Delaware                  22-3264565             
  (State or Other Jurisdiction              (I.R.S. Employer Identification No.)
of Incorporation or Organization)

c/o Ridgewood Power Corporation, 947 Linwood Avenue, Ridgewood, 
New Jersey 07450  
  (Address of Principal Executive Offices)                            (Zip Code)

	Registrant's Telephone Number, including Area Code:  (201) 447-
9000

	Securities Registered Pursuant to Section 12(b) of the Act:  None

Securities Registered Pursuant to Section 12(g) of the Act:

Shares of Beneficial Interest
(Title of Class)

     Indicate by check mark whether the Registrant (1) has filed 
all reports required to be filed by Section 13 or 15(d) of the 
Securities Exchange Act of 1934 during the preceding 12 months 
(or for such shorter period that the Registrant was required to 
file such reports), and (2) has been subject to such filing 
requirements for the past 90 days.  Yes 3 No ___

     Indicate by check mark if disclosure of delinquent filers 
pursuant to Item 405 of Regulation S-K is not contained herein, 
and will not be contained, to the best of Registrant's knowledge, 
in definitive proxy or information statements incorporated by 
reference in Part III of this Form 10-K or any amendment to this 
Form 10-K.[   ]

     There is no market for the Shares.  The aggregate capital 
contributions made for the Registrant's voting Shares held by 
non-affiliates of the Registrant at March 21, 1997 was 
$39,034,440.

Exhibit Index is located on page_____.
<PAGE>

PART I

Item 1.  Business.

Forward-looking statement advisory

This Annual Report on Form 10-K, as with some other 
statements made by the Trust from time to time, has forward-
looking statements.  These statements discuss business 
trends and other matters relating to the Trust's future 
results and the business climate and are found, among 
other places, at Items 1(c)(3), 1(c)(4), 1(c)(6)(ii) and 7.  
In order to make these statements, the Trust has had 
to make assumptions as to the future.  It has also had 
to make estimates in some cases about events that have 
already happened, and to rely on data that may be found 
to be inaccurate at a later time.  Because these 
forward-looking statements are based on assumptions, 
estimates and changeable data, and because any attempt to 
predict the future is subject to other errors, what happens 
to the Trust in the future may be materially different from 
the Trust's statements here.  

The Trust therefore warns readers of this document that they 
should not rely on these forward-looking statements without 
considering all of the things that could make them 
inaccurate.  The Trust's other filings with the Securities 
and Exchange Commission and its Confidential Memorandum 
discuss many (but not all) of the risks and uncertainties 
that might affect these forward-looking statements.  

Some of these are changes in political and economic 
conditions, federal or state regulatory structures, 
government taxation, spending and budgetary policies, 
government mandates, demand for electricity and thermal 
energy, the ability of customers to pay for energy received, 
supplies of fuel and prices of fuels, operational status of 
plant, mechanical breakdowns, availability of labor and the 
willingness of electric utilities to perform existing power 
purchase agreements in good faith.  Some of these 
cautionary factors that readers should consider are 
described below at Item 1(c)(4) -- Trends in the 
Electric Utility and Independent Power Industries.

By making these statements now, the Trust is not making any 
commitment to revise these forward-looking statements to 
reflect events that happen after the date of this document 
or to reflect unanticipated future events.
<PAGE>

(a)  General Development of Business.

     Ridgewood Electric Power Trust III, the Registrant hereunder 
(the "Trust"), was organized as a Delaware business trust on 
December 6, 1993 to participate in the development, construction 
and operation of independent power generating facilities 
("Independent Power Projects" or "Projects").  Ridgewood Energy 
Holding Corporation ("Ridgewood Holding"), a Delaware 
corporation, is the Corporate Trustee of the Trust.

     The Trust sold whole and fractional shares of beneficial 
interest in the Trust ("Investor Shares") at $100,000 per 
Investor Share, and terminated its private placement offering on 
May 31, 1995, at which time it had raised approximately $39.2 
million.  Net of Offering fees, commissions and expenses, the 
Offering provided approximately $32.9 million of net funds 
available for investments in the development and acquisition of 
Independent Power Projects and associated expenses.  The Trust 
has 764 record holders of Investor Shares (the "Investors").  As 
described below in Item 1(c)(2), the Trust has invested 
substantially all of its net funds in four sets of Independent 
Power Projects.

     Ridgewood Power Corporation (the "Managing Shareholder"), a 
Delaware corporation, is the Managing Shareholder of the Trust 
and as such has direct and exclusive discretion in the management 
and control of the affairs of the Trust (subject to the general 
supervision and review of the Independent Trustees and the 
Managing Shareholder acting together as the Board of the Trust).  
The Corporate Trustee acts on the instructions of the Managing 
Shareholder and is not authorized to take independent 
discretionary action on behalf of the Trust.  The Independent 
Trustees do not have any management or administrative powers over 
the Trust or its property other than as expressly authorized or 
required by the Declaration of Trust of the Trust (the 
"Declaration") or the 1940 Act.  See Item 10 - Directors and 
Executive Officers of the Registrant below for a further 
description of the management of the Trust.

     The Trust made an election to be treated as a "business 
development company" under the Investment Company Act of 1940, as 
amended ( the "1940 Act").  On February 14, 1994, the Trust 
notified the Securities and Exchange Commission of such election 
and registered the Investor Shares under the Securities Exchange 
Act of 1934, as amended (the "1934 Act").  On April 16, 1994, the 
election and registration became effective.

(b)  Financial Information about Industry Segments.

     The Trust operates in only one industry segment:  investing 
in independent power generation.

(c)  Narrative Description of Business.

(1)  General Description.

     The Trust was formed to participate in the development, 
construction and operation of independent electric power projects 
that generate electricity for sale to utilities and other users, 
and in some cases, to provide heat energy or chilled water as 
well to users.  

     Historically, producers of electric power in the United 
States consisted of regulated utilities and of industrial users 
that produced electricity to satisfy their own needs.  The 
independent power industry in the United States was created by 
federal legislation passed in response to the energy crises of 
the 1970s.  The Public Utility Regulatory Policies Act of 1978, 
as amended ("PURPA"), requires utilities to purchase electric 
power from "Qualifying Facilities" (as defined in PURPA), 
including "cogeneration facilities" and "small power producers," 
and also exempts these Qualifying Facilities from most utility 
regulatory requirements.  Under PURPA, Projects that are 
Qualifying Facilities are generally not subject to federal 
regulation, including the Public Utility Holding Company Act of 
1935, as amended, and state regulation.  Furthermore, PURPA 
generally requires electric utilities to purchase electricity 
produced by Qualifying Facilities at the utility's avoided cost 
of producing electricity (i.e., the incremental costs the utility 
would otherwise face to generate electricity itself or purchase 
electricity from another source).  Utilities in past years have 
done so under long-term power purchase contracts ("Power 
Contracts") which typically are the crucial determinant of the 
Qualifying Facility's success.

     The Trust has invested its funds in five Projects:  (i) a 
5.7 megawatt cogeneration facility located in Byron, California 
(the "Byron Project"); (ii) an 8.5 megawatt cogeneration facility 
located in Atwater, California (the "San Joaquin Project"); (iii) 
a portfolio of 31 cogeneration facilities located in California, 
New York, Massachusetts, Connecticut and Rhode Island, purchased 
from Eastern Utilities Associates, Inc. (the "On-site 
Cogeneration Projects") and (iv) a 12.3 megawatt electric 
generation plant fueled by gas drawn from a sanitary landfill 
near Providence, Rhode Island (the "Providence Project").

     As discussed below, the Trust is a "business development 
company" under the 1940 Act.  In accounting for its Projects, it 
treats each Project as a portfolio investment that is not 
consolidated with the Trust's accounts.  Accordingly, the 
revenues and expenses of each Project are not reflected in the 
Trust's financial statements and only cash distributions are 
included, as revenue, when received.  Accordingly, the 
recognition of revenue from Projects by the Trust is dependent 
upon the timing of distributions from Projects by the Managing 
Shareholder.  As discussed below at Item 5 - Market for 
Registrant's Common Equity and Related Stockholder Matters, 
distributions from Projects may include both income and capital 
components.

(2)  The Trust's Investments.

(i)  San Joaquin Project.  

     On January 17, 1995, Ridgewood Electric Power Trust III (the 
"Trust") and RW Central Valley, Inc., a newly formed California 
corporation which is wholly owned by the Trust ("Central 
Valley"), acquired 100% of the existing partnership interests of 
JRW Associates, L.P. ("JRW"), a California limited partnership 
which owns and operates an approximately 8.53 megawatt electric 
cogeneration facility located in the City of Atwater, Merced 
County, California.  The partnership interests were purchased 
from JRW Cogen, Inc. and NorCal Cogen, Inc., two corporations 
which were affiliates of a privately held company.  At the 
closing, the JRW partnership agreement was amended and restated 
so that Central Valley became the sole general partner of JRW 
with a 1% general partnership interest and the Trust became the 
sole limited partner of JRW with a 99% limited partnership 
interest.  Central Valley and the Trust plan to cause JRW to 
continue the operations of the Project in substantially the same 
manner as it has operated in the past.

     The aggregate cash purchase price paid by Central Valley and 
the Trust for 100% of the JRW partnership interests was 
$5,300,000.  Distributions from the Project to the Trust for 1996 
totalled $779,000 (a 14.7% annual return), down from $982,000 in 
1995.  The decrease was caused by fuel cost increases and by 
the withholding by Pacific Gas and Electric Company ("PG&E") of 
approximately $121,000 of capacity payments for what the Trust 
believes are spurious reasons based upon a disagreement over the 
interpretation of hours allotted for maintenance under the power 
purchase agreement with PG&E.  The Trust has instituted 
litigation against PG&E to recover the withheld payments.  See 
Item 3 -- Litigation.

(ii)  Byron Project.

     Also in January 1995, the Trust caused the formation of 
Byron Power Partners, L.P., a California limited partnership (the 
"Partnership") in which RW Byron, Inc., a newly formed California 
corporation which is wholly owned by the Trust ("Byron") owns a 
1% general partner interest and the Trust owns a 99% limited 
partnership interest.  On January 17, 1995, the Partnership 
acquired through a merger all of the assets and business of 
Altamont Cogeneration Corporation ("Altamont") a California 
corporation which owns and operates an approximately 5.7 megawatt 
electric cogeneration facility located near the city of Byron, 
Alameda County, California.  As a result of the merger, NorCal 
Altamont, Inc., the parent of Altamont and an affiliate of a 
privately held company, received a cash payment of $2,269,500 
representing the purchase price for the assets and businesses of 
Altamont acquired by the Partnership.  The total purchase price 
to the Trust was $3,138,000.  The Trust has been operating the 
Project in substantially the same manner as it has operated in 
the past.  Distributions to the Trust from the Byron Project in 
1996 were $429,000, up from $335,000 in 1995.  The increase 
reflected reclassification of some maintenance expenses as 
capital improvements, reductions in maintenance costs because of 
capital improvements and reductions in operating expenses.  The 
increase  was achieved despite the withholding by PG&E of $43,000 
in capacity payments for the reasons it did so for the San 
Joaquin Project.

(iii)  On-site Cogeneration Projects

     In September 1995, the Trust purchased the ownership 
interests in the On-Site Cogeneration Projects, a portfolio of 35 
"inside the fence" cogeneration Projects owned by affiliates of 
Eastern Utilities Associates, Inc., for an aggregate purchase 
price of approximately $11.3 million.  The On-site Cogeneration 
Projects use natural gas fired turbines or reciprocating engines 
to provide electrical energy and/or heat for industrial uses or 
air conditioning purposes under contracts with a variety of 
industrial customers.  The On-site Cogeneration Projects are 
located on 31 sites in California (16 sites), Connecticut (five 
sites), Massachusetts (two sites), New York (seven sites) and 
Rhode Island (one site).  The purchase agreement provided that 
the acquisition would take place as of September 30, 1995, and 
accordingly the Trust assumed the benefits and risks of the On-
site Cogeneration Projects accruing after that date.  
Distributions from the On-site Cogeneration Projects began in 
1996 and totalled $1,756,000 (a 14.7% annual return).

     The On-Site Cogeneration Projects have been divided for 
financial reporting purposes into four groups.  The Massachusetts 
Projects include a project located at a textile manufacturer in 
Fall River, Massachusetts (a 3.5 Megawatt turbine with backup 
diesel engines) and a project at a housing complex in Worcester, 
Massachusetts (.25 Megawatts).  The Trust is currently discussing 
contract revisions with the textile manufacturer.  The Rhode 
Island Project is located at a textile manufacturer in 
Centerdale, Rhode Island and has a rated capacity of 4.2 
Megawatts from three natural-gas-fired engines.  The host 
manufacturer has for several years been significantly in arrears 
in its payments and has continued to make sporadic payments to 
the Trust.  The Project's operations were suspended in October 
1996, although the host agreed to continue making payments under 
the lease agreement and to make up arrears.  The Trust and the 
host are currently negotiating terms for modifications to the 
existing agreement and a restart of the Project; otherwise, the 
Trust intends to file suit for payment of the arrears, in which 
case it is likely the host will disavow the agreement.

     The Coca-Cola Project is located at a bottling plant of 
Coca-Cola Bottling Company of New York at Elmsford, New York and 
has a rated capacity of 1.3 Megawatts with a .6 Megawatt standby 
diesel generator set.  The remaining 27 On-site Cogeneration 
Projects, all of which are natural-gas-fueled, are located in 
California and New York and had an aggregate rated capacity of 
5.5 Megawatts.  In 1996, the Trust discontinued operation of and 
wrote off four small On-Site Cogeneration Projects with a total 
rated capacity of .24 Megawatts of electricity, which had book 
values totalling $113,000.  The discontinued Projects had 
produced nominal cash flow or losses.

     The Trust is currently financing the acquisition of two or 
more small cogeneration facilities in the New York metropolitan 
area which will be managed by an independent operator.  The Trust 
will have a preferred right to annual distributions equal to 16% 
of its investment before the independent operator is entitled to 
any compensation or distribution rights.  The total investment is 
estimated to be less than $200,000.

     In purchasing the On-site Cogeneration Projects, the 
Managing Shareholder concluded that the costs of engaging third 
party managers to operate many smaller Projects would 
significantly reduce total returns to the Trust.  The Managing 
Shareholder, after reviewing the alternatives, elected to create 
an in-house management capability as a means of limiting costs, 
acquiring valuable operating and industry knowledge and 
increasing efficiency.  It accordingly organized an affiliate, 
Ridgewood Power Management Company ("RPMC").  Management 
responsibility for the On-site Cogeneration Projects was 
substantially transferred to the Managing Shareholder and RPMC at 
the end of 1995 and the Managing Shareholder and RPMC are 
currently operating or supervising operation of all of the 
Trust's Projects except 12 small On-Site Cogeneration Projects 
located in New York and Connecticut, which are managed by an 
independent operator.  See Item 10 -- Directors and Executive 
Officers of the Registrant.

(iv)  Providence Project

     The Trust and Ridgewood Electric Power Trust IV, a similar 
program organized by the Managing Shareholder ("Ridgewood Power 
IV"), acquired in April 1996 all of the equity interest in the 
Providence State Landfill Power Plant, located near Providence, 
Rhode Island.  The Trust invested $7.1 million in the Project and 
Ridgewood Power IV supplied the remainder of the $20 million 
investment in the Project.  The acquisition cost was 
approximately $15.5 million (including a $3 million partial 
prepayment of Project debt as a condition of obtaining the 
lenders' consents and transaction costs)and the remainder of the 
investment by the programs represents funds applied to operating 
reserves, working capital and reserves for capital improvements 
and expansion.  The Project is encumbered by $6 million of debt 
maturing in installments through 2004.  

     The Project burns methane gas (the major component of 
natural gas) generated by the decomposition of garbage in the 
landfill as fuel for a 12.3 Megawatt capacity electric generation 
plant.  The facility has been in operation since 1990 and has a 
Power Contract for 12.0 Megawatts with New England Power Company 
with a 23 year term remaining.  

     The Project leases the right to use the landfill site from 
the Rhode Island Resource Recovery Corporation, a state agency, 
for a royalty of 15% of net Project revenues (increasing to 15% 
to 18% in 2006) until 2020.  The Project in turn subleases those 
rights to Central Gas Limited Partnership ("Gasco").  Gasco, 
which is not affiliated with the Trust, operates and maintains 
the piping system and other facilities to collect the methane gas 
from the Landfill and supply it to the Project.  Gasco pays a 
fixed rent, computed on the basis of the Project's generating 
capacity, to the Project under the sublease, and the Project in 
turn buys its fuel from Gasco at a formula price per kilowatt-
hour generated by the Project.

     Since the Trust purchased the Project in April 1996, average 
output from the existing eight engine-generator sets has risen by 
approximately 33% from 9.2 Megawatts in the first three months of 
1996 to 12.2 Megawatts in December 1996.  Recent sales have 
approached the 12.0 Megawatt maximum under the Power Contract.  
In order to increase output to the maximum and to allow engines 
to be rotated off-line for preventative maintenance, an 
additional engine and generator set have been ordered and should 
be installed at the Project in April 1997.  This will increase 
Project capacity by approximately 1/8 and permit a more balanced 
operating rotation of engines.  The entire additional capacity 
will be sold under the existing Power Contract.  Distributions 
from the Project for 1996 to the Trust totalled $562,000 (a 7.9% 
annual return).

