SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997

Commission file number   0-23432     

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

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

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

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

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

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

Shares of Beneficial Interest(Title of Class)

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

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

     There is no market for the Shares.  The aggregate capital contributions 
made for the Registrant's voting Shares held by non-affiliates of the 
Registrant at March 21, 1998 was $39,034,440.

Exhibit Index is located on page 52.


<PAGE>
PART I

Item 1.  Business.

Forward-looking statement advisory

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

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

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

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

(a)  General Development of Business.

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

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

     The Trust is organized similarly to a limited partnership.  
Ridgewood Power Corporation (the "Managing Shareholder"), a 
Delaware corporation, is the Managing Shareholder of the Trust.  
In general, the Managing Shareholder has the powers of a general 
partner of a limited partnership.  It has complete control of the 
day to day operation of the Trust and as to most acquisitions.  
The Managing Shareholder is not regularly elected by the owners 
of the Investor Shares (the "Investors").  The Managing 
Shareholder and the Independent Trustees of the Trust meet 
together as the Board of the Trust and take the actions that the 
1940 Act requires a board of directors to take for a business 
development company.  The Board of the Trust also provides 
general supervision and review of the Managing Shareholder but 
does not have the power to take action on its own.  The 
Independent Trustees do not have any management or administrative 
powers over the Trust or its property other than as expressly 
authorized or required by the Declaration of Trust of the Trust 
(the "Declaration") or the 1940 Act.

	Ridgewood Energy Holding Corporation ("Ridgewood Holding"), 
a Delaware corporation, is the Corporate Trustee of the Trust.  
The Corporate Trustee acts on the instructions of the Managing 
Shareholder and is not authorized to take independent 
discretionary action on behalf of the Trust. See Item 10. - 
Directors and Executive Officers of the Registrant below for a 
further description of the management of the Trust.

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

(b)  Financial Information about Industry Segments.

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

(c)  Narrative Description of Business.

(1)  General Description.

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

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

     The Trust has invested its funds in four Projects:  (i) a 
5.7 megawatt cogeneration facility located in Byron, California 
(the "Byron Project"); (ii) an 8.5 megawatt cogeneration facility 
located in Atwater, California (the "San Joaquin Project"); (iii) 
a portfolio of 35 cogeneration facilities located in California, 
New York, Massachusetts, Connecticut and Rhode Island, purchased 
from Eastern Utilities Associates, Inc. (the "On-site 
Cogeneration Projects") and (iv) a 13.8 megawatt electric 
generation plant fueled by gas drawn from a sanitary landfill 
near Providence, Rhode Island (the "Providence Project").

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

(2)  The Trust's Investments.

(i)  San Joaquin Project.  

     On January 17, 1995, Ridgewood Electric Power Trust III (the 
"Trust") and RW Central Valley, Inc., a newly formed California 
corporation which is wholly owned by the Trust ("Central 
Valley"), acquired 100% of the existing partnership interests of 
JRW Associates, L.P. ("JRW"), a California limited partnership 
which owns and operates an approximately 8.53 megawatt electric 
cogeneration facility located in the City of Atwater, Merced 
County, California.  The partnership interests were purchased 
from JRW Cogen, Inc. and NorCal Cogen, Inc., two corporations 
which were affiliates of a privately held company.  At the 
closing, the JRW partnership agreement was amended and restated 
so that Central Valley became the sole general partner of JRW 
with a 1% general partnership interest and the Trust became the 
sole limited partner of JRW with a 99% limited partnership 
interest.  Central Valley and the Trust plan to cause JRW to 
continue the operations of the Project in substantially the same 
manner as it has operated in the past.  The aggregate cash 
purchase price paid by Central Valley and the Trust for 100% of 
the JRW partnership interests was $5,300,000. 

     The San Joaquin Project, which is a Qualifying Facility, has 
been operating since 1991 and uses natural-gas fired 
reciprocating engines to generate electricity for sale to Pacific 
Gas and Electric Company ("PG&E") under a long term contract 
expiring in 2020(the "Power Contract"). The Project's electricity 
output is sold at a formula price set by the California Public 
Utilities Commission that approximates the utility's avoided 
cost.  Currently, the formula consists of a fixed payment for the 
plant's capacity and a payment per unit of energy delivered that 
is tied to 85% of the cost of natural gas, the fuel used at the 
plant.  The capacity payments vary seasonally and are 
significantly higher during the April-October peak season.  
Thermal energy from the San Joaquin Project is used to provide 
steam to an adjacent food processing company under long term 
contracts that also terminate in 2020.

    Until 1997, the plant only operated during the six month peak 
season during peak hours.  In 1997, the California Public 
Utilities Commission amended the rate structure to allocate more 
of the capacity payments to operations during the non-peak months 
from November to March.  As a result, less of the capacity 
payment could be earned during the peak season.  The Trust 
approached the food processor with a proposal to run the Project 
and provide steam year-round to the processor.  To do so, the 
Trust made approximately $750,000 of improvements to the steam 
transfer system and the processor waived certain increases in the 
rent for the Project site.  The parties are negotiating 
modifications to the thermal host contracts under which the 
Project would rent its site from the food processor and supply it 
with steam for a net annual payment of $150,000 from the Project 
to the food processor.  

	California is implementing a competitive power market 
beginning April 1, 1998 in which generators will eventually 
auction capacity and energy output that is not committed for sale 
under long-term contracts.  It is expected that eventually the 
California Public Utilities Commission will change the payment 
formula for many long-term contracts (including the San Joaquin 
Project's) to use the auction prices for capacity and energy 
output.  This would have effects on the Project's revenues that 
are not predictable at this time but that might result in a 
reduction in the prices paid by PG&E for electricity during off-
peak periods.  

	Distributions from the Project to the Trust for 1997 
totalled $1,152,000 (a 21.4% annual return), up from $779,000 in 
1996.  The increase resulted from operating the plant for three 
additional months beginning in April 1997 and from moderating 
fuel costs.  Further, unlike 1996, there was no withholding by 
PG&E of capacity payments.  See Item 3 - Legal Proceedings.

(ii)  Byron Project.

     Also in January 1995, the Trust caused the formation of 
Byron Power Partners, L.P., a California limited partnership (the 
"Partnership") in which RW Byron, Inc., a newly formed California 
corporation which is wholly owned by the Trust ("Byron") owns a 
1% general partner interest and the Trust owns a 99% limited 
partnership interest.  On January 17, 1995, the Partnership 
acquired through a merger all of the assets and business of 
Altamont Cogeneration Corporation ("Altamont") a California 
corporation which owns and operates an approximately 5.7 megawatt 
electric cogeneration facility located near the city of Byron, 
Alameda County, California.  As a result of the merger, NorCal 
Altamont, Inc., the parent of Altamont and an affiliate of a 
privately held company, received a cash payment of $2,269,500 
representing the purchase price for the assets and businesses of 
Altamont acquired by the Partnership.  The total purchase price 
to the Trust was $3,138,000. 

     The Byron Project, like the San Joaquin Project, is fueled 
by natural gas and sells its electricity output to Pacific Gas & 
Electric Company under agreements substantially identical to 
those at the San Joaquin Project.  The Power Contracts also 
expire in 2020.  The Project's heat output is used to evaporate 
brine from oil and gas wells, with payments by the Project for 
the site lease offsetting the thermal host's payments for heat.

     The California Public Utilities Commission's changes to the 
rate structure under the San Joaquin Power Contract, discussed 
above, had identical impact on the Byron Project.  No material 
capital improvements were needed for the Byron Project to operate 
on a year-round schedule and like the San Joaquin Project it 
began that schedule in April 1997.   

     Distributions to the Trust from the Byron Project in 1997 
were $572,000 (a 20.2% annual return), up from $429,000 in 1996.  
The increase reflected the three months of additional operation 
in 1997, moderating fuel costs and the lack of withholding of 
payments by PG&E.