     The Trust currently has approximately $2.9 million of 
uninvested funds, some of which may be required for maintenance 
or replacement purposes or working capital.  The Trust is 
actively seeking additional small-scale Projects for investment. 

     If the Trust and another program with similar investment 
objectives have funds available at the same time for investment 
in the same or similar Projects, and a conflict of interest thus 
arises as to which program will make the investment, the Managing 
Shareholder will review the investment portfolio of each program.  
It will make the investment decision on the basis of such 
factors, among others, as the effects of the investment on the 
diversification of each program's portfolio, potential 
alternative investments, the effects investment by either program 
would have on the program's risk-return profile, the estimated 
tax effects of the investment on each program, the amount of 
funds available and the length of time those funds have been 
available for investment.  If more than one program has funds 
available for investment and the factors discussed above and 
other considerations indicate that the Project has approximately 
equal benefit for each Program, the Managing Shareholder will 
generally allocate the opportunity to each program in order of 
its organization date.  In that event, the Managing Shareholder 
will cause the oldest program to commit all of its reasonably 
available funds to that opportunity; if those funds are 
insufficient, the remainder of the opportunity will be offered to 
each successive program with reasonably available funds until the 
investment opportunity is exhausted.  A similar process would be 
followed for divestiture opportunities or competitive electricity 
sales.  

     An additional conflict could arise where the entities make 
investments in different forms, which would be the case where one 
entity's investment took the form of equity and the other's took 
the form of debt.  Although it anticipates that this situation is 
unlikely to arise, the Managing Shareholder, if practicable,would 
attempt to resolve any conflict of this type by reference to the 
terms negotiated by other debt or equity participants in the 
relevant Project or similar Projects.  Although the Managing 
Shareholder believes these practices may reduce potential 
conflicts of interest of this type, there can be no assurance 
that the interests of the entities will not diverge.  

(3)  Project Operation.

     Revenue from the San Joaquin, Byron and Providence Projects 
primarily comes from Power Contracts with the local electric 
utilities.  The pricing provisions of these Power Contracts 
usually have two components, energy payments and capacity 
payments.  Energy payments are based on a facility's net electric 
output, with payment rates usually indexed to the fuel costs of 
the purchasing utility or to general inflation indices.  Capacity 
payments are based on either a facility's net electric output or 
its available capacity.  Capacity payment rates vary over the 
term of a Power Contract according to various schedules. Until 
April 1997, approximately 90% of the capacity payment for the 
Byron and San Joaquin Projects was allocated to the peak demand 
months of April through October, and accordingly it was most 
economic to operate the Projects only in those months and to 
close them for the remainder of the year.  In 1997, the 
California Public Utilities Commission reduced the allocations to 
the peak months to approximately 78%.  This would cause a 
significant decrease in Project income if six-month operations 
were continued.  Accordingly, effective April 1, 1997, the Byron 
and San Joaquin Projects will be operated on a year-round 
schedule.  The Trust currently believes that substantially all 
of the incremental costs of full-year operation will be recovered 
from the energy payments and that the change will result in a 
nominal decrease or increase in Project income.  However, in 
order for the thermal user of the San Joaquin Project to use heat 
provided by the Project year-round, it must make approximately 
$400,000 of improvements.  The Trust has noted that the 
additional heat has substantial economic value to the user and 
has offered to finance the improvements itself, with repayment to 
be made through a reduction in land lease payments by the Trust 
to the user.

     The Power Contracts permit the purchasing utility to 
dispatch the facility (i.e., direct it to deliver a reduced level 
of electric output) in certain circumstances.  In such cases, 
payments under the Power Contract are structured so that, even 
when dispatching occurs, the facility continues to receive 
capacity payments (which are intended to cover fixed costs and 
which often provide substantially all of the facility's profits, 
if any) while it receives reduced energy payments (which 
primarily cover the variable operating, maintenance and fuel 
costs associated with operating the facility at lower or higher 
levels).

     The On-site Cogeneration Projects are "inside-the-fence" 
cogeneration facilities that are located on the sites of host 
businesses or organizations and that sell both their electrical 
output and their heat output to their hosts.  The long-term 
contracts with the hosts generally provide that the Trust is 
compensated on a "shared savings" basis, under which the net cost 
of the output is compared to the cost of purchasing the energy 
from utility suppliers under a predetermined formula and the 
Trust is paid a percentage of the computed savings.  The Trust's 
return is thus linked to the reliability and efficiency of its 
operations as well as the cost of alternate sources.  The On-Site 
Cogeneration Project located in Rhode Island is leased to the 
host and the Trust supplies operating and maintenance support on 
a contract basis.

     The major costs of a Project while in operation will be debt 
service (if applicable), fuel, taxes, maintenance and operating 
labor.  The ability to reduce operating interruptions and to have 
a Project's capacity available at times of peak demand are 
critical to the profitability of a Project.  Accordingly, skilled 
management is a major factor in the Trust's business.  

     The Trust, through the Managing Shareholder, operates most 
of its Projects, and Project operating costs have been wholly 
borne by the Trust as operating expenses and have not been borne 
by the Managing Shareholder.  Based on its experience with the 
Trust's Projects and its experience managing other similar 
investment programs, the Managing Shareholder believes that 
contracting with third persons for the management of operating 
Projects in many cases is not in the best interests of the Trust 
because of the fragmentation of responsibility, the need for 
extensive oversight of the managers, the loss in some cases of 
economies of scale, the difficulty in some areas of obtaining 
qualified managers and the generally high cost of management 
contracts.  These factors would be particularly burdensome in the 
case of the On-site Cogeneration Projects, many of which are 
small and located at multiple sites.  Further, the use of third 
persons to manage Projects deprives the Trust and other programs 
of management experience and hands-on knowledge that otherwise 
would be acquired by the Managing Shareholder or Affiliates. 

     The Managing Shareholder accordingly has organized RPMC to 
provide operating management for facilities operated by its 
investment programs, and has assigned day-to-day management of 
all of its Projects, other than 12 small On-site Cogeneration 
Projects located in New York and Connecticut, to RPMC.  See Item 
10 -- Directors and Executive Officers of the Registrant and Item 
13 -- Certain Relationships and Related Transactions for further 
information regarding the Operation Agreement and RPMC and for 
the cost reimbursements received by RPMC.

     Electricity produced by a Project is typically delivered to 
the purchaser through transmission lines which are built to 
interconnect with the utility's existing power grid or, in the 
On-site Cogeneration Projects, by direct connections.

     The overall demand for electrical energy is somewhat 
seasonal, with demand usually peaking in the summertime as a 
result of the increased use of air conditioning.  The impact of 
fluctuations in the demand or supply of electrical or thermal 
products generated upon the revenues of any particular Project is 
usually dependent on the terms of the Power Contract pursuant to 
which the energy is purchased:  under the shared savings 
contracts, changes in demand directly and proportionately affect 
the Trust's revenues. 

     Generally, revenues from the sales of electric energy from a 
cogeneration facility will represent the most significant portion 
of the facility's total revenue.  However, to maintain their 
status as a Qualifying Facility under PURPA, it is imperative 
that each cogeneration Project continue to satisfy PURPA 
cogeneration requirements as to the amount of thermal products 
generated.  Therefore, since the Byron and San Joaquin 
cogeneration Projects have only two customers (the electric 
energy purchaser and the thermal products purchaser), and because 
it may be impractical to obtain replacement purchasers of either 
the electrical or thermal output, loss of either of these 
customers will likely have a material adverse effect on the 
Project.  The On-Site Cogeneration Projects sell all of their 
output to a single customer and termination of those contracts 
would end all revenue from those Projects, unless the engines and 
other equipment could be economically moved to and installed on a 
new host's site.  The Providence Project burns methane gas 
generated by the decomposition of garbage, which causes that 
Project to be a "small power production facility" under PURPA.  
This allows it to be a Qualifying Facility without the need to 
sell thermal energy or to meet efficiency standards.

     The technology involved in conventional power plant 
construction and operations as well as electric and heat energy 
transfers and sales is widely known throughout the world.  There 
are usually a variety of vendors seeking to supply the necessary 
equipment for any Project.  So far as the Trust is aware, there 
are no limitations or restrictions on the availability of any of 
the components which would be necessary to complete construction 
and commence operations of any Project.  Generally, working 
capital requirements are not a significant item in the 
independent power industry.  The cost of maintaining adequate 
supplies of fuel sources is usually the most significant factor 
in determining working capital needs.

     Hydrocarbon fuels, such as natural gas, coal and fuel oil, 
have been generally available in recent years for use by 
Independent Power Projects, although there have been serious 
supply impairments for both oil and natural gas at times during 
the last 20 years.  Market prices for natural gas, oil and, to a 
lesser extent, coal have fluctuated significantly over the last 
few years.  See Item 7 -- Management's Discussion and Analysis of 
Results of Operation for additional information regarding the 
effects of natural gas price increases on certain Projects owned 
by the Trust.  Such fluctuations may directly inhibit the 
development of Projects because of the anticipated effects on 
Project profitability and may deter lenders to Projects or result 
in higher costs of financing. 

     In general, cogeneration, due to its higher efficiency, 
tends to be relatively more profitable as energy costs (including 
natural gas) increase and relatively less profitable as such 
costs decrease.  Projects which use natural gas as a fuel source 
bear the risk of gas price fluctuations adversely affecting their 
economics.

     In order to commence operations, most Projects require a 
variety of permits, including zoning and environmental permits.  
Inability to obtain such permits will likely mean that a Project 
will not be able to commence operations, and even if obtained, 
such permits must usually be kept in force in order for the 
Project to continue its operations.  

     Compliance with environmental laws is also a material factor 
in the independent power industry.  The Trust believes that 
capital expenditures for and other costs of environmental 
protection have not materially disadvantaged its activities 
relative to other competitors and will not do so in the future.  
Although the capital costs and other expenses of environmental 
protection may constitute a significant portion of the costs of a 
Project, the Trust believes that those costs as imposed by 
current laws and regulations have been and will continue to be 
largely incorporated into the prices of its investments and that 
it accordingly has adjusted its investment program so as to 
minimize material adverse effects.  If future environmental 
standards require that a Project spend increased amounts for 
compliance, such increased expenditures could have an adverse 
effect on the Trust to the extent it is a holder of such 
Project's equity securities.  See Item 1(c)(6) -- Business -- 
Narrative Description of Business -- Regulatory Matters.

(4) Trends in the Electric Utility and Independent Power 
Industries

     As a consequence of federal and state moves to deregulate 
large areas of the electric power industry and the existence, 
spurred by PURPA, of  private competitors to electric utilities 
in the market for generating electricity, a number of 
interrelated trends are occurring.  In accordance with industry 
usage, sales of electricity by generators to utilities or other 
marketers of electricity are referred to as "wholesale" 
transactions and sales by generators, utilities or others to end 
users of electricity are referred to as "retail" transactions.

Continued Deregulation of the Generating Market.  

     The Comprehensive Energy Policy Act of 1992 (the "1992 
Energy Act") encourages electric utilities to expand their 
wholesale generating capacity by removing some, but not all, of 
the limitations on their ownership of new generating facilities 
that qualify as "exempt wholesale generators" and on their 
ability to participate in Independent Power Projects.  See Item 
1(c)(6)(ii) -- Energy Regulation -- the 1992 Energy Act.  Many 
state electric utility regulators are considering plans to 
further encourage investment in wholesale generators and to 
facilitate utility decisions to spin off or divest generating 
capacity from the transmission or distribution businesses of the 
utilities.  As a result, Independent Power Projects in the future 
will face competition not only from other Independent Power 
Projects seeking to sell electricity on a wholesale basis but 
also from exempt wholesale generators, electric utilities with 
excess capacity and independent generators spun off or otherwise 
separated from their parent utilities.  Large-scale Projects that 
can sell large amounts of electricity or that have excellent 
reliability records or favorable locations may have competitive 
advantages over small-scale Projects (such as the Trust's), 
Projects that cannot commit to deliver power on a firm commitment 
basis or Projects that are located in electricity surplus areas 
with insufficient transmission capacity.

Wholesale-level Access to Transmission Capacity.  

     Without access to transmission capacity, an Independent 
Power Project or other wholesale generator can only sell to the 
local electric utility or to a facility on which it is located  
(or, in some states, which adjoins its location).  The most 
important changes occurring in the electric power industry are 
the efforts of FERC to compel utilities and power pools to 
provide nationwide access to transmission facilities to all 
wholesale power generators.  When combined with the increased 
competition in the generating area, this is likely to create an 
electricity supply market that may profoundly change the 
operations of electric utilities, consumers and Independent Power 
Projects.

     The 1992 Energy Act empowered FERC to require electric 
utilities and power pools to transmit electric power generated by 
other wholesale generators to wholesale customers.  This process 
is referred to as "wheeling" the electric power.  Essentially, 
the generator contributes power to a utility or power pool and is 
credited with that contribution, and the utility or power pool 
serving the wholesale customer makes available that amount of 
electric power to the customer and debits the generator.  
Wheeling is effected between power pools on a similar basis.  

     FERC initially dealt with wheeling requests on a case-by-
case basis as constrained by provisions of the 1992 Energy Act 
that require all costs of the transmitting utility to be 
recovered in the transmission charge and that prohibit wholesale 
competitors from wheeling power to customers of an electric 
utility under generating contracts or tariffs.  On April 24, 1996 
the Federal Energy Regulatory Commission adopted Order 888, which 
requires electric utilities and power pools to provide wholesale 
transmission facilities and information to all power producers on 
the same terms, and endorses the recovery by utilities of 
uneconomic capital costs from wholesale customers who change 
suppliers.  The utilities would also be required to furnish 
ancillary services, such as scheduling, load dispatch, and system 
protection, as needed.  These rights, however, would apply only 
to sales of new electric power over and above existing utility 
supply arrangements.  Initial trade estimates are that up to 6% 
of the entire U.S. market for wholesale power would be available 
to Independent Power Projects and other wholesale generators 
under the proposal.  

     Numerous regulatory issues must be addressed under this 
proposal of which one of the most contentious is the treatment of 
utility so-called "stranded costs."  Utilities that own 
generating plants with relatively high costs of production would 
be under severe competitive and regulatory pressure to purchase 
cheaper wholesale electricity, but in that event the utilities 
would not receive sufficient revenue to meet debt service 
requirements or other capital costs (the stranded costs)  
relating to the high-cost plants.  This might significantly 
impair utility cash flows and some utilities might be at risk of 
insolvency in that event.  The FERC order would require some 
mitigation efforts on the utility's part, but primarily would 
require wholesale customers who acquire electricity from a new 
supplier to compensate their former utility supplier for revenue 
lost.  This might require a customer who changes suppliers to pay 
a substantial additional fee to the prior utility supplier, thus 
inhibiting changes of supplier.   

     The order takes no action to modify existing power purchase 
contracts.  The order intends to create a competitive national 
market in electricity generation and thus may create additional 
pressure on electric utilities to seek changes to long-term power 
purchase contracts, as described further below.  The Trust has 
developed its business plan in anticipation of the order and will 
pursue its investment program to take advantage of opportunities 
as they arise in the changing industry.  The Trust is unable to 
predict the consequences of the order on its eventual operations 
or on the independent power industry.

     State public utility regulatory agencies must also review 
and approve certain aspects of wholesale power deregulation, and 
those agencies are currently holding proceedings and making 
determinations.  

     In addition to the FERC order or other Congressional or 
regulatory actions that may result in freer access to 
transmission capacity, agreements with Canada, and to a lesser 
extent with Mexico, are leading toward access for those 
countries' generators to U.S. markets.  In particular, certain 
Canadian suppliers, such as HydroQuebec (the Quebec provincial 
utility) are already offering substantial amounts of electricity 
in the U.S., and more may be offered if sufficient transmission 
capacity can be approved and built.  These agreements may also 
afford access to those countries' markets in the future for 
Independent Power Projects.  As a result, there is the 
possibility that a North American wholesale market will develop 
for electricity, with additional competitive pressures on U.S. 
generators.
 
Conservation Initiatives. 

     In recent years many state regulators, at the urging of 
citizens' groups and as contemplated by the 1992 Energy Act, have 
required electric utilities to engage in least cost utility 
planning, demand side management and other conservation programs.  
These programs have the common effect of encouraging utilities to 
look to conservation of electricity and the more efficient use of 
existing capacity as means of meeting new demand, as well as to 
purchases from Independent Power Projects or wholesale generators 
and to building more generation capacity.  There are also reports 
that utilities are reducing their reserve capacity levels to 
minimums and are more aggressively controlling dispatch of power 
as a means of minimizing new power purchases.  

Proposals to Modify PURPA and Existing Power Contracts.

     The independent power industry remains a creature of PURPA 
in most respects.  The prospects of increased competition to 
supply electricity, availability of wheeling of wholesale power, 
supply alternatives through the conservation initiative described 
above and reduced rates of increase in electricity demand have 
caused many electric utilities to advocate repeal or modification 
of PURPA and changes to existing long-term Power Contracts with 
Independent Power Projects.  These utilities have alleged that 
PURPA requires them to purchase electricity at higher prices than 
they could acquire new capacity themselves and that existing 
Power Contracts, signed when utilities anticipated much higher 
fuel and capital costs and higher demand, provide for prices 
substantially above current wholesale prices.  The independent 
power industry has pointed out that PURPA does not require 
utilities to purchase new supplies from Independent Power 
Projects at rates above alternative sources' prices (although a 
few state regulators have imposed such requirements from time to 
time) and that existing long-term Power Contracts were generally 
entered into on the basis of good faith estimates by the 
utilities of future conditions with the expectation that sponsors 
would rely upon them.  

     To date, FERC has rejected proposals to modify existing 
Power Contracts (except for contracts entered into under state 
regulations mandating payment of prices greater than utility 
avoided costs at the time the contracts were executed), and 
FERC's rulemaking proposals are expressly based on the principle 
that existing Power Contracts that comply with current law should 
not be modified by FERC.  Although proposals have been introduced 
in Congress to amend or repeal PURPA, no such proposal has yet 
been reported.  However, there can be no assurance that FERC or 
the Congress will not take action to reduce or eliminate the 
benefits or PURPA for Independent Power Projects or that they 
would not take action purporting to change or cancel existing 
Power Contracts or that they would not take action making 
compliance with those contracts economically or practically 
infeasible.  If any such action were to be taken, the value of 
existing Independent Power Projects might be significantly 
impaired or even eliminated.  If such action were to be proposed 
with any significant prospect of adoption, the consequent 
uncertainty might have similar effects.  

     In a related phenomenon, some electric utilities that are 
parties to long-term Power Contracts with rates substantially 
above current replacement costs have entered into buy-out 
arrangements with the owners of those Independent Power Projects.  
Under these agreements, the Power Contracts are terminated in 
exchange for a payment by the utility to the Project.  Typically, 
these arrangements have been limited to Independent Power 
Projects with high costs of production or other factors that have 
impaired their profitability, even with a firm Power Contract.  
The Trust does not anticipate investing in Projects with the 
expectation of soliciting or receiving a buy-out arrangement, but 
it will consider potential arrangements if conditions warrant. 

     In the absence of desired regulatory or legislative changes, 
many utilities have aggressively taken action to abrogate 
existing Power Contracts by alleging default by the generator or 
Project deficiencies.  Virginia Electric and Power Company 
attempted to do so for a Project owned by another business trust 
sponsored by the Managing Shareholder, alleging immaterial, 
technical violations of the Power Contract.  A federal district 
court held that the utility did not have the right to terminate 
the Power Contract on those grounds.  While the case was on 
appeal, that trust accepted an offer from the utility to settle 
the case by paying $3.75 million to the Trust in exchange for the 
cancellation of the Power Contract.  The settlement was concluded 
on January 17, 1997.   The case had no material effect on this 
Trust or its business.

Retail-level Competition

     An even more radical prospect for the electric power 
industry is retail-level competition, in which generators would 
be allowed to sell directly to customers by using (and paying a 
fee for) the local utility's distribution facilities.  Retail-
level competition presupposes the ability to wheel power in the 
appropriate amounts at economic costs from the generating Project 
to the electric utility whose wires link to the retail customer 
(typically a large industrial, commercial or governmental unit) 
and the ability to use the local utility's facilities to deliver 
the electricity to the customer.  In addition to the business and 
regulatory issues arising from wholesale wheeling, retail-level 
competition raises fundamental concerns as to the ability of 
utilities to recover stranded costs at the generating and 
distribution levels, the possibility that smaller customers will 
have less ability to demand pricing concessions, incentives for 
governmental agencies to act as intermediaries for consumers and 
the functions of state-level regulatory agencies in a price-
competitive environment which may be inconsistent with their 
traditional price-setting and service-prescribing roles. 

     Many states are experimenting with retail wheeling, 
including New Hampshire, whose three-year pilot program would 
allow up to 3% of state peak loads to be subject to retail 
competition, and Michigan, which is proposing to allow 
incremental growth in load demand to be supplied competitively.  
The New Hampshire program may be abrogated, because it proposes 
to split the burden of utility stranded costs between ratepayers 
and the utilities in opposition to FERC's position that utilities 
should not bear those costs. Many larger states, including 
California, New York, Massachusetts, Pennsylvania and Florida 
among others, are implementing large scale movements toward 
various forms of retail deregulation.  It appears that most 
states will do so by the year 2000.  These proposals are 
currently the subject of intensive debate and restructuring, and 
any such proposal is likely to undergo judicial review.  
Regulators and industry participants currently have extreme 
uncertainty as to whether and how far retail-level competition 
will be authorized, the treatment of stranded costs, the extent 
to which FERC's actions in the wholesale market will practically 
compel retail-level competition and the effects of any change.  
As of the date of this Annual Report, however, no state authority 
has proposed or implemented any plan that would abrogate or 
impair existing long-term Power Contracts with Independent Power 
Projects.  Instead, to the extent that long-term Power Contracts 
have rates above current avoided costs, the excess is being 
treated by most states as a form of stranded cost.  Many states 
are providing that all or most of the stranded costs will be 
borne by ratepayers rather than Independent Power Projects or 
utilities.  Typically, the state will require customers who 
change electricity suppliers to make payments to a fund used to 
reimburse utilities in part for the burden of stranded costs.  
Although this may lessen pressures on utilities to contest long-
term Power Contracts, it may deter retail customers from 
switching to independent power suppliers.

Initial Effects of Trends

     Although, as mentioned above, it is impractical to predict 
all the consequences of the rapidly evolving trends in the 
electric power industry, certain patterns are beginning to 
emerge.  First, as noted before, investment in new Independent 
Power Projects and in new utility generating capacity in the 
United States has substantially decelerated since 1993, as the 
larger participants in the development process (including 
developers, utilities, lenders and equipment suppliers) reassess 
their positions.  Indeed, many of the largest participants have 
announced their intentions to concentrate their resources in 
developing countries in Europe and Asia. Similarly, lenders are 
more reluctant currently to extend large amounts of non-recourse 
financing for development of Projects and are insisting on larger 
equity investments by owners of Projects.  The Trust believes 
that because it is focused on the independent power industry 
without competing business interests and because it seeks to make 
substantial equity investments in Projects, it has the ability to 
invest in attractive smaller Projects under these conditions.  

     In response to the current perceived slowing of electricity 
demand growth, the prospect of wholesale competition and the 
relatively higher prices currently payable under some long-term 
Power Contracts, many electric utilities have refrained from 
entering into new, long-term Power Contracts with Independent 
Power Projects and have instead proposed to purchase electricity 
from Qualifying Facilities or other generators under short-term 
contracts.  Competitive bidding by utilities, governmental units 
and in states where permitted, large industrial and commercial 
users for electricity supplies is becoming common.  In 1995 and 
1996, these competitive solicitations typically attracted large 
numbers of bids at prices substantially below prior utility 
prices.  Although these solicitations cover a minuscule part of 
the wholesale market, they indicate that there is currently 
intense competition to sell new capacity from Independent Power 
Projects. Certain state regulators, in response to these 
conditions, have proposed or approved auctions to generating 
businesses of the rights to supply utilities. In response to 
these developments, the Trust currently seeks to purchase 
Projects with existing long-term Power Contracts so as to 
minimize exposure to volatile short-term markets.  There is no 
assurance that it will be able to acquire those Projects or to do 
so on favorable terms.

     As a consequence of these trends and industry participants' 
reactions to them, many observers, including utilities, believe 
that there are temporary, regional surpluses of electric 
generating capacity.  For example, in the spring of 1995, the 
California public utilities commission projected that the state's 
three largest utilities would not need additional generating 
capacity until 2004, and that there was a current small surplus 
of capacity.  It should be noted, however, that the projections 
also foresaw a rapid increase of demand for capacity in the ten 
years following 2004.  Similarly, on a nationwide level a 1997 
estimate forecasted that 71,000 Megawatts of capacity is 
currently provided by fossil-fuel power plants that are over 30 
years old and are approaching the ends of their expected useful 
lives, that most nuclear power plants are facing relicensing 
proceedings that normally require extensive reconstruction, and 
that up to 10% of all U.S. generating capacity may be up for 
replacement in the next 15 years.  Accordingly, one of the most 
important and difficult questions for determination is whether 
the current reluctance to finance and build additional generating 
capacity will lead to capacity shortages on a regional or 
national basis in the next ten years.  Further, as the supply 
market becomes more fragmented and short-term, regulators and 
customers are beginning to raise concerns as to the dependability 
of supply.

     Another consequence of the current industry reluctance to 
commit to long-term increases in capacity and the perceived 
existence of regional surplus capacity is a short-term 
orientation on the part of many industry participants.  Recently, 
many companies, including affiliates of fuel suppliers and 
utilities, have applied to FERC to act as electric power 
marketers, because they anticipate that if wholesale wheeling 
becomes significant there will be strong demand for brokers or 
market makers in electric power.  It is uncertain whether power 
marketers will become significant factors in the electric power 
market.  A related development is the creation of derivative 
contracts for hedging of and speculation in electricity supplies.  
A few developers and utilities are also considering the 
construction of "merchant power plants," which would be built 
without firm Power Contracts in hopes of marketing their output 
on the anticipated short-term, competitive wholesale or retail 
markets.  

     With these conditions in mind, many observers see two 
primary strategies for Independent Power Projects to succeed in 
the United States:  first, Projects that have existing, firm, 
long-term Power Contracts may do well so long as regulatory or 
legislative actions do not abrogate the contracts.    Second, 
Projects that are low-cost producers of electricity, either from 
efficiencies or good management or as the result of successful 
cogeneration technologies, will have advantages in the 
competitive market.  The Trust intends to focus on both 
possibilities and to maintain a focus on medium-to-long-term 
results.  It also will consider Projects selling power to retail 
users rather than utilities.

     Finally, there have been industry-wide moves toward 
consolidation of participants and divestiture of Projects.  A 
number of utilities and equipment suppliers have proposed or 
entered into joint ventures to reduce risks and mobilize 
additional capital for the more competitive environment, while 
many electric utilities are in the process of combining, either 
as a means of reducing costs and capturing efficiencies, or as a 
means of increasing size as an organizational survival tactic.  A 
number of large natural gas utilities have also acquired or are 
considering acquiring electric utilities.  Industry observers 
have attributed this to the more entrepreneurial character of the 
gas industry, which has already been deregulated, and to the fact 
that natural gas is currently a preferred fuel for generating 
plants, which may encourage the combination of the fuel suppliers 
with fuel users to assure supply and reduce uncertainties.  These 
consolidations and acquisitions tend to create additional 
competitive pressures in the electric power industry; however, 
this trend is also encouraging the divestiture of smaller 
Projects or Projects that are deemed less central to the 
operations of large, consolidated businesses.  This may make 
attractive Projects available for investment by the Trust but may 
also tend to depress the resale value of the Trust's projects.

     The Byron, San Joaquin and Providence Projects have long-
term Power Contracts and the Trust intends to continue sales to 
the local utilities under those contracts, with no current plans 
to seek other customers.  In the event that the Power Contracts 
were terminated for any reason, the Trust might seek to sell 
electricity to other customers, but its ability to do so 
profitably cannot be assured.  

     The On-site Cogeneration Projects have output contracts with 
their hosts that expire at various times from 1998 to 2005.  The 
Trust is reviewing each contract with a view towards 
renegotiating or terminating it as the contract comes up for 
renewal, or in some cases in advance of the renewal date.  The 
profitability of each contract to the Trust and the benefits to 
the host depend upon the price of competing utility service and 
the efficient operation of the Project.  Accordingly, these 
contracts are sensitive to outside market conditions.

5.  Competition

     There are a large number of participants in the independent 
power industry.  Several large corporations specialize in 
developing, building and operating Independent Power Projects.  
Equipment manufacturers, including many of the largest 
corporations in the world, provide equipment and planning 
services and provide capital through finance affiliates.  Many 
regulated utilities are preparing for a competitive market, and a 
significant number of them already have organized subsidiaries or 
affiliates to participate in unregulated activities such as 
planning, development, construction and operating services or in 
owning exempt wholesale generators or up to 50% of Independent 
Power Projects.  In addition, there are many smaller firms whose 
businesses are conducted primarily on a regional or local basis.  
Many of these companies focus on limited segments of the 
cogeneration and independent power industry and do not provide a 
wide range of products and services.  There is significant 
competition among non-utility producers, subsidiaries of 
utilities and utilities themselves in developing and operating 
energy-producing projects and in marketing the power produced by 
such projects.

     The Trust is unable to accurately estimate the number of 
competitors but believes that there are many competitors at all 
levels and in all sectors of the industry.  Many of those 
competitors, especially affiliates of utilities and equipment 
manufacturers, may be far better capitalized than the Trust.

     Competition to market its energy products is generally not a 
factor in the current operations of the Trust since the major 
Projects in which it invests and proposes to invest have entered 
into long-term agreements to sell their output at specified 
prices.  However, a particular Project could be subject to future 
competition to market its energy products if its Power Contract 
expires or is terminated because of a default or failure to pay 
by the purchasing utility or other purchaser due to bankruptcy or 
insolvency of the purchaser or because of the failure of a 
Project to comply with the terms of the Power Contract; 
regulatory changes; loss of a cogeneration facility's status as a 
Qualifying Facility due to failure to meet minimum steam output 
requirements; or other reasons.  It is impossible at this time to 
estimate the level of marketing competition that the Trust would 
face in any such event.

6.  Regulatory Matters.

     Projects are subject to energy and environmental laws and 
regulations at the federal, state and local levels in connection 
with development, ownership, operation, geographical location, 
zoning and land use of a Project and emissions and other 
substances produced by a Project.  These energy and environmental 
laws and regulations generally require that a wide variety of 
permits and other approvals be obtained before the commencement 
of construction or operation of an energy-producing facility and 
that the facility then operate in compliance with such permits 
and approvals.  Since the Trust operates as a "business 
development company" under the 1940 Act, it is also subject to 
provisions of that act pertaining to such companies.

(i)  Energy Regulation.

(A)  PURPA.  The enactment in 1978 of PURPA and the adoption of 
regulations thereunder by FERC provided incentives for the 
development of cogeneration facilities and small power production 
facilities meeting certain criteria.  Qualifying Facilities under 
PURPA are generally exempt from the provisions of the Public 
Utility Holding Company Act of 1935, as amended (the "Holding 
Company Act"), the Federal Power Act, as amended (the "FPA"), 
and, except under certain limited circumstances, state laws 
regarding rate or financial regulation.  In order to be a 
Qualifying Facility, a cogeneration facility must (a) produce not 
only electricity but also a certain quantity of heat energy (such 
as steam) which is used for a purpose other than power 
generation, (b) meet certain energy efficiency standards when 
natural gas or oil is used as a fuel source and (c) not be 
controlled or more than 50% owned by an electric utility or 
electric utility holding company.  Other types of Independent 
Power Projects, known as "small power production facilities," can 
be Qualifying Facilities if they meet regulations respecting 
maximum size (in certain cases), primary energy source and 
utility ownership.  Recent federal legislation has eliminated the 
maximum size requirement for solar, wind, waste and geothermal 
small power production facilities (but not for hydroelectric or 
biomass) for a fixed period of time.

     In addition, PURPA requires electric utilities to purchase 
electricity generated by Qualifying Facilities at a price equal 
to the purchasing utility's full "avoided cost" and to sell back 
up power to Qualifying Facilities on a non discriminatory basis.  
Avoided costs are defined by PURPA as the "incremental costs to 
the electric utility of electric energy or capacity or both 
which, but for the purchase from the Qualifying Facility or 
Qualifying Facilities, such utility would generate itself or 
purchase from another source."  While public utilities are not 
required by PURPA to enter into long-term Power Contracts to meet 
their obligations to purchase from Qualifying Facilities, PURPA 
helped to create a regulatory environment in which it has become 
more common for such contracts to be negotiated until recent 
years.

     The exemptions from extensive federal and state regulation 
afforded by PURPA to Qualifying Facilities are important to the 
Trust and its competitors.  The seller of the On-site 
Cogeneration Projects has warranted that each On-site 
Cogeneration Project is a Qualifying Facility and the Trust 
currently believes that all or substantially all of those 
Projects are Qualifying Facilities.  The Trust currently believes 
that each of its other Projects is a Qualifying Facility.  
Maintaining the Qualified Facility status of a Project is of 
utmost importance to the Trust.  Such status may be lost if a 
Project does not meet the operational requirements of PURPA, such 
as minimum operating efficiency standards and minimum use of 
thermal energy by customers of a cogeneration Project.  The Trust 
endeavors to comply with these requirements, but there can be no 
assurance that a Project will maintain its Qualified Facility 
status.  If a Project loses its Qualifying Facility status, the 
utility can reclaim payments it made for the Project's non-
qualifying output to the extent those payments are in excess of 
current avoided costs (which are generally substantially below 
the Power Contract rates) or the Project's Power Contract can be 
terminated by the electric utility.  In California, the state 
regulator has authorized a comprehensive monitoring system under 
which electric utilities continuously meter a Project's 
performance.  Many California utilities, including PG&E, the 
utility that purchases the electric output from the Byron and San 
Joaquin Projects, aggressively use this data to press for 
termination of Qualifying Facility status, and there is an 
ongoing risk that the utility will assert that the Projects do 
not qualify for any given year.  The Trust believes that those 
Projects have qualified and will qualify. 