     Please refer to the discussion of the San Joaquin Project 
for further details on regulatory issues for the Byron Project.

(iii)  On-site Cogeneration Projects

     In September 1995, the Trust purchased the ownership 
interests in the On-Site Cogeneration Projects, a portfolio of 35 
"inside the fence" cogeneration Projects owned by affiliates of 
Eastern Utilities Associates, Inc. ("EUA"), for an aggregate 
purchase price of approximately $11.3 million.  The Trust has 
invested an additional $1,369,934 for capital improvements in the 
Projects and has expended additional amounts on remediation.  The 
On-site Cogeneration Projects use natural gas fired turbines or 
reciprocating engines to provide electrical energy and/or heat 
for industrial uses or air conditioning purposes under contracts 
with a variety of industrial customers.  The On-site Cogeneration 
Projects were located on 35 sites in California (18 sites), 
Connecticut (six sites), Massachusetts (two sites), New York 
(eight sites) and Rhode Island (one site).  The purchase 
agreement provided that the acquisition would take place as of 
September 30, 1995, and accordingly the Trust assumed the 
benefits and risks of the On-site Cogeneration Projects accruing 
after that date.  Distributions from the On-site Cogeneration 
Projects began in 1996 and in 1997 totalled $1,429,000 (a 11.9% 
annual return), down from $1,755,000 in 1996.

     Returns from the On-site Cogeneration Projects have 
deteriorated since their purchase and beginning in the third 
quarter of 1997 the Trust has closed the majority of the Projects 
for unprofitability.  As of April 1, 1998, only 15 of the 
Projects are still in operation.  In the future, the Trust may 
decide to close additional Projects because of contract 
expirations, unprofitability and other factors.

     The On-Site Cogeneration Projects have been divided for 
financial reporting purposes into four groups.  The Massachusetts 
Projects include a project located at a textile manufacturer in 
Fall River, Massachusetts (a 3.5 Megawatt turbine with backup 
diesel engines) and a project at a housing complex in Worcester, 
Massachusetts (.25 Megawatts).  The Trust has successfully 
resolved contract interpretation disputes with the textile 
manufacturer and the Massachusetts Projects remain profitable.  
The Rhode Island Project, which was sold in December 1997, was 
located at a textile manufacturer in Centerdale, Rhode Island and 
had a rated capacity of 4.2 Megawatts from three natural-gas-
fired engines.  The host was obligated under an equipment lease 
and maintenance agreement to make payments of approximately 
$900,000 per year to the Trust, and according to projections 
supplied by EUA, the Project should have earned cash flow of 
$800,000 per year.  The host manufacturer for several years had 
been significantly in arrears in its payments and made only 
sporadic payments to the Trust.  The Project's operations were 
suspended in October 1996, and were only briefly resumed in 
spring 1997 after the host made a few payments.  In May 1997 the 
host's primary lender threatened to place the host textile 
manufacturer into bankruptcy, which would have terminated the 
host's contract with the Trust.  After protracted negotiations, 
the Trust sold the Project to the lender in December 1997 for 
$900,000 and the Trust recorded a loss of $2,752,000.

     The Coca-Cola Project is located at a bottling plant of 
Coca-Cola Bottling Company of New York at Elmsford, New York and 
has a rated capacity of 1.3 Megawatts with a .6 Megawatt standby 
diesel generator set.  The Project is profitable but is not 
meeting projections because the bottling plant's demand for heat 
has decreased and because of design defects in the Project which 
make it incapable of avoiding a large portion of the bottling 
plant's charges from the local utility.

     The remaining 31 On-site Cogeneration Projects, all of which 
are or were natural-gas-fueled, were located in California and 
New York and had an aggregate rated capacity of 5.5 Megawatts.  
In 1996, the Trust discontinued operation of and wrote off four 
small On-Site Cogeneration Projects in this group with a total 
rated capacity of .24 Megawatts of electricity, which had book 
values totalling $113,000.  The discontinued Projects had 
produced nominal cash flow or losses.  In 1997 the Trust 
discontinued operation of and wrote off 15 additional Projects in 
this group, for a total of $1,992,000.  The Trust is pursuing an 
arbitration proceeding against EUA for damages, as described at 
Item 3 - Legal Proceedings. 

     The Trust is currently financing the acquisition of four 
small cogeneration facilities in the New York metropolitan area 
which will be managed by an independent operator.  The Trust will 
have a preferred right to annual distributions equal to 16% of 
its investment before the independent operator is entitled to any 
compensation or distribution rights.  The total investment was 
$135,000 at December 31, 1997.

     In purchasing the On-site Cogeneration Projects, the 
Managing Shareholder concluded that the costs of engaging third 
party managers to operate many smaller Projects would 
significantly reduce total returns to the Trust.  The Managing 
Shareholder, after reviewing the alternatives, elected to create 
an in-house management capability as a means of limiting costs, 
acquiring valuable operating and industry knowledge and 
increasing efficiency.  It accordingly organized an affiliate, 
Ridgewood Power Management Company ("RPMC").  Management 
responsibility for the On-site Cogeneration Projects was 
substantially transferred to the Managing Shareholder and RPMC at 
the end of 1995 and the Managing Shareholder and RPMC are 
currently operating or supervising operation of all of the 
Trust's Projects except 8 small On-Site Cogeneration Projects 
located in New York and Connecticut, which are managed by an 
independent operator.  See Item 10 -- Directors and Executive 
Officers of the Registrant.

(iv)  Providence Project

     The Trust and Ridgewood Electric Power Trust IV, a similar 
program organized by the Managing Shareholder ("Ridgewood Power 
IV"), acquired in April 1996 all of the equity interest in the 
Providence State Landfill Power Plant, located near Providence, 
Rhode Island.  The Trust invested $7.1 million in the Project and 
Ridgewood Power IV supplied the remainder of the $20 million 
investment in the Project.  The acquisition cost was 
approximately $15.5 million (including a $3 million partial 
prepayment of Project debt as a condition of obtaining the 
lenders' consents and transaction costs)and the remainder of the 
investment by the programs represents funds applied to operating 
reserves, working capital and reserves for capital improvements 
and expansion.  The Project is encumbered by $5.4 million of debt 
maturing in installments through 2004.  In 1997, as described 
below, capital improvements were completed and the Trust's total 
investment in the Project increased to $7,504,000.

     The Project burns methane gas (the major component of 
natural gas) generated by the decomposition of garbage in the 
landfill as fuel for a 13.8 Megawatt capacity electric generation 
plant.  The facility has been in operation since 1990 and has a 
Power Contract for 12.0 Megawatts with New England Power Company 
with a 22 year term remaining.  

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

     Since the Trust purchased the Project in April 1996, average 
output from the existing eight engine-generator sets has risen by 
approximately 25% from 9.2 Megawatts in the first three months of 
1996 to 12.2 Megawatts in December 1996 and 11.5 Megawatts in 
1997.  Since August 1997, monthly sales have approached or 
equalled the 12.0 Megawatt maximum under the Power Contract.  In 
order to increase output to the maximum and to allow engines to 
be rotated off-line for preventative maintenance, an additional 
engine and generator set were installed at the Project in spring 
1997.  Although this increased nominal Project capacity by 
approximately 1/8, the actual benefit is the ability to have one 
engine off-line at any time for maintenance and still produce the 
entire 12.0 Megawatts that can be sold under the existing Power 
Contract. Distributions from the Project for 1997 to the Trust 
totalled $922,941 (a 12.3% annual return) up from $562,000 for 
the period April 16-December 31, 1996.

     The Trust currently has approximately $1.8 million of 
uninvested funds, some of which may be required for maintenance 
or replacement purposes or working capital.  The Trust is 
actively seeking additional small-scale Projects for investment. 

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

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

(3)  Project Operation.