(B)  The 1992 Energy Act.  The Comprehensive Energy Policy Act of 
1992 (the "1992 Energy Act") empowered FERC to require electric 
utilities to make available their transmission facilities to and 
wheel power for Independent Power Projects under certain 
conditions and created an exemption for electric utilities, 
electric utility holding companies and other independent power 
producers from certain restrictions imposed by the Holding 
Company Act.  Although the Trust believes that the exemptive 
provisions of the 1992 Energy Act will not materially and 
adversely affect its business plan, the act may result in 
increased competition in the sale of electricity.

     The 1992 Energy Act created the "exempt wholesale generator" 
category for entities certified by FERC as being exclusively 
engaged in owning and operating electric generation facilities 
producing electricity for resale.  Exempt wholesale generators 
remain subject to FERC regulation in all areas, including rates, 
as well as state utility regulation, but electric utilities that 
otherwise would be precluded by the Holding Company Act from 
owning interests in exempt wholesale generators may do so.  
Exempt wholesale generators, however, may not sell electricity to 
affiliated electric utilities without express state approval that 
addresses issues of fairness to consumers and utilities and of 
reliability.

(C)  The Federal Power Act.  The FPA grants FERC exclusive 
rate-making jurisdiction over wholesale sales of electricity in 
interstate commerce.  The FPA provides FERC with ongoing as well 
as initial jurisdiction, enabling FERC to revoke or modify 
previously approved rates.  Such rates may be based on a 
cost-of-service approach or determined through competitive 
bidding or negotiation.  While Qualifying Facilities under PURPA 
are exempt from the rate-making and certain other provisions of 
the FPA, non-Qualifying Facilities are subject to the FPA and to 
FERC rate-making jurisdiction.  

     Companies whose facilities are subject to regulation by FERC 
under the FPA because they do not meet the requirements of PURPA 
may be limited in negotiations with power purchasers.  However, 
since such projects would not be bound by PURPA's heat energy use 
requirement for cogeneration facilities, they may have greater 
latitude in site selection and facility size.  If any of the 
Trust's electric power Projects failed to be a Qualifying 
Facility, it would have to comply with the FPA.

(D)  Fuel Use Act.  Projects may also be subject to the Fuel Use 
Act, which limits the ability of power producers to burn natural 
gas in new generation facilities unless such facilities are also 
coal capable within the meaning of the Fuel Use Act.  The Trust 
believes that each of its Projects subject to the Act is coal 
capable and thus qualifies for exemption from the Fuel Use Act.

(E)  State Regulation.  State public utility regulatory 
commissions have broad jurisdiction over Independent Power 
Projects which are not Qualifying Facilities under PURPA, and 
which are considered public utilities in many states.  In states 
where the wholesale or retail electricity market remains 
regulated, Projects that are not Qualifying Facilities may be 
subject to state requirements to obtain certificates of public 
convenience and necessity to construct a facility and 
organizational, accounting, financial and other corporate matters 
could be regulated on an ongoing basis.  Although FERC generally 
has exclusive jurisdiction over the rates charged by a 
non-Qualifying Facility to its wholesale customers, state public 
utility regulatory commissions have the practical ability to 
influence the establishment of such rates by asserting 
jurisdiction over the purchasing utility's ability to pass 
through the resulting cost of purchased power to its retail 
customers.  In addition, states may assert jurisdiction over the 
siting and construction of non-Qualifying Facilities and, among 
other things, issuance of securities, related party transactions 
and sale and transfer of assets.  The actual scope of 
jurisdiction over non-Qualifying Facilities by state public 
utility regulatory commissions varies from state to state.  
Certain states, including Rhode Island, also restrict the 
ownership of inside-the-fence Projects by persons other than the 
host, thus requiring the use of a lease structure or other 
arrangements.

(ii)  Environmental Regulation.

     The construction and operation of Independent Power Projects 
and the exploitation of natural resource properties are subject 
to extensive federal, state and local laws and regulations 
adopted for the protection of human health and the environment 
and to regulate land use.  The laws and regulations applicable to 
the Trust and Projects in which it invests primarily involve the 
discharge of emissions into the water and air and the disposal of 
waste, but can also include wetlands preservation and noise 
regulation.  These laws and regulations in many cases require a 
lengthy and complex process of renewing licenses, permits and 
approvals from federal, state and local agencies.  Obtaining 
necessary approvals regarding the discharge of emissions into the 
air is critical to the development of a Project and can be 
time-consuming and difficult.  Each Project requires technology 
and facilities which comply with federal, state and local 
requirements, which sometimes result in extensive negotiations 
with regulatory agencies.  Meeting the requirements of each 
jurisdiction with authority over a Project may require extensive 
modifications to existing Projects.

     The Clean Air Act Amendments of 1990 contain provisions 
which regulate the amount of sulfur dioxide and oxides of 
nitrogen which may be emitted by a Project.  These emissions may 
be a cause of "acid rain."  Qualifying Facilities are currently 
exempt from the acid rain control program of the Clean Air Act 
Amendments.  However, non-Qualifying Facility Projects will 
require "allowances" to emit sulfur dioxide after the year 2000.  
Under the Amendments, these allowances may be purchased from 
utility companies then emitting sulfur dioxide or from the 
Environmental Protection Agency ("EPA").  Further, an Independent 
Power Project subject to the requirements has a priority over 
utilities in obtaining allowances directly from the EPA if (a) it 
is a new facility or unit used to generate electricity; (b) 80% 
or more of its output is sold at wholesale; (c) it does not 
generate electricity sold to affiliates (as determined under the 
Holding Company Act) of the owner or operator (unless the 
affiliate cannot provide allowances in certain cases) and (d) it 
is non-recourse project-financed.  

     The market price of an allowance cannot be predicted with 
certainty at this time and there is no assurance that a market 
for such allowances will develop.  Projects fueled by natural gas 
are not expected to be materially burdened by the acid rain 
provisions of the Clean Air Act Amendments.  

     The Clean Air Act Amendments empower states to impose annual 
operating permit fees of at least $25 per ton of regulated 
pollutants emitted up to $100,000 per pollutant.  To date, no 
state in which the Trust operates has done so.  If a state were 
to do so, such fees might have a material effect on the Trust's 
costs of generation, in light of the relatively small size of the 
Trust's facilities as opposed to large utility generation plants 
that might benefit from the cap on fees.

     Based on current trends, the Managing Shareholder expects 
that environmental and land use regulation will become more 
stringent.  The Trust and the Managing Shareholder have not 
developed expertise and experience in obtaining necessary 
licenses, permits and approvals, which will be the responsibility 
of each Project's managers and Project Sponsors.  The Trust will 
rely upon qualified environmental consultants and environmental 
counsel retained by it or by Project Sponsors to assist in 
evaluating the status of Projects regarding such matters.

(iii)  The 1940 Act

     Since its Shares are registered under the 1934 Act, the 
Trust is required to file with the Commission certain periodic 
reports (such as Forms 10-K (annual report), 10-Q (quarterly 
report) and 8-K (current reports of significant events) and to be 
subject to the proxy rules and other regulatory requirements of 
that act that are applicable to the Trust.  The Trust has no 
intention to and will not permit the creation of any form of a 
trading market in the Shares in connection with this 
registration.

     On February 14, 1994, the Trust notified the Securities and 
Exchange Commission (the "Commission") of its election to be a 
"business development company" and registered its Shares under 
the 1934 Act.  On April 16, 1994, the election and registration 
became effective.  As a "business development company," the Trust 
is a closed-end company (defined by the 1940 Act as a company 
that does not offer for sale or have outstanding any redeemable 
security) that is regulated under the 1940 Act only as a business 
development company.  The act contains prohibitions and 
restrictions on transactions between business development 
companies and their affiliates as defined in that act, and 
requires that a majority of the board of the company be persons 
other than "interested persons" as defined in the act.  The board 
of the Trust is comprised of the Managing Shareholder and two 
individuals, Ralph O. Hellmold and Jonathan C. Kaledin, who also 
serve as independent trustees of the Trust and who serve as 
independent trustees of Ridgewood Electric Power II, and are 
independent panel members of Ridgewood Electric Power Trust V, 
each of which is a similar investment program organized by the 
Managing Shareholder,, but who are not otherwise affiliated with 
the Trust, the Managing Shareholder or any of their affiliates.  
See Item 10 -- Directors and Executive Officers of the Registrant.

     Under the 1940 Act, Commission approval is required for 
certain transactions involving certain closely affiliated persons 
of business development companies, including many transactions 
with the Managing Shareholder and the other investment programs 
sponsored by the Managing Shareholder.  There can be no assurance 
that such approval, if required, would be obtained.  In addition, 
a business development company may not change the nature of its 
business so as to cease to be, or to withdraw its election as, a 
business development company unless authorized to do so by at 
least a majority vote of its outstanding voting securities.

     The 1940 Act restricts the kind of investments a business 
development company may make.  A business development company may 
not acquire any asset other than a "Qualifying Asset" unless, at 
the time the acquisition is made, Qualifying Assets comprise at 
least 70% of the company's total assets by value.  The principal 
categories of Qualifying Assets that are relevant to the Trust's 
activities are:

(A)  Securities issued by "eligible portfolio companies" that are 
purchased by the Trust from the issuer in a transaction not 
involving any public offering (i.e., private placements of 
securities).  An "eligible portfolio company" (1) must be 
organized under the laws of the United States or a state and have 
its principal place of business in the United States; (2) may not 
be an investment company other than a small business investment 
company licensed by the Small Business Administration and 
wholly-owned by the Trust and (3) may not have issued any class 
of securities that may be used to obtain margin credit from a 
broker or dealer in securities.  The last requirement essentially 
excludes all issuers that have securities listed on an exchange 
or quoted on the National Association of Securities Dealers, 
Inc.'s national market system, along with other companies 
designated by the Federal Reserve Board.  Except for temporary 
investments of the Trust's available funds, substantially all of 
the Trust's investments are expected to be Qualifying Assets 
under this provision.

(B)  Securities received in exchange for or distributed on or 
with respect to securities described in paragraph (A) above, or 
on the exercise of options, warrants or rights relating to those 
securities.

(C)  Cash, cash items, U.S. Government securities or high quality 
debt securities maturing not more than one year after the date of 
investment.

     A business development company must make available 
"significant managerial assistance" to the issuers of Qualifying 
Assets described in paragraphs (A) and (B) above, which may 
include without limitation arrangements by which the business 
development company (through its directors, officers or 
employees) offers to provide (and, if accepted, provides) 
significant guidance and counsel concerning the issuer's 
management, operation or business objectives and policies.

     A business development company also must be organized under 
the laws of the United States or a state, have its principal 
place of business in the United States and have as its purpose 
the making of investments in Qualifying Assets described in 
paragraph (A) above.

     The Managing Shareholder believes that it may no longer be 
necessary for the Trust to continue its status as a business 
development company, because of the Managing Shareholder's active 
involvement in operating Projects through the Trust and other 
investment programs.  Although the Managing Shareholder believes 
it would be beneficial to the Trust to end the election and 
reduce costs of legal compliance that do not contribute to 
income, the process of withdrawing the business development 
company election requires a proxy solicitation and a special vote 
of investors, which is also costly.  Accordingly, the Managing 
Shareholder does not intend at this time to request the 
Investors' consent to withdrawing the business development 
company election.  Any change in the Trust's status will be 
effected only with the Investors' consent.

(d)  Financial Information about Foreign and Domestic Operations 
and Export Sales. 

     The Trust has invested in Projects located in California, 
Connecticut, Massachusetts, New York and Rhode Island and has no 
foreign operations.

(e)  Employees.

     The employees of the Byron and San Joaquin Projects have 
been transferred to RPMC and accordingly the Trust has no 
employees.  The persons described below at Item 10.  Directors 
and Executive Officers of the Registrant serve as executive 
officers of the Trust and have the duties and powers usually 
applicable to similar officers of a Delaware corporation in 
carrying out the Trust business.

Item 2.  Properties.

     Pursuant to the Management Agreement between the Trust and 
the Managing Shareholder (described at Item 10(c)), the Managing 
Shareholder provides the Trust with office space at the Managing 
Shareholder's principal office at The Ridgewood Commons, 947 
Linwood Avenue, Ridgewood, New Jersey 07450.  

     The following table shows the material properties (relating 
to Projects) owned or leased by the Trust's subsidiaries or 
partnerships in which the Trust has an interest.  The On-site 
Cogeneration Projects are located on the hosts' sites and 
generally do not occupy material amounts of space. All of the 
Projects are described in further detail at Item 1(c)(2).

Approximate
                                                       Square
                     Ownership  Ground   Approximate  Footage of   Description
                      Interests  Lease      Acreage    Project (Actual    of
Project      Location  in Land  Expiration   of Land  or Projected)    Project

Byron         Byron,      Leased    2021         2      28,000      Gas-fired
            California                                            cogeneration 
                                                                     facility 
San Joaquin  Atwater,     Leased    2021         1      25,000       Gas-fired
            California                                            cogeneration 
                                                                     facility
On-Site      31 sites     Leased   various       n/a       n/a     Inside-the-
Cogeneration   in CA,       or                                          fence,
              CT, MA,     licensed                                   gas-fired
             NY and RI                                              or diesel-
                                                                       fueled 
                                                                 cogeneration 
                                                                  engines and 
                                                                    generators
Providence   Providence,  Leased    2020         4      10,000       Landfill 
            Rhode Island                                             gas-fired 
                                                                    generation 
                                                                      facility

Item 3.  Legal Proceedings.

     There are no legal proceedings involving the Trust.  The 
Trust's subsidiaries that own the San Joaquin and Byron Projects 
filed suit in the Superior Court of California, City and County 
of San Francisco, in February 1997 against PG&E, alleging breach 
of the Power Contracts by PG&E's withholding a total of 
approximately $164,000 as noted above.  PG&E has answered the 
complaint and has counterclaimed for all payments made to those 
Projects.

     The Trust's subsidiaries that own the On-site Cogeneration 
Projects brought an arbitration proceeding in the amount of $4.1 
million against the seller, a subsidiary of Eastern Utilities 
Associates, Inc., before the American Arbitration Association in 
Boston, Massachusetts in December 1996, alleging breaches of 
representations and warranties made by the seller in the 
agreements of sale.  The seller has counterclaimed for 
approximately $550,000 that it alleges it was owed for management 
services during October, November and December 1995.  The parties 
are in the process of naming arbitrators.

Item 4.  Submission of Matters to a Vote of Security Holders.

     The Trust did not submit any matters to a vote of the 
Investors during the fourth quarter of 1995. 

PART II

Item 5.  Market for Registrant's Common Equity and Related 
Stockholder Matters.

(a)  Market Information.  

     The Trust sold 391.8444 Investor Shares of beneficial 
interest in the Trust in its private placement offering of 
Investor Shares which closed on May 31, 1995.  There is currently 
no established public trading market for the Investor Shares and 
the Trust does not intend to allow a public trading market to 
develop.  As of the date of this Form 10-K, all such Investor 
Shares have been issued and are outstanding.  There are no 
outstanding options or warrants to purchase, or securities 
convertible into, Investor Shares and the Trust has no intention 
to make any public offering of Investor Shares.

     Investor Shares are restricted as to transferability under 
the Declaration.  In addition, under federal laws regulating 
securities the Investor Shares have restrictions on 
transferability when the Investor Shares are held by persons in a 
control relationship with the Trust.  Investors wishing to 
transfer Shares should also consider the applicability of state 
securities laws.  The Investor Shares have not been and are not 
expected to be registered under the Securities Act of 1933, as 
amended (the "1933 Act"), or under any other similar law of any 
state (except for certain registrations that do not permit free 
resale) in reliance upon what the Trust believes to be exemptions 
from the registration requirements contained therein.  Because 
the Investor Shares have not been registered, they are 
"restricted securities" as defined in Rule 144 under the 1933 
Act.

(b)  Holders

     As of the date of this Form 10-K, there are 764 record 
holders of Investor Shares.

(c)  Dividends

     The Trust made no distributions for the year 1994 and made 
distributions as follows in the years 1995 and 1996:

                             Year ended                Year ended
                           December 31, 1996    December 31, 1995
Total distributions
 to Investors                $3,694,661               $2,310,158
Distributions per
 Investor Share                   9,429                    5,896
Distributions to
 Managing Shareholder           $37,312                   17,522

     Distributions are made on a monthly basis.  The Trust's 
ability to make future distributions to Investors and their 
timing will depend on the net cash flow of the Trust and 
retention of reasonable reserves as determined by the Trust to 
cover its anticipated expenses. Subject to the other factors 
described in this Annual Report on Form 10-K, the Trust's goal is 
to provide Investors with annual distributions of net cash flow, 
as defined in the Declaration of Trust, of 14% of their Capital 
Contributions to the Trust.  Because the Trust's objective is to 
distribute net cash flow, a substantial portion of many 
distributions will include cash flow that represents depreciation 
and amortization charges against assets at the Project level.  
Nevertheless, because the Projects are not consolidated with the 
Trust for accounting purposes, all funds received from Projects 
are considered to be revenue to the Trust for accounting 
purposes.  Occasionally, distributions may also include cash 
released from operating or debt service reserves, Trust-level 
depreciation or amortization, or other non-cash charges against 
earnings.  For purposes of generally accepted accounting 
principles, amounts of distributions in excess of accounting 
income may be considered to be capital in nature.  Investors 
should be aware that the Trust is organized to return net cash 
flow rather than accounting income to Investors.

Item 6.  Selected Financial Data.

     The following data is qualified in its entirety by the 
financial statements presented elsewhere in this Annual Report on 
Form 10-K.

Supplemental Information      As of and          As of and          As of and
 Schedule                      for the            for the            for the 
Selected Financial Data      Year Ended         Year Ended       Period Ended 
                             December 31,      December 31,       December 31,
                                1996              1995               1994     
Total Fund Information:
Net revenue from
 operating projects          $3,525,613         $1,317,287                 $0
Net income (loss)             2,541,686          1,440,550           (213,299)
Net assets (shareholders'
 equity)                     31,388,939         32,579,226         18,671,356
Investments in project
 development and power
 generation limited  
 partnerships                28,050,750         20,884,493                  0
Total assets                 31,430,075         32,651,668         18,405,145
Per Investor Share:
  Revenues                       $9,630             $6,066             $1,178
  Expenses                        3,143              2,389              2,144
  Net income (loss)               6,486              3,676               (966)
  Net asset value                80,106             83,143             84,598
Distributions to Investors        9,429              5,896                  0


Item 7.  Management's Discussion and Analysis of Financial 
Condition and Results of Operations.

     The following discussion and analysis should be read in 
conjunction with the Trust's financial statements and the notes 
thereto presented elsewhere herein.

Results of Operations.

     Income of the Trust from Projects was as follows:


Project                              1996                   1995
Byron                            $428,540               $335,211
San Joaquin                       779,409                982,076
On-site Cogeneration (total)    1,756,410                      0
    Massachusetts                 660,201                      0
    Rhode Island                  572,970                      0
    Coca-Cola                     160,940                      0
    Others                        362,299                      0
Providence                        562,427*                     0

*  April 16-December 31, 1996.

     12 months ended December 31, 1996 versus 12 months ended 
December 31, 1995.

     Net income for 1996 was $2,542,000, a $1,101,000 increase 
(76.4%) from the 1995 net income of $1,441,000.  Revenues 
increased $1,042,000 to $3,773,000 (38.2%), while Trust-level 
expenses rose to $1,232,000 in 1996 from $936,000 in the prior 
year, a $295,000 (31.5%) increase.

     With the On-site Cogeneration Projects and the Providence 
Project making their first distributions to the Trust in 1996, 
income from power generation projects increased by 167.6% 
($2,208,000) to $3,526,000, and concurrently, as funds were 
invested in Projects, interest and dividend income decreased to 
$248,000 in 1996 from $1,060,000 in 1995, an $812,000 (76.6%) 
decrease.  Distributions from the On-site Cogeneration Projects 
were substantially below expectations (a 14.1% annual return in 
1996), resulting from poor maintenance and operation and in some 
cases a pattern of overbilling under prior ownership.  These 
Projects also suffered temporarily in late 1996 from sharp 
increases in natural gas prices.  Most of these Projects are 
"shared savings" projects under which the Projects' billings are 
computed with reference to utilities' retail electricity and gas 
rates.  Because utility rates to retail customers in many cases 
did not rise as fast as the gas prices paid by the Projects, 
margins were severely impacted in 1996.  The high natural gas 
prices began to abate in February 1997 and the Trust is taking 
action to obtain longer-term gas supplies (where its customers 
will cooperate) to reduce exposure to gas price fluctuations.  

     Distributions from the Providence Project were low (an 11.1% 
annualized return) but within expectations.  At the time the 
Project was purchased its profitability was low and the Trust 
planned to make significant investments and changes to operations 
to increase the Project's efficiency and profitability.  As 
discussed above, output has increased by an average of 33% in the 
8 1/2 months of ownership by the Trust.

     Trust-level expenses increased by 31.5% from 1995 to 1996, 
but the nature of those expenses changed significantly as the 
Trust ended the major portion of its investment program.  The 
investment fee, which is charged in the year capital 
contributions are made and which is paid to the Managing 
Shareholder to compensate it for investment advice and 
evaluation, was $344,000 in 1995 but was not charged in 1996, 
reflecting the conclusion of the offering of Investor Shares in 
1995.  The management fee, which is charged on the basis of the 
Trust's net assets, increased from $482,000 in 1995 to $794,000 
in 1996, a $312,000 (64.6%) increase.  The management fee is 
expected to remain at that level.  

     The investment process caused significant increases in due 
diligence and project investigation expenses payable to third 
parties, which increased to $258,000 in 1996 from $8,000 in 1995. 
These expenses are not expected to recur at those levels.  The 
Trust also incurred writeoffs of $113,000 for the four small 
discontinued On-site Cogeneration Projects.  

     Other Trust-level operating expenses included accounting and 
legal fees, which decreased $42,000 (46.4%) from $90,000 in 1995 
to $48,000 in 1996, as the start-up period ended, and other 
expenses, which rose from $12,000 to $18,000 (50.5%).
 
     12 months ended December 31, 1995 versus period ended 
December 31, 1994.

     Net income for calendar 1995 was $1,440,550 as compared to a 
net loss of $231,299 for 1994 (January 3, 1994 through December 
31, 1994).  The 1995 results reflect the ending of the Trust's 
offering of Investor Shares and the beginning of operations.  
Revenues increased by 814.5% from 1994, as two Projects were 
acquired and began to distribute cash flow to the Trust, and 
interest revenue increased because of the larger amount of 
offering proceeds received and awaiting investment.  

     Expenses increased by 97.9% to $936,000; however, $344,000 
of this amount reflects payment of the investment fee on sales of 
Investor Shares made during 1995.  This fee will not recur.  The 
remainder of the increase is attributable to the annual 
management fee paid for the first time in 1995 to the Managing 
Shareholder, and to increases in accounting and legal expenses as 
a consequence of beginning operations.  

     Trends affecting the independent power industry generally 
are described at Item 1 -- Business.

Liquidity and Capital Resources.

     The Trust currently intends to apply up to $400,000 of its 
$2.9 million of uninvested funds to modifications to the host's 
facilities at the San Joaquin Project to allow year-round 
operation.  It anticipates that demands in 1997 for maintenance 
and improvement funds and working capital over and above cash 
flow generated by the Projects will not be significant.  
Therefore, the Trust will attempt to invest the remaining funds 
in a small-scale Project or Projects, such as the small 
cogeneration Projects described above at Item 1(c)(2) -- Business 
-- Narrative Description of Business -- The Trust's Investments.

     The Trust anticipates that its cash flow during 1997 and 
unexpended offering proceeds will be adequate to fund its 
obligations.  In the event that there is an unanticipated need 
for working capital or for repairs or replacement of equipment, 
the Managing Shareholder has also obtained a credit line of 
$500,000 from a bank, which it intends to make available for 
those purposes to the Trust or other programs the Managing 
Shareholder is sponsoring.  The Managing Shareholder will not 
impose charges for use of that line in excess of those charged to 
it by the bank.

Trends affecting Results of Operations.

     In addition to the industry trends discussed above at Item 
1(c)(4) -- Business --Trends in the Electric Utility and 
Independent Power Industries as described above, several of the 
Trust's Projects are experiencing significant pressures on their 
profitability and operations.  Recent increases in natural gas 
prices during the winter months of 1996 and early 1997 impaired 
profitability at certain of the On-Site Cogeneration Projects, 
although prices began to fall toward prior levels in February 
1997.  As the Byron and San Joaquin Projects move to 12 month 
operation, they will become exposed to wintertime fluctuations in 
gas prices.  The Managing Shareholder is considering entering 
into long-term gas supply arrangements to reduce exposure to the 
gas price fluctuations, but the relatively small size of the 
Projects as customers may limit its ability to do so. The 
Providence Project, which burns landfill gas, has no exposure to 
gas price fluctuations.

Item 8.  Financial Statements and Supplementary Data.

Index to Financial Statements


     Report of Independent Accountants                       F-2
      Statement of Operations for Years
      ended December 31, 1996 and 
      1995 and Period from Commencement of
      Share Offering (January 4, 1994)
      through December 31, 1994                              F-3
     Balance Sheet at December 31, 1996 and 1995             F-4
     Statement of Changes in Shareholders'
      Equity for Years ended 
      December 31, 1996 and 1995 and
      Period from Commencement of Share
      Offering through December 31, 1994                     F-5
     Statement of Cash Flows for Years
      ended December 31, 1996 and 1995
      and Period from Commencement of Share
      Offering through December 31, 1995                F-6 -F-7
     Notes to Financial Statements                    F-8 to F-13

     All schedules are omitted because they are not applicable or 
the required information is shown in the financial statements or 
notes thereto.

     The financial statements are presented in accordance with 
generally accepted accounting principles and Securities and 
Exchange Commission positions applicable to business investment 
companies, which require the Trust's investments in Projects to 
be presented on the cash method, rather than on the equity 
method.  

Item 9.  Changes in and Disagreements with Accountants on 
Accounting and Financial Disclosure.

     Neither the Trust nor the Managing Shareholder has had an 
independent accountant resign or decline to continue providing 
services since their respective inceptions and neither has 
dismissed an independent accountant during that period.  During 
that period of time no new independent accountant has been 
engaged by the Trust or the Managing Shareholder, and the 
Managing Shareholder's current accountants, Price Waterhouse LLP, 
have been engaged by the Trust.

PART III

Item 10.  Directors and Executive Officers of the Registrant.

(a)  General.

     As Managing Shareholder of the Trust, Ridgewood Power 
Corporation has direct and exclusive discretion in management and 
control of the affairs of the Trust (subject to the general 
supervision and review of the Independent Trustees and the 
Managing Shareholder acting together as the Board of the Trust).  
The Managing Shareholder will be entitled to resign as Managing 
Shareholder of the Trust only (i) with cause (which cause does 
not include the fact or determination that continued service 
would be unprofitable to the Managing Shareholder) or (ii) 
without cause with the consent of a majority in interest of the 
Investors.  It may be removed from its capacity as Managing 
Shareholder as provided in the Declaration.

     Ridgewood Energy Holding Corporation, a Delaware corporation 
incorporated in April 1992, is the Corporate Trustee of the 
Trust.

(b)  Managing Shareholder.

     The Managing Shareholder was incorporated in February 1991 
as a Delaware corporation for the primary purpose of acting as a 
managing shareholder of business trusts and as a managing general 
partner of limited partnerships which are organized to 
participate in the development, construction and ownership of 
Independent Power Projects.

     The Managing Shareholder has also organized Ridgewood 
Electric Power Trust I ("Ridgewood Power I"), Ridgewood Electric 
Power Trust II ("Ridgewood Power II"), Ridgewood Electric Power 
Trust IV ("Ridgewood Power IV") and Ridgewood Electric Power 
Trust V ("Ridgewood Power V") as Delaware business trusts to 
participate in the independent power industry.  The business 
objectives of these four trusts are similar to those of the 
Trust.

     The Managing Shareholder is an affiliate of Ridgewood Energy 
Corporation ("Ridgewood Energy"), which has organized and 
operated 46 limited partnership funds and one business trust over 
the last 12 years (of which 25 have terminated) and which had 
total capital contributions in excess of $190 million.  The 
programs operated by Ridgewood Energy have invested in oil and 
natural gas drilling and completion and other related activities.

     Robert E. Swanson has been the President, sole director and 
sole stockholder of the Managing Shareholder since its inception 
in February 1991.  Set forth below is certain information 
concerning Mr. Swanson and other executive officers of the 
Managing Shareholder.

     Robert E. Swanson, age 50, has also served as President of 
the Trust since its inception in November 1992 and as President 
of RPMC, Ridgewood Power I, Ridgewood Power II, Ridgewood Power 
IV and Ridgewood Power V, since their respective inceptions.  Mr. 
Swanson has been President, registered principal, sole director 
and sole stockholder of Ridgewood Securities Corporation, the 
Placement Agent for the private placement offerings of those four 
trusts.  In addition, he has been President, sole director and 
sole stockholder of Ridgewood Energy since its inception in 
October 1982.  Prior to forming Ridgewood Energy in 1982, Mr. 
Swanson was a tax partner at the former New York and Los Angeles 
law firm of Fulop & Hardee and an officer in the Trust and 
Investment Division of Morgan Guaranty Trust Company.  His 
specialty is in personal tax and financial planning, including 
income, estate and gift tax.  Mr. Swanson is a member of the New 
York State and New Jersey bars, the Association of the Bar of the 
City of New York and the New York State Bar Association.  He is a 
graduate of Amherst College and Fordham University Law School.  

     Robert L. Gold, age 38, has served as Executive Vice 
President of the Managing Shareholder, the Trust, Ridgewood Power 
I, Ridgewood Power II, Ridgewood Power IV and Ridgewood Power V 
since their respective inceptions, with primary responsibility 
for marketing and acquisitions.  He has served as Vice President 
and General Counsel of Ridgewood Securities Corporation since he 
joined the firm in December 1987.  Mr. Gold has also served as 
Executive Vice President of Ridgewood Energy since October 1990.  
He served as Vice President of Ridgewood Energy from December 
1987 through September 1990. For the two years prior to joining 
Ridgewood Energy and Ridgewood Securities Corporation, Mr. Gold 
was a corporate attorney in the law firm of Cleary, Gottlieb, 
Steen & Hamilton in New York City where his experience included 
mortgage finance, mergers and acquisitions, public offerings, 
tender offers, and other business legal matters. Mr. Gold is a 
member of the New York State bar.  He is a graduate of Colgate 
University and New York University School of Law.

     Thomas R. Brown, age 42, joined the Managing Shareholder in 
November 1994 as Senior Vice President and holds the same 
position with the Trust, RPMC and each of the other trusts 
sponsored by the Managing Shareholder.  He became Chief Operating 
Officer of the Managing Shareholder, RPMC, and the five trusts in 
October 1996.  Mr. Brown has over 19 years experience in the 
development and operation of power and industrial projects.  From 
1992 until joining the Managing Shareholder he was employed by 
Tampella Services, Inc., an affiliate of Tampella, Inc., one of 
the world's largest manufacturers of boilers and related 
equipment for the power industry.  Mr. Brown was Project Manager 
for Tampella's Piney Creek project, a $100 million bituminous 
waste coal fired circulating fluidized bed power plant.  Between 
1990 and 1992 Mr. Brown was Deputy Project Manager at Inter-Power 
of Pennsylvania, where he successfully developed a 106 megawatt 
coal fired facility.  Between 1982 and 1990 Mr. Brown was 
employed by Pennsylvania Electric Company, an integrated utility, 
as a Senior Thermal Performance Engineer.  Prior to that, Mr. 
Brown was an Engineer with Bethlehem Steel Corporation.  He has 
an Bachelor of Science degree in Mechanical Engineering from 
Pennsylvania State University and an MBA in Finance from the 
University of Pennsylvania.  Mr. Brown satisfied all requirements 
to earn the Professional Engineer designation in 1985.

     Martin V. Quinn, age 48, assumed the duties of Chief 
Financial Officer of the Managing Shareholder, the Trust, the 
other four trusts sponsored by the Managing Shareholder and RPMC 
in November 1996.  Under a consulting arrangement, Mr. Quinn 
devoted a majority of his time to the business of Ridgewood Power 
and RPMC while continuing his other activities, which concluded 
on March 31, 1997.  On that date, he became a full-time officer 
of Ridgewood Power and 
RPMC.  

     Mr. Quinn has 27 years of experience in financial management 
and corporate mergers and acquisitions, gained with major, 
publicly-traded companies and an international accounting firm.  
He formerly served as Vice President of Finance and Chief 
Financial Officer of NORSTAR Energy, an energy services company, 
from February 1994 until June 1996.  From 1991 to March 1993, Mr. 
Quinn was employed by Brown-Forman Corporation, a diversified 
consumer products company and distiller, where he was Vice 
President-Corporate Development.  From 1981 to 1991, Mr. Quinn 
held various officer-level positions with NERCO, Inc., a mining 
and natural resource company, including Vice President- 
Controller and Chief Accounting Officer for his last six years 
and Vice President-Corporate Development.  Mr. Quinn's 
professional qualifications include his certified public 
accountant qualification in New York State, membership in the 
American Institute of Certified Public Accountants, six years of 
experience with the international accounting firm of Price 
Waterhouse, and a Bachelor of Science degree in Accounting and 
Finance from the University of Scranton (1969).

     Mary Lou Olin, age 44, has served as Vice President of the 
Managing Shareholder, the Trust, RPMC, Ridgewood Power I, 
Ridgewood Power II and Ridgewood Power IV since their respective 
inceptions.  She has also served as Vice President of Ridgewood 
Energy since October 1984, when she joined the firm.  Her primary 
areas of responsibility are investor relations, communications 
and administration.  Prior to her employment at Ridgewood Energy, 
Ms. Olin was a Regional Administrator at McGraw-Hill Training 
Systems where she was employed for two years.  Prior to that, she 
was employed by RCA Corporation.  Ms. Olin has a Bachelor of Arts 
degree from Queens College.