     Revenue from the San Joaquin, Byron and Providence Projects 
primarily comes from Power Contracts with the local electric 
utilities.  The pricing provisions of these Power Contracts have 
two components, energy payments and capacity payments.  Energy 
payments are based on a facility's net electric output, with 
payment rates usually indexed to the fuel costs of the purchasing 
utility or to general inflation indices.  Capacity payments are 
based on either a facility's net electric output or its available 
capacity.  Capacity payment rates vary over the term of a Power 
Contract according to various schedules. Until April 1997, 
approximately 90% of the capacity payment for the Byron and San 
Joaquin Projects was allocated to the peak demand months of April 
through October, and accordingly it was most economic to operate 
the Projects only in those months and to close them for the 
remainder of the year.  In 1997, the California Public Utilities 
Commission reduced the allocations to the peak months to 
approximately 78%.  This would cause a significant decrease in 
Project income if six-month operations were continued.  
Accordingly, effective April 1, 1997, the Byron and San Joaquin 
Projects were operated on a year-round schedule.  The Trust 
believes that substantially all of the incremental costs of full-
year operation will be recovered from the energy payments.  In 
1997, the change resulted in material increases in the Projects' 
income.  The allocation of capacity payments to peak and non-peak 
months may be changed at any time by action of the California 
Public Utilities Commission, based on its own review or petitions 
by purchasing utilities, and any change may materially and 
adversely affect the two Projects.  

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

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

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

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

     The Managing Shareholder accordingly has organized RPMC to 
provide operating management for facilities operated by its 
investment programs, and has assigned day-to-day management of 
all of its Projects, other than 8 small On-site Cogeneration 
Projects located in New York and Connecticut, to RPMC.  See Item 
10 -- Directors and Executive Officers of the Registrant and Item 
13 -- Certain Relationships and Related Transactions for further 
information regarding the Operation Agreement and RPMC and for 
the cost reimbursements received by RPMC.

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

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

     Generally, revenues from the sales of electric energy from a 
cogeneration facility will represent the most significant portion 
of the facility's total revenue.  However, to maintain their 
status as a Qualifying Facility under PURPA, it is imperative 
that each cogeneration Project continue to satisfy PURPA 
cogeneration requirements as to the amount of thermal products 
generated.  Therefore, since the Byron and San Joaquin 
cogeneration Projects have only two customers (the electric 
energy purchaser and the thermal products purchaser), and because 
it may be impractical to obtain replacement purchasers of either 
the electrical or thermal output, loss of either of these 
customers would likely have a material adverse effect on the 
Trust.  

	PG&E undertakes a monitoring program as required by the 
California Public Utilities Commission for data on thermal 
deliveries at the Byron and San Joaquin Projects.  If a Project 
were to fail to meet PURPA standards, PG&E would be able to 
exclude a proportionate part of its purchases of electricity from 
the long-term power contract and pay at substantially lower spot 
rates for that part of its purchases.  This would require the 
Project to refund substantial amounts.  To date PG&E has not been 
able to establish any deficiency by the Projects and the Trust 
believes that the San Joaquin and Byron Projects have 
consistently exceeded PURPA requirements.  

     Customers of Projects that accounted for more than 10% of 
annual distributions from operating sources to the Trust in each 
of the last three fiscal years are:

<TABLE>
<CAPTION>
                                           Calendar year 
                                 1997          1996          1995
<S>                             <C>             <C>          <C>
Pacific Gas & Electric Co.       42.3%           34.3%       100.0%
 (San Joaquin & Byron Projects)
New England Electric System      22.6%           16.0%         0.0%
 (Providence Project)
Globe Manufacturing Co.          18.3%           18.7%         0.0%
 (Massachusetts Projects)
The Worcester Company             6.9%           16.3%         0.0%
 (Rhode Island Project)
</TABLE>

     Each On-Site Cogeneration Project sells all of its output to 
a single customer and termination of those contracts would end 
all revenue from a Project, unless the engines and other 
equipment could be economically moved to and installed on a new 
host's site.  The Providence Project burns methane gas generated 
by the decomposition of garbage, which causes that Project to be 
a "small power production facility" under PURPA.  This allows it 
to be a Qualifying Facility without the need to sell thermal 
energy or to meet efficiency standards.

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

     Hydrocarbon fuels, such as natural gas, coal and fuel oil, 
have been generally available in recent years for use by 
Independent Power Projects, although there have been serious 
supply impairments for both oil and natural gas at times during 
the last 20 years.  Market prices for natural gas, oil and, to a 
lesser extent, coal have fluctuated significantly over the last 
few years.  Such fluctuations directly affect the profitability 
of Projects that use these fuels. 

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

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

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

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

	The Trust is somewhat insulated from recent deregulatory 
trends in the electric industry because the San Joaquin, Byron 
and Providence Projects are Qualifying Facilities with long-term 
formula-price Power Contracts.  Each Power Contract now provides 
for rates in excess of current short-term rates for purchased 
power. There has been much speculation that in the course of 
deregulating the electric power industry, federal or state 
regulators or utilities would attempt to invalidate these power 
purchase contracts as a means of throwing some of the costs of 
deregulation on the owners of independent power plants.  

     To date, the Federal Energy Regulatory Commission and 
California authorities have ruled that existing Power Contracts 
will not be affected by their deregulation initiatives.  The 
regulators have so far rejected the requests of a few utilities 
to invalidate existing Power Contracts. Instead, most state plans 
for deregulation of the electric power industry treat the value 
of long-term Power Contracts that are above current and 
anticipated market prices as "stranded costs" of the utilities.  
The utilities are to be allowed to recover those costs during a 
transition period.  This is typically done by imposing a 
transition fee or surcharge on rates that is paid to the utility. 
This alternative is being implemented in California, may reduce 
incentives to invalidate the Olinda Project's Power Contract.  In 
some states, utilities are being encouraged or ordered to issue 
bonds or other financial instruments to retire stranded cost 
assets or contracts, supported by transition charges.

     No action has yet been taken by federal or state legislators 
to date to impair Independent Power Projects' existing power 
sales contracts, and there are federal constitutional provisions 
restricting actions to impair existing contracts.  There can not 
be any assurance, however, that the rapid changes occurring in 
the industry and the economy as a whole would not cause 
regulators or legislative bodies to attempt to change the 
regulatory structure in ways harmful to Independent Power 
Projects or to attempt to impair existing contracts.  In 
particular, some regulatory agencies have urged utilities to 
construe Power Contracts strictly and to police Independent Power 
Projects compliance with those Power Contracts vigorously.  See 
the discussion of the San Joaquin Project, above, for regulatory 
requirements in California for utility monitoring of Power 
Contracts and potential effects on the San Joaquin and Byron 
Projects.

     Predicting the consequences of any legislative or regulatory 
action is inherently speculative and the effects of any action 
proposed or effected in the future may harm or help the Trust.  
Because of the consistent position of the regulatory authorities 
to date and the other factors discussed here, the Trust believes 
that so long as it performs its obligations under the Power 
Contracts, it will be entitled to the benefits of the contracts.   

     In recent years, many electric utilities have attempted to 
exploit all possible means of terminating Power Contracts with 
independent power projects, including requests to regulatory 
agencies and alleging violations of even immaterial terms of the 
Power Contracts as justification for terminating those contracts. 
If such an attempt were to be made, the Trust might face material 
costs in contesting those utility actions.  Other utilities have 
from time to time made offers to purchase and terminate Power 
Contracts for lump sums. No such offer has been suggested or made 
to the Trust, although the Trust would entertain such an offer.

     Finally, the Power Contracts are subject to modification or 
rejection in the event that the utility purchaser enters 
bankruptcy.  There can be no assurance that the utility purchaser 
will stay out of bankruptcy.