     Donald C. Stewart, age 52, serves as an advisor and 
consultant to the Trust and is expected to be actively involved 
in reviewing the Trust's acquisitions and operations.  Mr. 
Stewart has 25 years of expertise in the field of independent 
power generation, fuel procurement, engineering and finance.  Mr. 
Stewart spent the first ten years of his business career as a 
certified public accountant with a major international firm.  He 
has been the Chairman of Vermont Gas Systems, a regulated public 
utility, President of Consolidated Power Company, a developer of 
large scale cogeneration projects and President of Hercules 
Engines, Inc., a manufacturer of industrial engines and 
electrical generation equipment. Mr. Stewart has a Bachelor of 
Science degree from Lehigh University. 

     Douglas R. Wilson, age 36, joined Mr. Stewart in October 
1996 to provide financial advisory services for evaluating, 
structuring and overseeing the Trust's investments.  He has over 
13 years of capital markets experience, including specialization 
in complex lease and project financings and in energy-related 
businesses.  From January 1993 until October 1996, he was 
associated with BTM Capital Corporation, the structured finance 
unit of the Bank of Tokyo-Mitsubishi.  Before that he earned a 
Master's degree in Business Administration from the Wharton 
School of the University of Pennsylvania from September 1990 
through May 1992.  He has a Bachelor of Business Administration 
degree from the University of Texas. 

 (c)  Management Agreement.

     The Trust has entered into a Management Agreement with the 
Managing Shareholder detailing how the Managing Shareholder will 
render management, administrative and investment advisory 
services to the Trust.  Specifically, the Managing Shareholder 
will perform (or arrange for the performance of) the management 
and administrative services required for the operation of the 
Trust.  Among other services, it will administer the accounts and 
handle relations with the Investors, provide the Trust with 
office space, equipment and facilities and other services 
necessary for its operation and conduct the Trust's relations 
with custodians, depositories, accountants, attorneys, brokers 
and dealers, corporate fiduciaries, insurers, banks and others, 
as required.  The Managing Shareholder will also be responsible 
for making investment and divestment decisions, subject to the 
provisions of the Declaration.

     The Managing Shareholder will be obligated to pay the 
compensation of the personnel and all administrative and service 
expenses necessary to perform the foregoing obligations.  The 
Trust will pay all other expenses of the Trust, including 
transaction expenses, valuation costs, expenses of preparing and 
printing periodic reports for Investors and the Commission, 
postage for Trust mailings, Commission fees, interest, taxes, 
legal, accounting and consulting fees, litigation expenses and 
other expenses properly payable by the Trust.  The Trust will 
reimburse the Managing Shareholder for all such Trust expenses 
paid by it.

     As compensation for the Managing Shareholder's performance 
under the Management Agreement, the Trust is obligated to pay the 
Managing Shareholder an annual management fee described below at 
Item 13 -- Certain Relationships and Related Transactions.

     The Board of the Trust (including both initial Independent 
Trustees) have approved the initial Management Agreement and its 
renewals.  Each Investor consented to the terms and conditions of 
the initial Management Agreement by subscribing to acquire 
Investor Shares in the Trust.  The Management Agreement will 
remain in effect until January 4, 1998 and year to year 
thereafter as long as it is approved at least annually by (i) 
either the Board of the Trust or a majority in interest of the 
Investors and (ii) a majority of the Independent Trustees.  The 
agreement is subject to termination at any time on 60 days' prior 
notice by the Board, a majority in interest of the Investors or 
the Managing Shareholder.  The agreement is subject to amendment 
by the parties with the approval of (i) either the Board or a 
majority in interest of the Investors and (ii) a majority of the 
Independent Trustees.

(d)  Executive Officers of the Trust.

     Pursuant to the Declaration, the Managing Shareholder has 
appointed officers of the Trust to act on behalf of the Trust and 
sign documents on behalf of the Trust as authorized by the 
Managing Shareholder.  Mr. Swanson has been named the President 
of the Trust and the other principal officers of the Trust are 
identical to those of the Managing Shareholder.  The officers 
have the duties and powers usually applicable to similar officers 
of a Delaware business corporation in carrying out Trust 
business.  Officers act under the supervision and control of the 
Managing Shareholder, which is entitled to remove any officer at 
any time.  Unless otherwise specified by the Managing 
Shareholder, the President of the Trust has full power to act on 
behalf of the Trust.  The Managing Shareholder expects that most 
actions taken in the name of the Trust will be taken by Mr. 
Swanson and the other principal officers in their capacities as 
officers of the Trust under the direction of the Managing 
Shareholder rather than as officers of the Managing Shareholder.

(e)  The Trustees.

     The 1940 Act requires the Independent Trustees to be 
individuals who are not "interested persons" of the Trust as 
defined under the 1940 Act (generally, persons who are not 
affiliated with the Trust or with affiliates of the Trust).  
There must always be at least two Independent Trustees; a larger 
number may be specified by the Board from time to time.  Each 
Independent Trustee has an indefinite term.  Vacancies in the 
authorized number of Independent Trustees will be filled by vote 
of the remaining Board members so long as there is at least one 
Independent Trustee; otherwise, the Managing Shareholder must 
call a special meeting of Investors to elect Independent 
Trustees.  Vacancies must be filled within 90 days.  An 
Independent Trustee may resign effective on the designation of a 
successor and may be removed for cause by at least two-thirds of 
the remaining Board members or with or without cause by action of 
the holders of at least two-thirds of Shares held by Investors.  
Under the Declaration, the Independent Trustees are authorized to 
act only where their consent is required under the 1940 Act and 
to exercise a general power to review and oversee the Managing 
Shareholder's other actions.  They are under a fiduciary duty 
similar to that of corporation directors to act in the Trust's 
best interest and are entitled to compel action by the Managing 
Shareholder to carry out that duty, if necessary, but ordinarily 
they have no duty to manage or direct the management of the Trust 
outside their enumerated responsibilities.

     The Independent Trustees of the Trust are Ralph O. Hellmold 
and Jonathan C. Kaledin.  Set forth below is certain information 
concerning Mr. Hellmold and Mr. Kaledin, who also serve as 
independent trustees of Ridgewood Power II, an independent power 
program sponsored by Ridgewood Power.  Neither Mr. Hellmold nor 
Mr. Kaledin is otherwise affiliated with the Trust, any of the 
Trust's officers or agents, Ridgewood Power, any other Trustee, 
any affiliates of the Managing Shareholder and any other 
Trustees, or any director, officer or agent of any of the 
foregoing.

     Ralph O. Hellmold, age 56, is founder, sole shareholder and 
President of Hellmold Associates, Inc., an investment banking 
firm, broker-dealer and investment adviser specializing in 
working with troubled companies or their creditors to raise 
capital, divest businesses and restructure liabilities, whether 
in or outside bankruptcy.  Other financial advisory services 
provided by Hellmold Associates, Inc. include mergers and 
acquisitions advice, valuations, fairness opinions and expert 
witness testimony.  In addition to working with troubled 
companies or their creditors, Hellmold Associates, Inc. also acts 
as general partner of funds which invest in the securities of 
financially distressed companies.  Mr. Hellmold is also a 
director of Core Materials Corp., Columbus, Ohio.

     From 1987 to 1990, when he formed Hellmold Associates, Inc., 
Mr. Hellmold was a Managing Director at Prudential-Bache Capital 
Funding, where he served as co-head of the Corporate Finance 
Group, co-head of the Investment Banking Committee and head of 
the Financial Restructuring Group.  From 1974 to 1987, Mr. 
Hellmold was a partner at Lehman Brothers and its successors, 
where he worked in the General Corporate Finance Group and 
co-founded the Financial Restructuring Group.  Prior thereto, he 
was a research analyst at Lehman Brothers and at Francis I. du 
Pont & Company.  He received his undergraduate degree magna cum 
laude from Harvard College and an M.I.A. from Columbia 
University.  He is a Chartered Financial Analyst and a member of 
the New York Society of Security Analysts.  Mr. Hellmold is the 
holder of one-half share each in Ridgewood Power I and Ridgewood 
Power II, a shareholder of one-half Share in the Trust and a 
limited partner or shareholder in numerous limited partnerships 
and a business trust sponsored by Ridgewood Energy to invest in 
oil and gas development and related businesses.  

     Jonathan C. Kaledin, age 38, has been New York Regional 
Counsel of The Nature Conservancy, the international land 
conservation organization, since September 1995.  From 1990 to 
June 1995, he was founder and Executive Director of the National 
Water Funding 
Council ("NWFC"), an advocacy and public affairs organization 
representing municipalities, businesses, financial institutions 
and others on federal Clean Water Act and Safe Drinking Water Act 
funding issues.  Prior to forming the NWFC in 1990, Mr. Kaledin 
was an attorney with the Boston law firm of Wright & Moehrke.  
There he specialized in wetlands, water, environmental review, 
zoning and hazardous and solid waste matters, representing 
clients in state and federal court and before state and federal 
agencies and local boards and commissions.  From 1987 through 
1990, Mr. Kaledin was Assistant Regional Counsel for the New 
England office of the Environmental Protection Agency ("EPA").  
His responsibilities at the EPA included administrative and 
judicial environmental enforcement under the Clean Water Act and 
other federal water protection legislation.  Mr. Kaledin received 
his undergraduate degree magna cum laude from Harvard College and 
a law degree from New York University.  

     The Corporate Trustee of the Trust is Ridgewood Energy 
Holding Corporation.  Legal title to Trust Property is now and in 
the future will be in the name of the Trust, if possible, or 
Ridgewood Energy Holding Corporation as trustee.  Ridgewood 
Energy Holding Corporation is also a trustee of Ridgewood Power 
I, Ridgewood Power II, Ridgewood Power IV and of an oil and gas 
business trust sponsored by Ridgewood and is expected to be a 
trustee of other similar entities that may be organized by the 
Managing Shareholder and Ridgewood Energy.  The President, sole 
director and sole stockholder of Ridgewood Energy Holding 
Corporation is Robert E. Swanson; its other executive officers 
are identical to those of the Managing Shareholder. The principal 
office of Ridgewood Energy Holding Corporation is at 1105 North 
Market Street, Suite 1300, Wilmington, Delaware 19899.

     The Trustees are not liable to persons other than 
Shareholders for the obligations of the Trust.

     The Trust has relied and will continue to rely on the 
Managing Shareholder and engineering, legal, investment banking 
and other professional consultants (as needed) and to monitor and 
report to the Trust concerning the operations of Projects in 
which it invests, to review proposals for additional development 
or financing, and to represent the Trust's interests.  The Trust 
will rely on such persons to review proposals to sell its 
interests in Projects in the future.

(f)  Section 16(a) Beneficial Ownership Reporting Compliance

     Each of the Independent Trustees and executive officers of 
the Trust did not file on a timely basis as 
required by section 16(a) of the 1934 Act Forms 3 reporting their 
status as officers or directors of the Trust and their beneficial 
ownership.  Mr. Quinn and Mr. Brown each made one late filing of 
Form 3 in December 1996 and each of the others made one late 
filing in April 1997.  The number of transactions that were not 
reported on a timely basis by each of these persons was zero.

(g) RPMC.

     As discussed above at Item 1 -- Business, RPMC has assumed 
day-to-day management responsibility for all of the Trust's 
Projects, effective January 1, 1996.  Like the Managing 
Shareholder, RPMC is wholly owned by Robert E. Swanson.  It has 
entered into an "Operation Agreement" with certain of the Trust's 
subsidiaries, effective January 1, 1996, under which RPMC, under 
the supervision of the Managing Shareholder, will provide the 
management, purchasing, engineering, planning and administrative 
services for those Projects that were previously furnished by 
employees of the Trust or by unaffiliated professionals or 
consultants and that were borne by the Trust as operating 
expenses, as well as billing, payment and other Project-level 
accounting and service costs.  To the extent that those services 
were provided by the Managing Shareholder and related directly to 
the operation of the Project, RPMC will charge the Trust at its 
cost for these services and for the Trust's allocable amount of 
certain overhead items. RPMC will share space and facilities with 
the Managing Shareholder and its Affiliates. To the extent that 
common expenses can be reasonably allocated to RPMC, the Managing 
Shareholder may, but is not required to, charge RPMC at cost for 
the allocated amounts and such allocated amounts will be borne by 
the Trust and other programs.  Common expenses that are not so 
allocated will be borne by the Managing Shareholder.  

     Initially, the Managing Shareholder does not anticipate 
charging RPMC for the full amount of rent, utility supplies and 
office expenses allocable to RPMC.  As a result, both initially 
and on an ongoing basis the Managing Shareholder believes that 
RPMC's charges for its services to the Trust are likely to be 
materially less than its economic costs and the costs of engaging 
comparable third persons as managers.  RPMC will not receive any 
compensation in excess of its costs.

     Allocations of costs will be made either on the basis of 
identifiable direct costs, time records or in proportion to each 
program's investments in Projects managed by RPMC, and 
allocations will be made in a manner consistent with generally 
accepted accounting principles.

     RPMC will not provide any services related to the 
administration of the Trust, such as investment, accounting, tax, 
investor communication or regulatory services, nor will it 
participate in identifying, acquiring or disposing of Projects.  
RPMC will not have the power to act in the Trust's name or to 
bind the Trust, which will be exercised by the Managing 
Shareholder or the Trust's officers, although it may be 
authorized to act on behalf of the subsidiaries that own 
Projects.

     The Operation Agreement does not have a fixed term and is 
terminable by RPMC, by the Managing Shareholder or by vote of a 
majority of interest of Investors, on 60 days' prior notice. The 
Operation Agreement may be amended by agreement of the Managing 
Shareholder and RPMC; however, no amendment that materially 
increases the obligations of the Trust or that materially 
decreases the obligations of RPMC  shall become effective until 
at least 45 days after notice of the amendment, together with the 
text thereof, has been given to all Investors. 

     The principal officers of RPMC are Mr. Swanson (President), 
Mr. Gold (Executive Vice President), Mr. Brown (Senior Vice 
President and Chief Operating Officer), Mr. Quinn (Senior Vice 
President and Chief Financial Officer), Ms. Olin (Vice 
President), Joseph A. Heyison, General Counsel, and Douglas V. 
Liebschner, Vice President - Operations.  Mr. Heyison, age 42, 
joined RPMC in January 1996.  He was previously of counsel to the 
law firm of De Forest & Duer, concentrating in corporate finance, 
banking, environmental law and securities.  He is a member of the 
bars of New Jersey, New York and Ohio and was graduated from the 
University of Pennsylvania Law School in 1979.

     Douglas V. Liebschner, age 50, joined RPMC in June 1996 as 
Vice President of Operations.  He has over 27 years of experience 
in the operation and maintenance of power plants.  From 1992 
until joining RPMC, he was employed by Tampella Services, Inc., 
an affiliate of Tampella, Inc., one of the world's largest 
manufacturers of boilers and related equipment for the power 
industry.  Mr. Liebschner was Operations Supervisor for 
Tampella's Piney Creek project, a $100 million bituminous waste 
coal fired circulating fluidized bed (CFB) power plant.  Between 
1989 and 1992, he supervised operations of a waste to energy 
plant in Poughkeepsie, N.Y. and an anthracite waste coal burning 
CFB in Frackville, Pa.  From 1969 to 1989, Mr. Liebschner served 
in the U.S. Navy, retiring with the rank of Lieutenant Commander.  
While in the Navy, he served mainly in billets dealing with the 
operation, maintenance and repair of ship propulsion plants, 
twice serving as Chief Engineer on board U.S. Navy combatant 
ships.  He has a Bachelor of Science degree from the U.S. Naval 
Academy, Annapolis, Md.

Item 11.  Executive Compensation.

     Through 1995, the executive officers of the Trust and the 
Managing Shareholder were compensated by Ridgewood Energy.  The 
Trust was not charged for their compensation; the Managing 
Shareholder remitted a portion of the fees paid to it by the 
Trust to reimburse Ridgewood Energy for employment costs incurred 
on the Managing Shareholder's business.  In 1996 and future 
years, the Managing Shareholder will compensate these persons 
without additional payments by the Trust and will be reimbursed 
by Ridgewood Energy for costs related to Ridgewood Energy's 
business.  The Trust will reimburse RPMC at cost for services 
provided by RPMC's employees.  Information as to the fees payable 
to the Managing Shareholder and certain affiliates is contained 
at Item 13.  Certain Relationships and Related Transactions.

     As compensation for services rendered to the Trust, pursuant 
to the Declaration, each Independent Trustee is entitled to be 
paid by the Trust the sum of $5,000 annually and to be reimbursed 
for all reasonable out-of-pocket expenses relating to attendance 
at Board meetings or otherwise performing his duties to the 
Trust.  Accordingly, in January 1995 and following years, the 
Trust paid each Independent Trustee $5,000 for his services.  The 
Board of the Trust is entitled to review the compensation payable 
to the Independent Trustees annually and increase or decrease it 
as the Board sees reasonable.  The Trust is not entitled to pay 
the Independent Trustees compensation for consulting services 
rendered to the Trust outside the scope of their duties to the 
Trust without prior Board approval.

     Ridgewood Energy Holding Corporation, the Corporate Trustee 
of the Trust, is not entitled to compensation for serving in such 
capacity, but is entitled to be reimbursed for Trust expenses 
incurred by it which are properly reimbursable under the 
Declaration.


Item 12.  Security Ownership of Certain Beneficial Owners and
Management.

     The Trust sold 391.8444 Investor Shares (approximately $39.2 
million of gross proceeds) of beneficial interest in the Trust 
pursuant to a private placement offering under Rule 506 of 
Regulation D under the Securities Act.  The offering closed on 
May 31, 1995.  Further details concerning the offering are set 
forth above at Item 1 -- Business.

     The Managing Shareholder purchased for cash in the offering 
one full Investor Share.  Ralph O. Hellmold, an Independent 
Trustee of the Trust, purchased for cash in the offering one-half 
of a full Investor Share.  By virtue of their purchase of 
Investor Shares, the Managing Shareholder and Mr. Hellmold are 
entitled to the same ratable interest in the Trust as all other 
purchasers of Investor Shares.  No other Trustees or executive 
officers of the Trust acquired Investor Shares in the Trust's 
offering.

     The Managing Shareholder was issued one Management Share in 
the Trust representing the beneficial interests and management 
rights of the Managing Shareholder in its capacity as the 
Managing Shareholder (excluding its interest in the Trust 
attributable to Investor Shares it acquired in the offering).  
The management rights of the Managing Shareholder are described 
in further detail above at Item 1 -- Business and in Item 10 - 
Directors and Executive Officers of the Registrant.  Its 
beneficial interest in cash distributions of the Trust and its 
allocable share of the Trust's net profits and net losses and 
other items attributable to the Management Share are described in 
further detail below at Item 13 -- Certain Relationships and 
Related Transactions..

Item 13.  Certain Relationships and Related Transactions.

     The Declaration provides that cash flow of the Trust, less 
reasonable reserves which the Trust deems necessary to cover 
anticipated Trust expenses, is to be distributed to the Investors 
and the Managing Shareholder (collectively, the "Shareholders"), 
from time to time as the Trust deems appropriate.  Prior to 
Payout (the point at which Investors have received cumulative 
distributions equal to the amount of their capital 
contributions), each year all distributions from the Trust, other 
than distributions of the revenues from dispositions of Trust 
Property, are to be allocated 99% to the Investors and 1% to the 
Managing Shareholder until Investors have been distributed during 
the year an amount equal to 14% of their total capital 
contributions (a "14% Priority Distribution"), and thereafter all 
remaining distributions from the Trust during the year, other 
than distributions of the revenues from dispositions of Trust 
Property, are to be allocated 80% to Investors and 20% to the 
Managing Shareholder.  Revenues from dispositions of Trust 
Property are to be distributed 99% to Investors and 1% to the 
Managing Shareholder until Payout.  In all cases, after Payout, 
Investors are to be allocated 80% of all distributions and the 
Managing Shareholder 20%.    

     For any fiscal period, the Trust's net profits, if any, 
other than those derived from dispositions of Trust Property, are 
allocated 99% to the Investors and 1% to the Managing Shareholder 
until the profits so allocated offset (1) the aggregate 14% 
Priority Distribution to all Investors and (2) any net losses 
from prior periods that had been allocated to the Shareholders.  
Any remaining net profits, other than those derived from 
dispositions of Trust Property, are allocated 80% to the 
Investors and 20% to the Managing Shareholder.  If the Trust 
realizes net losses for the period, the losses are allocated 80% 
to the Investors and 20% to the Managing Shareholder until the 
losses so allocated offset any net profits from prior periods 
allocated to the Shareholders.  Any remaining net losses are 
allocated 99% to the Investors and 1% to the Managing 
Shareholder.  Revenues from dispositions of Trust Property are 
allocated in the same manner as distributions from such 
dispositions.  Amounts allocated to the Investors are apportioned 
among them in proportion to their capital contributions. 

     On liquidation of the Trust, the remaining assets of the 
Trust after discharge of its obligations, including any loans 
owed by the Trust to the Shareholders, will be distributed, 
first, 99% to the Investors and the remaining 1% to the Managing 
Shareholder, until Payout, and any remainder will be distributed 
to the Shareholders in proportion to their capital accounts.

     The Trust did not make any distributions in 1994 to the 
Managing Shareholder (which is a member of the Board of the 
Trust) or any other person and made distributions in 1995 and 
1996 as stated at Item 5 -- Market for Registrant's Common Equity 
and Related Stockholder Matters.  The Trust paid fees to the 
Managing Shareholder and its affiliates as follows:

Fee                 Paid to         1996         1995           1994

Management         Managing      $794,026    $482,000             $0
 fee              Shareholder

Cost
 reimbursements*    RPMC       11,566,400           0              0

Investment         Managing             0     343,779        421,011
 fee              Shareholder

Placement          Ridgewood            0     147,950        188,847
 agent fee        Securities
 and sales        Corporation
 commissions

Organizational,    Managing             0     860,195      1,088,727
distribution      Shareholder
 and offering
 fee

* Prior to 1996, these costs were either paid by the Trust or by the Projects 
directly.  These include all payroll, parts, routine maintenance and other 
expenses (except for royalties for landfill gas) of operating Projects that 
are not operated by non-affiliated managers, and an allocation of RPMC's
overhead.


     The investment fee equaled 2% of the proceeds of the 
offering of Investor Shares and was payable for the Managing 
Shareholder's services in investigating and evaluating investment 
opportunities and effecting investment transactions.  The 
placement agent fee (1% of the offering proceeds) and sales 
commissions were also paid from proceeds of the offering, as was 
the organizational, distribution and offering fee (5% of offering 
proceeds) for legal, accounting, consulting, filing, printing, 
distribution, selling, closing and organization costs of the 
offering.

     The management fee, payable monthly under the Management 
Agreement at the annual rate of 2.5% of the Trust's net asset 
value, began on the date the first Project was acquired and 
compensates the Managing Shareholder for certain management, 
administrative and advisory services for the Trust.  In addition 
to the foregoing, the Trust reimbursed the Managing Shareholder 
at cost for expenses and fees of unaffiliated persons engaged by 
the Managing Shareholder for Trust business and in 1995 for 
payroll and other costs of operation of the Trust's Projects.  
Beginning in 1996, these reimbursements were paid to RPMC.  The 
reimbursements to RPMC, which do not exceed its actual costs, are 
described at Item 10(f) -- Directors and Executive Officers of the 
Registrant -- RPMC.

     Other information in response to this item is reported in 
response to Item 11.  Executive Compensation, which information 
is incorporated by reference into this Item 13.

PART IV

Item 14.  Exhibits, Financial Statement Schedules, and Reports on 
Form 8-K.

(a)  Financial Statements.

     See the Index to Financial Statements in Item 8 hereof.

(b)  Reports on Form 8-K.

     No Forms 8-K were filed with the Commission by the 
Registrant during the quarter ending December 31, 1996.

(c)  Exhibits

     3A.   Certificate of Trust of the Registrant is incorporated 
           by reference to Exhibit 3A of Registrant's 
           Registration Statement filed with the Commission on 
           February 15, 1994.

     3B.   Declaration of Trust of the Registrant is incorporated 
           by reference to Exhibit 3B of Registrant's 
           Registration Statement filed with the Commission on 
           February 19, 1994.

     10A.  Management Agreement dated as of January 3, 1994 
           between the Registrant and Ridgewood Power Corporation 
           is incorporated by reference to Exhibit 10A of 
           Registrant's Registration Statement filed with the 
           Commission on February 15, 1994.

     10B.  Acquisition Agreement dated as of January 9, 1995 
           among JRW Cogen, Inc., and NorCal Cogen, Inc., as 
           Sellers, and RW Central Valley, Inc., and Ridgewood 
           Electric Power Trust III, as Purchasers, is 
           incorporated by reference to Exhibit 2(i) to 
           Registrant's Form 8K filed with the Commission on 
           February 16, 1995.

     10C.  Agreement of Merger dated as of January 9, 1995 among 
           Altamont Cogeneration Corporation, NorCal Altamont, 
           Inc., and Byron Power Partners, L.P. is incorporated 
           by reference to Exhibit 2(ii) to Registrant's Form 8K 
           filed with the Commission on February 16, 1995.

     10.D  Asset Acquisition Agreement by and 
           among Northeast Landfill Power  Joint Venture,
           Northeast Landfill Power Company, Johnson 
           Natural Power Corporation and Ridgewood 
           Providence Power Partners, L.P. , is incorporated by 
           reference to Exhibit 2 of the Registrant's Current
           Report on Form 8-K filed with the Commission on
           May 2, 1996.

     10.E  Operation Agreement, dated as of April 16, 
           1996, among Ridgewood/Providence Corporation, 
           Ridgewood/Providence Power Partners, L.P. and 
           Ridgewood Power Management Corporation     Page 75

     The Registrant agrees to furnish supplementally a copy of 
any omitted exhibit or schedule to agreements filed as exhibits 
to the Commission upon request.

     21.   Subsidiaries of the Registrant.  Incorporated by 
           reference to Exhibit 21 of the Registrant's Annual 
           Report on Form 10-K for the year ended December 31, 
           1995.

     24.   Powers of Attorney                         Page 81

     27.   Financial Data Schedule                    Page 82

<PAGE>








SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the 
Securities Exchange Act of 1934, the Registrant has duly caused 
this report to be signed on its behalf by the undersigned, 
thereunto duly authorized.

Signature                      Title                        Date

RIDGEWOOD ELECTRIC POWER TRUST III
 (Registrant)

By:/s/ Robert E. Swanson    President and Chief    April 14, 1997
       Robert E. Swanson     Executive Officer

   
     Pursuant to the requirements of the Securities Exchange Act of 
1934, this report has been signed below by the following persons on 
behalf of the Registrant and in the capacities and on the dates 
indicated.


By:/s/ Robert E. Swanson    President and Chief    April 14, 1997
       Robert E. Swanson     Executive Officer

By:/s/ Martin V. Quinn      Senior Vice President and
       Martin V. Quinn   Chief Financial Officer   April 15, 1997

By:/s/ Kathleen P. McSherry     Controller         April 15, 1997
       Kathleen P. McSherry

RIDGEWOOD POWER CORPORATION  Managing Shareholder  April 14, 1997

By:/s/ Robert E. Swanson       President
       Robert E. Swanson

        
/s/ Robert E. Swanson  *      Independent Trustee  April 14, 1997
Ralph O. Hellmold 

/s/ Robert E. Swanson  *      Independent Trustee  April 14, 1997
Jonathan C. Kaledin 

*  As attorney-in-fact for the Independent Trustee

<PAGE>













Ridgewood Electric Power Trust III

Financial Statements

December 31, 1996, 1995 and 1994




















                             -F1-

<PAGE>
1177 Avenue of the Americas         Telephone 212 596 7000
New York, NY 10036                  Facsimile 212 596 8910
[Letterhead of Price Waterhouse LLP]

Report of Independent Accountants

March 24, 1997

To the Shareholders and Trustees of 
Ridgewood Electric Power Trust III

In our opinion, the accompanying balance sheet and the related 
statements of operations, changes in shareholders' equity and of 
cash flows present fairly, in all material respects, the 
financial position of Ridgewood Electric Power Trust III at 
December 31, 1996 and 1995, and the results of its operations and 
its cash flows for each of the two years in the period ended 
December 31, 1996 and the period January 3, 1994 (commencement of 
share offering) through December 31, 1994, in conformity with 
generally accepted accounting principles.  These financial 
statements are the responsibility of the Trust's management; our 
responsibility is to express an opinion on these financial 
statements based on our audits.  We conducted our audits of these 
statements in accordance with generally accepted auditing 
standards which require that we plan and perform the audit to 
obtain reasonable assurance about whether the financial 
statements are free of material misstatement.  An audit includes 
examining, on a test basis, evidence supporting the amounts and 
disclosures in the financial statements, assessing the accounting 
principles used and significant estimates made by management, and 
evaluating the overall financial statement presentation.  We 
believe that our audits provide a reasonable basis for the 
opinion expressed above.

As explained in Note 3, the financial statements include 
investments, valued at $28,050,750 and %20,884,493 (89% and 64% 
of shareholders' equity, respectively) as of December 31, 1996 
and 1995, respectively, whose values have been estimated by 
management in the absence of readily ascertainable market values.  
We have reviewed the procedures used by management in arriving at 
their estimate of value and have inspected underlying 
documentation, and, in the circumstances, we believe the 
procedures are reasonable and the documentation appropriate.  
However, because of the inherent uncertainty of valuation, those 
estimated values may differ significantly from the values that 
would have been used had a ready market for the investments 
existed, and the differences could be material to the financial 
statements.

/s/  Price Waterhouse LLP

                           -F2-
<PAGE>

Ridgewood Electric Power Trust III
Statement of Operations


                                                                 Commencement
                                                                     of Share
                                                                     Offering
                                                             (January 3, 1994)
                               Year Ended         Year Ended          Through
                             December 31,       December 31,     December 31,
                                     1996               1995             1994
Revenue:
 Income from power
  generation projects        $  3,525,613       $  1,317,287     $        ---
 Interest and dividend
  income                          247,762          1,059,570          259,911
                                3,773,375          2,376,857          259,911
               
Expenses:               
 Investment fee                       ---            343,779          421,011
 Project due diligence
  costs                           258,378              8,210           25,105
 Management fee                   794,026            482,309              ---
 Accounting and legal fees         48,231             90,043           16,199
 Miscellaneous                     18,012             11,966           10,895
 Writedown of limited
  partnership investments         113,042                ---              ---
                                1,231,689            936,307          473,210
               
               
    Net income (loss)        $  2,541,686       $  1,440,550      $  (213,299)

Allocation to:               
 Shareholders                $  2,516,269       $  1,426,145      $  (211,166)
 Managing shareholder              25,417             14,405           (2,133)
                             $  2,541,686       $  1,440,550      $  (213,299)
               

See accompanying notes to financial statements.

                                -F3-

<PAGE>
Ridgewood Electric Power Trust III
Balance Sheet

                                                            December 31,
                                                     1996                1995
               
Assets:
Investments in power generation projects    $  28,050,750       $  20,884,493
Cash and cash equivalents                       2,959,240          10,972,576
Due from affiliates                               109,085             299,194
Deferred due diligence costs                       30,000             303,213
Interest receivable                                   ---              51,233
Other assets                                      281,000             140,959
               
    Total assets                            $  31,430,075       $  32,651,668
               
               
               
               
Liabilities and Shareholders' Equity:               
               
Accounts payable and accrued expenses         $    41,136       $      72,442
               
               
               
Shareholders' equity:               
Shareholders' equity
 (391.8444 shares issued
 and outstanding)                              31,406,084          32,584,476
Managing shareholder's
 accumulated deficit                              (17,145)             (5,250)
               
    Total shareholders' equity                 31,388,939          32,579,226
               
    Total liabilities and
     shareholders' equity                   $  31,430,075       $  32,651,668
               
               






See accompanying notes to financial statements.

                               -F4-
<PAGE>

Ridgewood Electric Power Trust III
Statement of Changes in Shareholders' Equity

                                                    Managing     
                             Shareholders        Shareholder            Total

Initial capital
 contributions, net
 (220.7053 shares)           $ 18,484,655     $          ---    $  18,484,655
               
Net loss for the period          (211,166)            (2,133)        (213,299)
                     
Shareholders' equity,
 December 31, 1994               
  (220.7053 shares)            18,273,489             (2,133)      18,271,356
               
Capital contributions,
 net (171.1391 shares)         15,195,000                ---       15,195,000
               
Cash distributions             (2,310,158)           (17,522)      (2,327,680)
                  
Net income for the year         1,426,145             14,405        1,440,550
                  
Shareholders' equity,
 December 31, 1995               
 (391.8444 shares)             32,584,476             (5,250)      32,579,226
               
Cash distributions             (3,694,661)           (37,312)      (3,731,973)
               
Net income for the year         2,516,269             25,417        2,541,686
               
Shareholders' equity,
 December 31, 1996               
 (391.8444 shares)           $ 31,406,084     $      (17,145)   $  31,388,939









See accompanying notes to financial statements.