     After the Power Contracts for the San Joaquin, Byron and 
Providence Projects expire in 2020 or those contracts terminate 
for other reasons, those Projects under currently anticipated 
conditions would be free to sell their output on the competitive 
electric supply market, either in spot, auction or short-term 
arrangements or under long-term contracts if those Power 
Contracts could be obtained.  There is no assurance that the 
Projects could then sell their output or do so profitably.  
Because the San Joaquin and Byron Projects are fueled by natural 
gas purchased at market prices and because those Projects are 
relatively small-scale, they might have cost disadvantages in 
competing against larger competitors that would enjoy economies 
of scale.  While the Providence Project is not subject to natural 
gas price fluctuations and it may benefit from environmental 
requirements for utilities to purchase power from environmentally 
favorable sources, the supply of fuel gas from the landfill is 
not assured, and it may also have diseconomies of small scale.  
The Trust is unable to anticipate whether thermal sales from 
cogeneration from the San Joaquin and Byron Projects or 
environmental subsidies at the Providence Project would offset 
any possible cost disadvantages in electric generation or gas 
supply deficiencies or whether in fact the Projects would have 
cost disadvantages after the contracts end.  It is thus 
impossible to predict the profitability of those Projects after 
termination of the Power Contracts.  

     The remaining On-site Cogeneration Projects, which have 
"shared savings" contracts, are exposed to the changes in the 
electric industry that are being caused by wholesale and retail 
deregulation, as explained below.  To date, these deregulation 
efforts have not had material adverse effects on these Projects, 
but there is the potential for some impact on revenues in 1998 
and later years.  

(5).  Competition

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

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

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

(iv)  Potential Legislation and Regulation.

     All federal, state and local laws and regulations, including 
but not limited to PURPA, the Holding Company Act, the 1992 
Energy Act and the FPA, are subject to amendment or repeal. 
Future legislation and regulation is uncertain, and could have 
material effects on the Trust.

(6).  Regulatory Matters.

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

(i)  Energy Regulation.

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

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

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

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

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

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

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

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

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

(ii)  Environmental Regulation.

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

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

     Title V of the Clean Air Act Amendments added a new 
permitting requirement for existing sources that requires all 
significant sources of air pollution to submit new applications 
to state agencies.  Title V implementation by the states 
generally does not impose significant additional restrictions on 
the Trust's Projects, other than requirements to continually 
monitor certain emissions and document compliance.  The 
permitting process is voluminous and protracted and the costs of 
fees for Title V applications, of testing and of engineering 
firms to prepare the necessary documentation have increased.  The 
Trust believes that all of its facilities will be in compliance 
with Title V requirements with only minor modifications such as 
the installation of an additional catalytic converter on some 
engines.

     In July 1997 the Environmental Protection Agency adopted 
more stringent standards for levels of ozone and small 
particulate matter (particles less than 25 microns in diameter) 
in geographic areas.  These new standards may cause some areas in 
which Projects are located to be classified as non-attainment 
areas.  If so, states will be required to impose additional 
requirements for industries to reduce emissions.  It is uncertain 
whether or how any reductions would be applied to small 
facilities such as the Trust's Projects.  If reductions were 
required, the Trust might have to make significant capital 
investments to install new control technology or might have to 
reduce operations.  In addition, many eastern states, including 
Massachusetts and New York, have organized in the Ozone Transport 
Assessment Group to require further restrictions on emissions of 
nitrogen oxides.  The Environmental Protection Agency is 
considering the Group's recommendations as well as other 
proposals to reduce emissions of nitrogen oxides and other ozone-
forming chemicals.  If adopted, new regulations could required 
the Trust to install additional equipment to reduce those 
emissions or to change operations.  Nitrogen oxide reductions can 
be difficult to achieve with add-on equipment and often require 
decreases in operating efficiency, both of which could cause 
material cost to the Trust.  It is not possible at this time to 
estimate whether or not any potential regulatory changes would 
materially affect the Trust.

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

     The Trust's Projects must comply with many federal and state 
laws and regulations governing wastewater and stormwater 
discharges from the Projects.  These are generally enforced by 
states under "NPDES" permits for point sources of discharges and 
by stormwater permits.  Under the Clean Water Act, NPDES permits 
must be renewed every five years and permit limits can be reduced 
at that time or under re-opener clauses at any time.  The 
Projects have not had material difficulty in complying with their 
permits or obtaining renewals.  The Projects use closed-loop 
engine cooling systems which do not require large discharges of 
coolant except for periodic flushing to local sewer systems under 
permit and do not make other material discharges to groundwaters 
or streams. 

     In 1998, the Trust's Projects will become subject to the 
reporting requirements of the Emergency Planning and Community 
Right-to-Know Act that require the Projects to prepare toxic 
release inventory release forms.  These forms will list all toxic 
substances on site that are used in excess of threshold levels so 
as to allow governmental agencies and the public to learn about 
the presence of those substances and to assess potential hazards 
and hazard responses.  The Trust does not anticipate that this 
will result in any material adverse effect on it.  

     Based on current trends, the Managing Shareholder expects 
that environmental and land use regulation will become more 
stringent.  The Trust and the Managing Shareholder have developed 
limited expertise and experience in obtaining necessary licenses, 
permits and approvals.  The Trust will rely upon qualified 
environmental consultants and environmental counsel retained by 
it to assist in evaluating the status of Projects regarding such 
matters.

(iii)  The 1940 Act

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

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

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

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

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

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

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

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

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

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

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

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

(e)  Employees.

     The Projects are operated by RPMC and accordingly the Trust 
has no employees.  The persons described below at Item 10.  
Directors and executive officers of the Managing Shareholder and 
RPMC serve as executive officers of the Trust and have the duties 
and powers usually applicable to similar officers of a Delaware 
corporation in carrying out the Trust business.

Item 2.  Properties.

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

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

<TABLE>
<CAPTION>

                                                      Approximate
                                            Approx-     Square        Descrip-
                       Ownership  Ground     imate    Footage of        tion
                       Interests  Lease     Acreage    Project (Actual   of
Project      Location   in Land  Expiration  of Land  or Projected)    Project

<S>        <C>           <C>      <C>         <C>     <C>        <C>          
Byron         Byron,      Leased    2021         2      28,000      Gas-fired 
            California                                            cogeneration
                                                                      facility
San Joaquin  Atwater,     Leased    2021         1      25,000       Gas-fired
            California                                            cogeneration
                                                                      facility
On-Site      15 sites     Leased   various       n/a       n/a     Inside-the-
 Cogen-        in CA,       or                                          fence,
 eration      CT, MA,     licensed                                   gas-fired
              and NY                                                or diesel-
                                                                       fueled 
                                                                  cogeneration
                                                                   engines and
                                                                    generators
Providence   Providence,  Leased    2020         4      10,000       Landfill
             Rhode Island                                            gas-fired
                                                                    generation
                                                                      facility

</TABLE>

Item 3.  Legal Proceedings.

     The Trust's subsidiaries that own the San Joaquin and Byron 
Projects filed suit in the Superior Court of California, City and 
County of San Francisco, in February 1997 against PG&E, alleging 
breach of the Power Contracts by PG&E's withholding a total of 
approximately $164,000 as noted above.  PG&E has answered the 
complaint and has counterclaimed for all payments made to those 
Projects.  The parties have conducted settlement negotiations 
since October 1997 without coming to a final agreement.  If 
settlement is not reached by mid-April 1998, discovery will 
resume and a trial is scheduled for August 1998.

     On February 27, 1997, Michael Cutbirth, an individual, sued 
the Managing Shareholder in the Superior Court of California, 
Kern County, claiming damages for violation of an alleged 
confidentiality agreement and for fraud relating to the 
acquisition of the San Joaquin and Byron Projects.  Mr. Cutbirth 
claims that the Managing Shareholder agreed to deal with him 
exclusively in connection with the Projects.  The suit includes a 
claim for an equity interest in the Projects and an management 
contract for the Projects.  The Managing Shareholder removed the 
lawsuit to the United States District Court for the Eastern 
District of California.  Discovery has been completed and motions 
for summary judgment are pending before the court.  The Managing 
Shareholder believes it has ample defenses and is vigorously 
defending the case.  If summary judgment is not obtained, the 
case is scheduled for trial in June 1998.  The Trust might be 
obligated to indemnify the Managing Shareholder against any 
liability if the Managing Shareholder acted in good faith and in 
the Trust's best interests and the conduct was neither negligence 
or misconduct.  

     The Trust's subsidiaries that own the On-site Cogeneration 
Projects brought an arbitration proceeding against the seller, a 
subsidiary of Eastern Utilities Associates, Inc., before the 
American Arbitration Association in Boston, Massachusetts in 
December 1996, alleging fraud and breaches of representations and 
warranties made by the seller in the agreements of sale.  The 
Trust has requested damages including refund of some or all of 
the purchase price, the costs of capital improvements and other 
items and has requested that the damages be doubled or trebled 
under applicable Massachusetts law.  The seller has 
counterclaimed for approximately $550,000 that it alleges it was 
owed for management services during October, November and 
December 1995.  The parties are conducting limited discovery in 
preparation for arbitration hearings scheduled for June 1998.  
See also Item 7 - Management's Discussion and Analysis of 
Financial Condition and Results of Operations - Results of 
Operations - The year ended December 31, 1997 . . . . for 
information regarding the damages suffered by the Trust.

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

     The Trust did not submit any matters to a vote of the 
Investors during the fourth quarter of 1997. 

PART II

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

(a)  Market Information.  

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

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

     The Managing Shareholder is considering the possibility of a 
combination of the Trust and four other investment programs 
sponsored by the Managing Shareholder (Ridgewood Electric Power 
Trusts I, II, IV and V) into a publicly traded entity.  This 
would require the approval of the Investors in the Trust and the 
other programs after proxy solicitations complying with 
requirements of the Securities and Exchange Commission, 
compliance with the "rollup" rules of the Securities and Exchange 
Commission and other regulations, and a change in the federal 
income tax status of the Trust from a partnership (which is not 
subject to tax) to a corporation.  The process of considering and 
effecting a combination, if the decision is made to do so, will 
be very lengthy.  There is no assurance that the Managing 
Shareholder will recommend a combination, that the Investors of 
the Trust or other programs will approve it, that economic 
conditions or the business results of the participants will be 
favorable for a combination, that the combination will be 
effected or that the economic results of a combination, if 
effected, will be favorable to the Investors of the Trust or 
other programs.  

(b)  Holders

     As of the date of this Form 10-K, there are 759 record 
holders of Investor Shares.

(c)  Dividends

     The Trust made distributions as follows in the years 1996 
and 1997:

                             Year ended                Year ended
                         December 31, 1997      December 31, 1996
Total distributions 
 to Investors                $3,045,001                $3,694,661
Distributions per 
 Investor Share                   7,771                     9,429
Distributions to
 Managing Shareholder            30,758                    37,312


     Distributions are made on a monthly basis.  The Trust's 
ability to make future distributions to Investors and their 
timing will depend on the net cash flow of the Trust and 
retention of reasonable reserves as determined by the Trust to 
cover its anticipated expenses.  

     Subject to the other factors described in this Annual Report 
on Form 10-K, the Trust's goal is to provide Investors with 
annual distributions of net cash flow, as defined in the 
Declaration of Trust, of 14% of their Capital Contributions to 
the Trust.  The Trust's cash flow comes primarily from 
distributions from Projects.  Those distributions are from cash 
flow of the Projects, which includes income of Projects plus 
funds representing depreciation and amortization charges taken by 
the Projects.  Because the Trust's objective is to distribute net 
cash flow, a substantial portion of many distributions by the 
Trust will include cash flow derived from depreciation and 
amortization charges against assets at the Project level. 
Nevertheless, because the Projects are not consolidated with the 
Trust for accounting purposes, all funds received from Projects 
are considered to be revenue to the Trust for accounting 
purposes.  Occasionally, distributions may also include cash 
released from operating or debt service reserves, Trust-level 
depreciation or amortization, or other non-cash charges against 
earnings.  Investors should be aware that the Trust is organized 
to return net cash flow rather than accounting income to 
Investors.

Item 6.  Selected Financial Data.

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

<TABLE>
<CAPTION>
Supplemental Information      As of and      As of and          As of and          As of and 
Schedule                       for the        for the            for the            for the 
Selected Financial Data       Year Ended     Year Ended         Year Ended       Period Ended
                             December 31,    December 31,      December 31,      December 31,
                                1997            1996              1995               1994     
Total Fund Information:
<S>                         <C>             <C>                <C>                <C>         


Net revenue from 
 operating projects          $4,075,390     $3,525,613         $1,317,287                 $0
Net income (loss)            (1,355,866)(A)  2,541,686          1,440,550           (213,299)
Net assets
 (shareholders' equity)      26,957,314     31,388,939         32,579,226         18,671,356
Investments in project
 development and power
 generation limited
 partnerships                24,613,978     28,050,750         20,884,493                  0
Total assets                 27,336,224     31,430,075         32,651,668         18,405,145
Per Investor Share:
  Revenues                      $10,788         $9,630             $6,066             $1,178 
  Expenses                       14,249(A)       3,143              2,389              2,144
  Net income (loss)              (3,460)         6,486              3,676               (966)
  Net asset value                68,796         80,106             83,143             84,598
Distributions to Investors        7,771          9,429              5,896                  0

</TABLE>
(A)  After writedowns of investments of $4,743,631 ($12,106 per 
Investor Share).

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

Introduction

     The following discussion and analysis should be read in 
conjunction with the Trust's financial statements and the notes 
thereto, found at the end of this Annual Report. The Trust 
carries its investment in the Projects it owns at fair value and 
does not consolidate its financial statements with the financial 
statements of the Projects.  Revenue is recorded by the Trust as 
cash distributions are declared by the Projects.  Trust revenues 
may fluctuate from period to period depending on the operating 
cash flow generated by the Projects and the amount of cash 
retained to fund capital expenditures.  Dollar amounts in this 
discussion are generally rounded to the nearest $1,000, except 
per share data.

Outlook

     The U.S. electricity markets are being restructured and 
there is a trend away from regulated electricity systems towards 
deregulated, competitive market structures.  The States that the 
Trust's Projects operate in have passed or are considering new 
legislation that permits utility customers to choose their 
electricity supplier in a competitive electricity market.  The 
Providence, San Joaquin and Byron Projects are "Qualified 
Facilities" as defined under the Public Utility Regulatory 
Policies Act of 1978 and currently sell their electric output to 
utilities under long-term contracts expiring in 2020, 2021 and 
2020, respectively.  During the term of the contracts, the 
utilities may or may not attempt to buy out the contracts prior 
to expiration.  At the end of the contracts, the Projects will 
become merchant plants and may be able to sell the electric 
output at then current market prices.  There can be no assurance 
that future market prices will be sufficient to allow the 
Projects to operate profitably.

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

Results of Operations
The year ended December 31, 1997 compared to the year ended 
December 31, 1996.

     In 1997, the Trust's net loss was $1,356,000.  The loss 
resulted from third and fourth quarter 1997 charges to earnings 
totaling $4,744,000 relating to the write-down to net realizable 
value of the Trust's investment in 16 terminated On-site 
Cogeneration Projects acquired from affiliates of Eastern 
Utilities Associates in 1995.  In 1996, the Trust wrote-down four 
On-site Cogeneration Projects totaling $113,000.  The 1997 and 
1996 results from operations for the On-site Cogeneration 
Projects were substantially below expectations; resulting from 
the prior owner's poor maintenance and operation, design defects, 
defaults by a customer; in some cases, a pattern of overbilling 
of customers; and other breaches of the purchase agreement.  
These Projects also suffered temporarily in early 1997 and late 
1996 from sharp increases in natural gas prices.  Most of these 
Projects are "shared savings" projects under which the Projects' 
billings are computed with reference to utilities' retail 
electricity and gas rates.  Because utility rates to retail 
customers in many cases did not rise as fast as the gas prices 
paid by the Projects, margins were severely impacted in the 
winter of 1996-1997.