                             -F5-
<PAGE>

Ridgewood Electric Power Trust III
Statement of Cash Flows
                                                                 Commencement
                                                                     of Share
                                                                     Offering
                                                             (January 3, 1994)
                               Year Ended         Year Ended          Through
                             December 31,       December 31,     December 31,
                                     1996               1995             1994
Cash flows from
 operating activities:
  Net income (loss)         $   2,541,686      $   1,440,550    $    (213,299)
                  
Adjustment to reconcile
 net income (loss) to net
 cash used in operating
 activities:                
  Writedown of limited
   partnership investments        113,042                ---              ---
  Purchase of investments
   in power generation
   projects                    (7,279,299)       (20,884,493)             ---
  Proceeds from transfer of
   investment                     353,619                ---              ---

Changes in assets
 and liabilities:               
  Increase in
   due from affiliates           (109,085)          (299,194)             ---
  Decrease (increase) in
   deferred due diligence costs   273,213           (140,683)        (162,530)
  Decrease (increase) in
   interest receivable             51,233            (51,233)             ---
  Increase in other assets       (140,041)          (135,959)          (5,000)
  (Decrease) increase in
   accounts payable and 
   accrued expenses               (85,731)           (61,347)         133,789
               
Total adjustments              (6,823,049)       (21,572,909)         (33,741)
                  
Net cash used in operating
 activities                    (4,281,363)       (20,132,359)        (247,040)
                             
Cash flows provided by
 financing activities:               
  Proceeds from shareholders'
   contributions                      ---         17,527,545       21,499,170
  Selling commissions and
   distribution and offering 
   costs paid                         ---         (2,332,545)      (3,014,515)
  Cash distributions to
   shareholders                (3,731,973)        (2,327,680)             ---
                                    -F6-
<PAGE>
Net cash provided by
 (used in) financing
 activities                    (3,731,973)        12,867,320       18,484,655
               
Net (decrease) increase in
 cash and cash equivalents     (8,013,336)        (7,265,039)      18,237,615
               
Cash and cash equivalents,
 beginning of period           10,972,576         18,237,615              ---
               
Cash and cash equivalents,
 end of period              $   2,959,240      $  10,972,576    $  18,237,615
               
                              
See accompanying notes to financial statements.

                                 -F7-

<PAGE


Ridgewood Electric Power Trust III
Notes to Financial Statements

1.  Organization and Purpose

Nature of business

     Ridgewood Electric Power Trust III (the "Trust") was formed 
as a Delaware business trust on December 6, 1993, by Ridgewood 
Energy Holding Corporation acting as the Corporate Trustee.  The 
managing shareholder of the Trust is Ridgewood Power Corporation.  
The Trust began offering shares on January 3, 1994.  The Trust 
commenced operations on April 16, 1994, and discontinued its 
offering of Trust shares on  May 31, 1995.

     The Trust has been organized to invest in independent power 
generation facilities and in the development of these facilities.  
These independent power generation facilities include 
cogeneration facilities, which produce both electricity and 
thermal energy, and other power plants that use various fuel 
sources (except nuclear).  The power plants sell electricity and 
thermal energy to utilities and industrial users under long-term 
contracts.

"Business Development Company" election

     Effective April 16, 1994, the Trust elected to be treated as 
a "Business Development Company" under the Investment Company Act 
of 1940 and registered its shares under the Securities Exchange 
Act of 1934.

2.  Summary of Significant Accounting Policies

Use of Estimates

     The preparation of the financial statements in conformity 
with generally accepted accounting principles requires management 
to make estimates and assumptions that affect the reported 
amounts of assets and liabilities, and disclosure of contingent 
assets and liabilities at the date of the financial statements 
and the reported amounts of revenues and expenses during the 
reporting period.  Actual results could differ from the 
estimates.

Investments in power generation projects

     The Trust holds investments in power generating projects, 
which are stated at fair value.  Due to the non-liquid nature of 
the investments, the fair values of the investments are assumed 
to equal cost unless current available information provides a 
basis for adjusting the carrying value of the investments.

Revenue Recognition

     Income from investments is recorded when received.  Interest 
and dividend income are recorded as earned.

Offering costs

     Costs associated with offering Trust shares (selling 
commissions, distribution and offering costs) are recorded as a 
reduction of the shareholders' capital contributions.

Cash and Cash equivalents

     The Trust considers all highly liquid investments with 
original maturities of three months or less as cash and cash 
equivalents.

                               -F8-


<PAGE>


Ridgewood Electric Power Trust III
Notes to Financial Statements

Due diligence costs relating to potential power project 
investments

     Costs relating to the due diligence performed on potential 
power project investments, are initially deferred, until such 
time as the Trust determines whether or not it will make an 
investment in the respective project.  Costs relating to 
completed projects are capitalized and costs relating to rejected 
projects are expensed at the time of rejection.

Income taxes

     No provision is made for income taxes in the accompanying 
financial statements as the income or losses of the Trust are 
passed through and included in the tax returns of the individual 
shareholders of the Trusts. 

Reclassification

     Certain items in previously issued financial statements have 
been reclassified for comparative purposes.

3.  Investments in Power Generation Projects

     The Trust had the following investments in power generation 
projects:

                                                   Fair values as of December 
31,

                                                     1996                 1995

Power generation projects:            
 JRW Associates, L.P.                       $   5,305,298       $    5,305,298
 Byron Power Partners, L.P.                     3,138,072            2,958,072
 Ridgewood Providence Power
  Partners, L.P.                                7,130,000                  ---
 On-site Cogeneration Projects:
  Ridgewood/Rhode Island PPLP                   3,722,618            3,722,618
  Ridgewood/Mass. PPLP                          3,223,881            3,223,881
  Ridgewood/Elmsford PPLP                       1,430,136            1,430,136
  Other On-site Cogeneration
   Project Partnerships                         4,100,745            4,244,488
                                            $  28,050,750        $  20,884,493


JRW Associates, L.P. (known as San Joaquin Power Company)

     On January 17, 1995, the Trust acquired 100% of the existing 
partnership interests of JRW Associates, L.P., which owns and 
operates an 8.5 megawatt electric cogeneration facility, located 
in Atwater, California.  The aggregate cost of the investment was 
$5,305,298.  The Trust received distributions of $779,409 and 
$982,076 from the project in 1996 and 1995, respectively.

Byron Power Partners, L.P. (known as Byron Power Company)

     In January 1995, the Trust caused the formation of Byron 
Power Partners, L.P. in which the Trust owns 100% of the existing 
partnership interests.  On January 17, 1995, Byron Power 
Partners, L.P. acquired a 5.7 megawatt electric cogeneration 
facility, located in Byron, California.  As of December 31, 1996 
and 1995, the Trust's investment in the partnership was 
$3,138,072 and $2,958,072, respectively.  The Trust received 
distributions of $428,540 and $335,211 from the project in 1996 
and 1995, respectively.

                              -F9-
<PAGE>

Ridgewood Electric Power Trust III
Notes to Financial Statements

Providence Project

     In 1996, Ridgewood Providence Power Partners, L.P. was 
formed as a Delaware limited partnership ("Providence Power").  
The Trust invested $7,058,700 and owns a 35.7% limited 
partnership interest in Providence Power.  In addition, Ridgewood 
Providence Power Corporation was formed as a Delaware corporation 
("RPPCorp.").  The Trust invested $71,300 and owns 35.7% of the 
outstanding common stock of RPPCorp., which is the sole general 
partner of Providence Power.

     On April 16, 1996, Providence Power purchased substantially 
all of the net assets of Northeastern Landfill Power Joint 
Venture.  The assets acquired include a 12.3 megawatt ("MW") 
capacity electrical generating station, located at the Central 
Landfill in Johnston, Rhode Island (the "Providence Project").  
The Providence Project includes eight reciprocating electric 
generator engines, which are fueled by methane gas produced and 
collected from the landfill.  The electricity generated is sold 
to New England Power Corporation under a long-term contract.  The 
purchase price was $15,533,021 cash, including transaction costs 
and repayment of $3,000,000 of principal on senior secured non-
recourse notes payable.  In addition, Providence Power assumed 
the obligation to repay the remaining principal outstanding of 
$6,310,404 on the senior secured non-recourse notes payable.

     Through ownership in RPPCorp. and Providence Power, the 
Trust owns 35.7% of the Providence Project.  The remaining 64.3% 
is owned by Ridgewood Electric Power Trust IV ("Trust IV").  
Ridgewood Power Corporation is the managing partner of the Trust 
and Trust IV.  In 1996, the Trust received distributions of 
$562,427 from the Providence Project.

On-site Cogeneration Projects

     On September 29, 1995, the Trust acquired a portfolio of 35 
projects from affiliates of Eastern Utilities Associates ("EUA"), 
which sell electricity and thermal energy to industrial and 
commercial customers.  The projects are held in eight limited 
partnerships of which the Trust is the sole limited partner and 
is the sole owner of each of the general partners.  In the 
aggregate, the projects have 13.7 MW of base load and 5.7 MW of 
backup and standby capacity.  The Trust paid a total of 
$11,300,000 for the projects and has invested additional amounts 
in working capital.  EUA operated the projects under a transition 
agreement until January 1, 1996, at which time Ridgewood Power 
Management Corporation, an affiliate of the Trust, assumed 
operational control.  No distributions were made by these 
projects in 1995.  The Trust received distributions of $1,756,410 
from these projects in 1996.

Ridgewood/Rhode Island Power Partners L.P.

     Ridgewood/Rhode Island Power Partners Limited Partnership 
(the "Partnership") leases three 1,400 kilowatt Cooper Superior 
gas fired generator sets with heat recovery to a Rhode Island 
manufacturing company under a lease expiring in 2006.  Two 
engines are in regular use and one engine is on standby.  The 
partnership receives a monthly fixed lease payment and a 
maintenance payment, which escalates over the term of the lease.  
The Partnership is responsible for maintaining the engines and 
related equipment.  At the expiration of the lease, the lessee 
may purchase the equipment from the partnership for its fair 
market value.  The Trust and customer are currently in 
negotiations to revise the lease.  As of December 31, 1996 and 
1995, the total cost of the Trust's investment in the partnership 
was $3,722,618.  The Trust received distributions of $572,970 
from the project in 1996.

                            -F10

<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements

Ridgewood/Mass. Power Partners L.P.

     Ridgewood/Mass. Power Partners L.P. (the "Partnership") owns 
two projects.  The first is a 3.5 MW base load, simple cycle, 
dual-fuel, combustion turbine powered plant with a heat recovery 
steam generator which sells electric power and steam to a 
manufacturing facility on whose site the plant is located.  The 
project includes two 1.6 MW Caterpillar diesel engine generator 
sets to provide backup power.  The project sells electric and 
thermal energy to the manufacturing facility at the project's 
production cost (as defined in the Energy Service Agreement) plus 
a share of the savings (the difference between what the electric 
and thermal energy would have cost the company absent the 
cogeneration plant).  The Energy Service Agreement expires at the 
end of 2005.  As of  December 31, 1996 and 1995, the total cost 
of the Trust's investment in the partnership was $3,223,881.  The 
Trust received distributions of $660,201 from the project in 
1996.  The Partnership also owns a smaller group of four 
cogeneration generator sets totaling 255 kilowatt ("KW") serving 
a residential complex in Worcester, Massachusetts.  The energy 
services agreement ("ESA") provides that the partnership receives 
from the customer the cost to purchase electricity and natural 
gas from the local utility, less a guaranteed savings based on 
the utility's current rates.  The ESA expires in 2004.

Ridgewood/Elmsford Power Partners, L.P. 

     Ridgewood/Elmsford Power Partners, L.P. (the "Partnership") 
owns one cogeneration project consisting of two 665 KW (1,330 KW 
total) dual-fuel Cooper Superior engine generator sets with heat 
recovery and a Caterpillar 600 kilowatt standby diesel generator 
set.  The Energy Services Agreement ("ESA") expires in 2005 and 
provides that the Partnership receives its production costs (as 
defined in the ESA) plus a share of the excess of the customer's 
avoided cost over production costs.  As of December 31, 1996 and 
1995, the total cost of the Trust's investment in the partnership 
was $1,430,136.  The Trust received distributions of $160,940 
from the project in 1996. 

The "Other On-site Cogeneration Project Partnerships"

     The "other on-site cogeneration project partnerships" 
consist of five partnerships, which own 30 of the 35 projects 
acquired from Eastern Utilities Associates.  These 30 projects 
represent approximately one-third of the Trust's investment in 
the on-site cogeneration projects.  All thirty are gas-fired 
cogeneration projects, located in California, Connecticut or New 
York.  Their energy service agreements have terms expiring 
between September 1996 and 2011.  The projects represent 5.5 MW 
of base load capacity.  The largest project is 660 KW or 12% of 
the capacity.  The projects range in size from 30 KW to 660 KW.  
As of December 31, 1996 and 1995, the total cost of the Trust's 
investment in the partnerships was $4,100,745 and $4,244,488, 
respectively.  In 1996, the Trust wrote-off four small projects 
amounting to $113,042.  The Trust received distributions of 
$362,299 from the projects in 1996.

California Pumping Project

     During 1995, the Trust acquired 11 natural gas fueled diesel 
engines, which drive deep irrigation well pumps in Ventura 
County, California.  The aggregate purchase price was $353,619.  
On December 31, 1995, the engines were sold to an affiliate at 
book value and no gain or loss was recognized on the transaction.

                                -F11-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements

4.  Transactions With Managing Shareholder And Affiliates

     The Trust also pays to the managing shareholder a 
distribution and offering fee up to 5% of each capital 
contribution made to the Trust.  The fee is intended to cover 
legal, accounting, consulting, filing, printing, distribution, 
selling and closing costs for the offering of the Trust.  For the 
periods ended December 31, 1996, 1995 and 1994, the Trust paid 
fees for these services to the managing shareholder totaling 
zero, $860,195 and $1,088,727, respectively.  These fees were 
recorded as a reduction in shareholders' capital contributions.

     The Trust pays to the managing shareholder an investment fee 
up to 2% of each capital contribution made to the Trust.  The fee 
is payable to the managing shareholder for its services in 
investigating and evaluating investment opportunities and 
effecting transactions for investing the capital of the Trust.  
For the periods ended December 31, 1996, 1995 and 1994, the Trust 
paid investment fees to the managing shareholder of zero, 
$343,779 and $421,011, respectively.

     The Trust entered into a management agreement with the 
managing shareholder, under which the managing shareholder 
renders certain management, administrative and advisory services 
and provides office space and other facilities to the Trust.  As 
compensation to the managing shareholder, the Trust pays the 
managing shareholder an annual management fee equal to 2.5% of 
the net asset value of the Trust payable monthly upon the closing 
of the Trust.  For the years ended December 31, 1996 and 1995, 
the Trust paid management fees to the managing shareholder of 
$794,026 and $482,309, respectively.

     Under the Declaration of Trust, the managing shareholder is 
entitled to receive each year 1% of all distributions made by the 
Trust (other than those derived from the disposition of Trust 
property) until the shareholders have been distributed in that 
year an amount equal to 14% of their equity contribution.  
Thereafter, the managing shareholder is entitled to receive 20% 
of the distributions for the remainder of the year.  The managing 
shareholder is entitled to receive 1% of the proceeds from 
dispositions of Trust properties until the shareholders have 
received cumulative distributions equal to their original 
investment ("Payout").  In all cases, after Payout the managing 
shareholder is entitled to receive 20% of all remaining 
distributions of the Trust. 

     Where permitted, in the event the managing shareholder or an 
affiliate performs brokering services in respect of an investment 
acquisition or disposition opportunity for the Trust, the 
managing shareholder or such affiliate may charge the Trust a 
brokerage fee.  Such fee may not exceed 2% of the gross proceeds 
of any such acquisition or disposition.  No such fees were paid 
through December 31, 1996.

     The managing shareholder purchased one share of the Trust 
for $84,000.  Through the closing of the Trust's offering on May 
31, 1995, commissions and placement fees of $390,844 were earned 
by Ridgewood Securities Corporation, an affiliate of the managing 
shareholder.

                                  -F12-

<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements

     In 1996, under an operating agreement with the Trust, 
Ridgewood Power Management Corporation ("Ridgewood Management"), 
an entity related to the managing shareholder through common 
ownership, provides management, purchasing, engineering, planning 
and administrative services to the power generation projects 
operated by the Trust.  Ridgewood Management charges the projects 
at its cost for these services and for the allocable amount of 
certain overhead items.  Allocations of costs are on the basis of 
identifiable direct costs, time records or in proportion to 
amounts invested in projects managed by Ridgewood Management.

5.  Arbitration and Litigation

     The Trust's subsidiaries that own the on-site cogeneration 
projects brought an arbitration proceeding in the amount of 
$4,100,000 against Eastern Utilities Associates, Inc., the former 
owner.  The Trust claims breaches of representations and 
warranties made by the former owner at the time the on-site 
cogeneration projects were acquired.  The former owner has 
counterclaimed for approximately $550,000 for alleged unpaid 
management services.  The Trust has not reflected the amounts 
claimed in its financial statements pending the outcome of the 
arbitration proceeding.

     In February 1997, the Trust's subsidiaries that own the San 
Joaquin and Byron projects filed suit in the Superior Court of 
California against Pacific Gas and Electric Company ("PG & E") 
for breach of the power sales contracts.  The Trust argues PG & E 
has improperly withheld approximately $200,000 of capacity 
payments.  The Trust has not reflected the withheld capacity 
payments in its financial statements pending the outcome of the 
suit.

6.  Subsequent Event

Ridgewood AES Power Partners, L.L.C.

     The Trust, in conjunction with its managing shareholder, has 
accepted a proposal to invest in a cogeneration project at the 
North Shore University Hospital, located on Long Island in Nassau 
County, New York.  The Trust is to receive a 16% preferred return 
and 50 % of the net cash flow in excess of the preferred return.  
As of December 31, 1996, the Trust's investment in the project 
was $30,000.  The Trust's total purchase price is estimated to be 
$60,000.

                             -F13-