     Without the write-downs of the On-site Cogeneration 
Projects, net income for 1997 would have been $3,388,000 as 
compared to net income of $2,655,000 for 1996, an increase of 
$733,000 (27.6%).  This increase reflects a $549,000 increase in 
income received from Projects in which the Trust has invested, a 
decrease of $96,000 (38.7%) in interest income and a decrease of 
$280,000 (25.0%) in other Trust expenses.  In 1997, interest 
income decreased by $96,000 from 1996, as a result of the 
increase of the amount of cash invested in Projects, which 
decreased the cash invested in short-term securities.  For 1997, 
the Trust's expenses (excluding investment write-downs) decreased 
by $280,000 from 1996, principally due to a $254,000 decrease in 
Project due diligence costs because the Trust evaluated fewer 
acquisition targets in 1997. There were no material changes in 
the other expense categories.

     As summarized below, income from power generation projects 
increased 15.6% to $4,075,000 in 1997 compared to $3,526,000 in 
1996:

Project                                   1997          1996          1995

On-site Cogeneration:
    Massachusetts                   $  745,000      $ 660,000               0
    Rhode Island                       283,000        573,000               0
    New York                           293,000        161,000               0
    Others                             108,000        362,000               0
    Subtotal                         1,429,000      1,756,000               0
San Joaquin                          1,152,000        779,000         982,000
Providence                             923,000        562,000*              0
Byron                                  571,000        429,000         335,000

Total                               $4,075,000     $3,526,000      $1,317,000

*   Represents a partial year April 16 to December 31, 1996.

     In 1997, income from the San Joaquin, Providence and the 
Byron Projects increased by $373,000 (47.9%), $361,000 (64.2%), 
and $142,000 (33.1%), respectively.  As a result of changes made 
in the calculation of capacity payments received under their 
electricity sales contracts, the San Joaquin and Byron Projects 
improved profitability by operating for nine months in 1997, as 
compared to six months in 1996.  It is expected that these 
Projects will operate for twelve months in 1998.  The Trust 
acquired its interest in the Providence Project in mid-April 
1996.  Accordingly, 1996 results only include eight and one half 
months of activity.  Additionally, 1997 operating profitability 
improved by adding a ninth engine and increasing sales to the 
utility.  In 1997, income from the On-Site Cogeneration Projects 
decreased by $327,000 (18.6%) as a result of the problems 
discussed above.

The year ended December 31, 1996 compared to the year ended 
December 31, 1995.

     Net income for 1996 was $2,542,000, a $1,101,000 increase 
(76.4%) from the 1995 net income of $1,441,000.  Revenues 
increased $1,397,000 to $3,773,000 (58.8%), while Trust-level 
expenses rose to $1,232,000 in 1996 from $936,000 in the prior 
year, a $295,000 (31.5%) increase.

     With the On-site Cogeneration Projects and the Providence 
Project making their first distributions to the Trust in 1996, 
income from power generation projects increased by 167.5% 
($2,208,000) to $3,526,000, and concurrently, as funds were 
invested in Projects, interest and dividend income decreased to 
$248,000 in 1996 from $1,060,000 in 1995, an $812,000 (76.6%) 
decrease.  Distributions from the On-site Cogeneration Projects 
were substantially below expectations (a 14.1% annual return in 
1996), resulting from the factors discussed above.  These 
Projects also suffered temporarily in late 1996 from sharp 
increases in natural gas prices.

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

     Trust-level expenses increased by 31.6% from 1995 to 1996, 
but the nature of those expenses changed significantly as the 
Trust ended the major portion of its investment program.  The 
investment fee, which is charged in the year capital 
contributions are made and which is paid to the Managing 
Shareholder to compensate it for investment advice and 
evaluation, was $344,000 in 1995 but was not charged in 1996, 
reflecting the conclusion of the offering of Investor Shares in 
1995.  The management fee, which is charged on the basis of the 
Trust's net assets, increased from $482,000 in 1995 to $794,000 
in 1996, a $312,000 (64.6%) increase.  

     The investment process caused significant increases in due 
diligence and project investigation expenses payable to third 
parties, which increased to $258,000 in 1996 from $8,000 in 1995. 
The Trust also incurred writeoffs of $113,000 for the four small 
discontinued On-site Cogeneration Projects.

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

Liquidity and Capital Resources  

     For 1997, net cash provided by operating activities of 
$2,804,000 included $594,000 of cash which was transferred to the 
Trust when the Trust changed its cash management procedures and 
consolidated all significant cash balances at the Trust level.  
In 1997, net cash provided by operating activities include 
deductions of $1,370,000 and $664,000 for cash advances to 
various projects to fund capital expenditures and working 
capital, respectively.  Cash distributions to shareholders were 
$3,076,000 in 1997 as compared to $3,732,000 in 1996.  As a 
result of lower earnings from the On-site Cogeneration Projects, 
monthly cash distributions were reduced to $500 per share in July 
1997 from an average of $800 per share during the first six 
months of the year. 

     During the fourth quarter of 1997, the Trust and Fleet Bank, 
N.A. (the "Bank") entered into a revolving line of credit 
agreement, whereby the Bank provides a three year committed line 
of credit facility of $750,000.  Outstanding borrowings bear 
interest at the Bank's prime rate or, at the Trust's choice, at 
LIBOR plus 2.5%.  The credit agreement requires the Trust to 
maintain a ratio of total debt to tangible net worth of no more 
than 1 to 1 and a minimum debt service coverage ratio of 2 to 1.  
The credit facility was obtained in order to allow the Trust to 
operate using a minimum amount of cash, maximize the amount 
invested in Projects and maximize cash distributions to 
shareholders.  There were no borrowings under the line of credit 
in 1997.

     Other than investments of available cash in power generation 
Projects, obligations of the Trust are generally limited to 
payment of the management fee to the Managing Shareholder, 
payments for certain accounting and legal services to third 
persons and distributions to shareholders of available operating 
cash flow generated by the Trust's investments.  The Trust's 
policy is to distribute as much cash as is prudent to 
shareholders.  Accordingly, the Trust has not found it necessary 
to retain a material amount of working capital.  The need to 
retain working capital is further reduced by the availability of 
the line of credit facility.  The Trust anticipates that its cash 
flow from operations during 1998, unexpended offering proceeds 
and line of credit facility will be adequate to fund its 
obligations.

Financial instruments

     The Trust's investments in financial instruments are short-
term investments of working capital or excess cash.  Those short-
term investments are limited by its Declaration of Trust to 
investments in United States government and agency securities or 
to obligations of banks having at least $5 billion in assets.  
Currently the Trust invests only in bank obligations of Fleet 
Bank, N.A.  Because the Trust invests only in short-term 
instruments for cash management, its exposure to interest rate 
changes is low.

Year 2000 Remediation.

     The Managing Shareholder and its affiliates began year 2000 
review and planning in early 1997.  After initial remediation was 
completed, a more intensive review discovered additional issues 
and the Managing Shareholder began a formal remediation program 
in late 1997.  The Managing Shareholder has assessed problems, 
has a written plan for remediation and is implementing the plan 
on schedule.  

     The accounting, network and financial packages for the 
Ridgewood companies are basically off-the-shelf packages that 
will be remediated, where necessary, by obtaining patches or 
updated versions.  The Managing Shareholder expects that updating 
will be complete before the end of 1998 with ample time for 
implementation, testing and custom changes to some modifications 
made by Ridgewood to those programs.  

     The marketing and investor relations functions rely on 
custom-written software and the Managing Shareholder has hired a 
specialist to remedy that software. The year 2000 changes in the 
distribution system, which is used to send checks to Investors, 
have been completed and are being tested.  The effort is on 
schedule to complete remediation and testing by December 31, 1998 
and the Managing Shareholder believes that all material systems 
will be year 2000 compliant by early 1999.  Some systems are 
being remediated using the "sliding window" technique.  Although 
this will allow compliance for several years beyond the year 
2000, eventually those systems will have to be rewritten again or 
replaced.

     The Managing Shareholder and its affiliates do not 
significantly rely on computer input from suppliers and customers 
and thus are not directly affected by other companies' year 2000 
compliance.  However, if customers' payment systems or suppliers' 
systems were adversely affected by year 2000 problems, the Trust 
could be affected.  Because the Trust and the Managing 
Shareholder are extremely small relative to the size of their 
material customers and suppliers and are paid or supplied using 
the same systems as larger companies, requests for written 
assurances of compliance from those customers or suppliers are 
not cost-effective.

     Although the total cost associated with year 2000 compliance 
is not yet determined, the Trust does not believe that the costs 
will be material to its financial position or results of 
operation.

Item 8.  Financial Statements and Supplementary Data.

Index to Financial Statements

     Report of Independent Accountants                       F-2
     Balance Sheet at December 31, 1997 and 1996             F-3
     Statement of Operations for Three Years
      ended December 31, 1997                                F-4
     Statement of Changes in Shareholders'
      Equity for Three Years ended December 31,
      1997                                                   F-5
     Statement of Cash Flows for Three Years
      ended December 31, 1997                           F-6 -F-7
     Notes to Financial Statements                   F-8 to F-14

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

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

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

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

PART III

Item 10.  Directors and Executive Officers of the Registrant.

(a)  General.

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

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

(b)  Managing Shareholder.

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

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

     The Managing Shareholder is an affiliate of Ridgewood Energy 
Corporation ("Ridgewood Energy"), which has organized and 
operated 46 limited partnership funds and one business trust over 
the last 16 years (of which 25 have terminated) and which had 
total capital contributions in excess of $190 million.  The 
programs operated by Ridgewood Energy have invested in oil and 
natural gas drilling and completion and other related activities.  
Other affiliates of the Managing Shareholder include Ridgewood 
Securities Corporation ("Ridgewood Securities"), an NASD member 
which has been the placement agent for the private placement 
offerings of the six trusts sponsored by the Managing Shareholder 
and the funds sponsored by Ridgewood Energy; Ridgewood Power 
Capital Corporation ("Ridgewood Capital"), organized in 1998, 
which assists in offerings made by the Managing Shareholder; and 
Ridgewood Power VI Corporation ("Power VI Corp."), which is a 
managing shareholder of the Growth Fund and RPMC.  Each of these 
corporations is wholly owned by Robert E. Swanson, who is their 
sole director.

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

     Robert E. Swanson, age 51, has also served as President of 
the Trust since its inception in November 1992 and as President 
of RPMC, Ridgewood Power I, Ridgewood Power II, Ridgewood Power 
IV, Ridgewood Power V and the Growth Fund, since their respective 
inceptions.  Mr. Swanson has been President and registered 
principal of Ridgewood Securities and became the Chairman of the 
Board of Ridgewood Capital on its organization in 1998.  In 
addition, he has been President and sole stockholder of Ridgewood 
Energy since its inception in October 1982.  Prior to forming 
Ridgewood Energy in 1982, Mr. Swanson was a tax partner at the 
former New York and Los Angeles law firm of Fulop & Hardee and an 
officer in the Trust and Investment Division of Morgan Guaranty 
Trust Company.  His specialty is in personal tax and financial 
planning, including income, estate and gift tax.  Mr. Swanson is 
a member of the New York State and New Jersey bars, the 
Association of the Bar of the City of New York and the New York 
State Bar Association.  He is a graduate of Amherst College and 
Fordham University Law School.  

     Robert L. Gold, age 39, has served as Executive Vice 
President of the Managing Shareholder, RPMC, Ridgewood Power I, 
the Trust, Ridgewood Power II, Ridgewood Power IV, Ridgewood 
Power V and the Growth Fund since their respective inceptions, 
with primary responsibility for marketing and acquisitions.  He 
has been President of Ridgewood Power Capital Corporation since 
its organization in 1998.  He has served as Vice President and 
General Counsel of Ridgewood Securities Corporation since he 
joined the firm in December 1987.  Mr. Gold has also served as 
Executive Vice President of Ridgewood Energy since October 1990.  
He served as Vice President of Ridgewood Energy from December 
1987 through September 1990. For the two years prior to joining 
Ridgewood Energy and Ridgewood Securities Corporation, Mr. Gold 
was a corporate attorney in the law firm of Cleary, Gottlieb, 
Steen & Hamilton in New York City where his experience included 
mortgage finance, mergers and acquisitions, public offerings, 
tender offers, and other business legal matters. Mr. Gold is a 
member of the New York State bar.  He is a graduate of Colgate 
University and New York University School of Law.

     Thomas R. Brown, age 43, joined the Managing Shareholder in 
November 1994 as Senior Vice President and holds the same 
position with the Trust, RPMC and each of the other trusts 
sponsored by the Managing Shareholder.  He became Chief Operating 
Officer of the Managing Shareholder, RPMC and the Ridgewood Power 
I through V trusts in October 1996, and is the Chief Operating 
Officer of the Growth Fund.  Mr. Brown has over 20 years' 
experience in the development and operation of power and 
industrial projects.  From 1992 until joining the Managing 
Shareholder he was employed by Tampella Services, Inc., an 
affiliate of Tampella, Inc., one of the world's largest 
manufacturers of boilers and related equipment for the power 
industry.  Mr. Brown was Project Manager for Tampella's Piney 
Creek project, a $100 million bituminous waste coal fired 
circulating fluidized bed power plant.  Between 1990 and 1992 Mr. 
Brown was Deputy Project Manager at Inter-Power of Pennsylvania, 
where he successfully developed a 106 megawatt coal fired 
facility.  Between 1982 and 1990 Mr. Brown was employed by 
Pennsylvania Electric Company, an integrated utility, as a Senior 
Thermal Performance Engineer.  Prior to that, Mr. Brown was an 
Engineer with Bethlehem Steel Corporation.  He has an Bachelor of 
Science degree in Mechanical Engineering from Pennsylvania State 
University and an MBA in Finance from the University of 
Pennsylvania.  Mr. Brown satisfied all requirements to earn the 
Professional Engineer designation in 1985.

     Martin V. Quinn, age 50, assumed the duties of Chief 
Financial Officer of the Managing Shareholder, the Trust, the 
other four trusts organized by the Managing Shareholder and RPMC 
in November 1996 under a consulting arrangement.  He became a 
full-time officer of the Managing Shareholder and RPMC in April 
1997 and is now also Chief Financial Officer of the Growth Fund.  

     Mr. Quinn has 29 years of experience in financial management 
and corporate mergers and acquisitions, gained with major, 
publicly-traded companies and an international accounting firm. 
He formerly served as Vice President of Finance and Chief 
Financial Officer of NORSTAR Energy, an energy services company, 
from February 1994 until June 1996.  From 1991 to March 1993, Mr. 
Quinn was employed by Brown-Forman Corporation, a diversified 
consumer products company and distiller, where he was Vice 
President-Corporate Development.  From 1981 to 1991, Mr. Quinn 
held various officer-level positions with NERCO, Inc., a mining 
and natural resource company, including Vice President- 
Controller and Chief Accounting Officer for his last six years 
and Vice President-Corporate Development.  Mr. Quinn's 
professional qualifications include his certified public 
accountant qualification in New York State, membership in the 
American Institute of Certified Public Accountants, six years of 
experience with the international accounting firm of Price 
Waterhouse, and a Bachelor of Science degree in Accounting and 
Finance from the University of Scranton (1969).

     Mary Lou Olin, age 45, has served as Vice President of the 
Managing Shareholder, RPMC, Ridgewood Capital, the Trust, 
Ridgewood Power I, Ridgewood Power II, Ridgewood Power IV, 
Ridgewood Power V and the Growth Fund since their respective 
inceptions.  She has also served as Vice President of Ridgewood 
Energy since October 1984, when she joined the firm.  Her primary 
areas of responsibility are investor relations, communications 
and administration.  Prior to her employment at Ridgewood Energy, 
Ms. Olin was a Regional Administrator at McGraw-Hill Training 
Systems where she was employed for two years.  Prior to that, she 
was employed by RCA Corporation.  Ms. Olin has a Bachelor of Arts 
degree from Queens College.

(c)  Management Agreement.

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

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

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

     The Board of the Trust (including both initial Independent 
Trustees) have approved the initial Management Agreement and its 
renewals.  Each Investor consented to the terms and conditions of 
the initial Management Agreement by subscribing to acquire 
Investor Shares in the Trust.  The Management Agreement will 
remain in effect until January 4, 1999 and year to year 
thereafter as long as it is approved at least annually by (i) 
either the Board of the Trust or a majority in interest of the 
Investors and (ii) a majority of the Independent Trustees.  The 
agreement is subject to termination at any time on 60 days' prior 
notice by the Board, a majority in interest of the Investors or 
the Managing Shareholder.  The agreement is subject to amendment 
by the parties with the approval of (i) either the Board or a 
majority in interest of the Investors and (ii) a majority of the 
Independent Trustees.

(d)  Executive Officers of the Trust.

     Pursuant to the Declaration, the Managing Shareholder has 
appointed officers of the Trust to act on behalf of the Trust and 
sign documents on behalf of the Trust as authorized by the 
Managing Shareholder.  Mr. Swanson has been named the President 
of the Trust and the other executive officers of the Trust are 
identical to those of the Managing Shareholder, with the addition 
of Joseph A. Heyison, Senior Vice President and General Counsel.  
Mr. Heyison, age 43, joined RPMC in January 1996.  He was 
previously of counsel to the law firm of De Forest & Duer, 
concentrating in corporate finance, banking, environmental law 
and securities.  He is a member of the bars of New Jersey, New 
York and Ohio and was graduated from the University of 
Pennsylvania Law School in 1979.

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

(e)  The Trustees.

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

     The Independent Trustees of the Trust are Ralph O. Hellmold 
and Jonathan C. Kaledin.  Set forth below is certain information 
concerning Mr. Hellmold and Mr. Kaledin, who also serve as 
independent trustees of Ridgewood Power II and as independent 
panel members of Ridgewood Power V.  Both are independent power 
programs sponsored by Ridgewood Power. Independent panel members 
must approve transactions between their program and the Managing 
Shareholder or companies affiliated with the Managing 
Shareholder, but have no other responsibilities.  Neither Mr. 
Hellmold nor Mr. Kaledin is otherwise affiliated with the Trust, 
any of the Trust's officers or agents, the Managing Shareholder, 
any other Trustee, any affiliates of the Managing Shareholder and 
any other Trustees, or any director, officer or agent of any of 
the foregoing.  

     Ralph O. Hellmold, age 57, is founder, sole shareholder and 
President of Hellmold Associates, Inc., an investment banking 
firm, broker-dealer and investment adviser specializing in 
working with troubled companies or their creditors to raise 
capital, divest businesses and restructure liabilities, whether 
in or outside bankruptcy.  Other financial advisory services 
provided by Hellmold Associates, Inc. include mergers and 
acquisitions advice, valuations, fairness opinions and expert 
witness testimony.  In addition to working with troubled 
companies or their creditors, Hellmold Associates, Inc. also acts 
as general partner of funds which invest in the securities of 
financially distressed companies.  

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

     Jonathan C. Kaledin, age 39, has been New York Regional 
Counsel of The Nature Conservancy, the international land 
conservation organization, since September 1995.  From 1990 to 
June 1995, he was founder and Executive Director of the National 
Water Funding Council ("NWFC"), an advocacy and public affairs 
organization representing municipalities, businesses, financial 
institutions and others on federal Clean Water Act and Safe 
Drinking Water Act funding issues.  Prior to forming the NWFC in 
1990, Mr. Kaledin was an attorney with the Boston law firm of 
Wright & Moehrke.  There he specialized in wetlands, water, 
environmental review, zoning and hazardous and solid waste 
matters, representing clients in state and federal court and 
before state and federal agencies and local boards and 
commissions.  From 1987 through 1990, Mr. Kaledin was Assistant 
Regional Counsel for the New England office of the Environmental 
Protection Agency ("EPA").  His responsibilities at the EPA 
included administrative and judicial environmental enforcement 
under the Clean Water Act and other federal water protection 
legislation.  Mr. Kaledin received his undergraduate degree magna 
cum laude from Harvard College and a law degree from New York 
University.  

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

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

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

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

     To the knowledge of the Trust, there were no violations of 
the reporting requirements of section 16(a) of the 1934 Act by 
officers and directors of the Trust in the last fiscal year.

(g)  RPMC.

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

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

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

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

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


th the text thereof, has been given to all Investors. 

     The executive officers of RPMC are Mr. Swanson (President), 
Mr. Gold (Executive Vice President), Mr. Brown (Senior Vice 
President and Chief Operating Officer), Mr. Quinn (Senior Vice 
President and Chief Financial Officer), Ms. Olin (Vice 
President), Mr. Heyison (Senior Vice President and General 
Counsel).   Douglas V. Liebschner, Vice President - Operations, 
is a key employee.  

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

Item 11.  Executive Compensation.

     Through 1995, the executive officers of the Trust and the 
Managing Shareholder were compensated by Ridgewood Energy.  The 
Trust was not charged for their compensation; the Managing 
Shareholder remitted a portion of the fees paid to it by the 
Trust to reimburse Ridgewood Energy for employment costs incurred 
on the Managing Shareholder's business.  Since 1996 the Managing 
Shareholder has compensated these persons without additional 
payments by the Trust and will be reimbursed by Ridgewood Energy 
for costs related to Ridgewood Energy's business.  The Trust will 
reimburse RPMC at allocable cost for services provided by RPMC's 
employees; no such reimbursement per employee exceeded $60,000 in 
1996 or 1997.  Information as to the fees payable to the Managing 
Shareholder and certain affiliates is contained at Item 13 -- 
Certain Relationships and Related Transactions.

     As compensation for services rendered to the Trust, pursuant 
to the Declaration, each Independent Trustee is entitled to be 
paid by the Trust the sum of $5,000 annually and to be reimbursed 
for all reasonable out-of-pocket expenses relating to attendance 
at Board meetings or otherwise performing his duties to the 
Trust.  Accordingly, in January 1998 the Trust paid each 
Independent Trustee $5,000 for his services.  The Board of the 
Trust is entitled to review the compensation payable to the 
Independent Trustees annually and increase or decrease it as the 
Board sees reasonable.  The Trust is not entitled to pay the 
Independent Trustees compensation for consulting services 
rendered to the Trust outside the scope of their duties to the 
Trust without prior Board approval.

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

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

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

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

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

Item 13.  Certain Relationships and Related Transactions.

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

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

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

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


<TABLE>
<CAPTION>
Fee                 Paid to        1997         1996         1995         1994

<S>              <C>           <C>        <C>          <C>          <C>        
Management         Managing     $ 766,866    $794,026     $482,000          $0
 fee              Shareholder

Cost 
 reimbursements*    RPMC       14,308,444  11,566,400            0           0

Investment         Managing             0           0      343,779     421,011
 fee              Shareholder

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

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

</TABLE>

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

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

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

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

PART IV

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

(a)  Financial Statements.

     See the Index to Financial Statements in Item 8 hereof.

(b)  Reports on Form 8-K.

     No Forms 8-K were filed with the Commission by the 
Registrant during the quarter ending December 31, 1997.

(c)  Exhibits

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

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

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

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

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

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

     10.E  Operation Agreement, dated as of April 16,            
1996, among Ridgewood/Providence Corporation,            
Ridgewood/Providence Power Partners, L.P. and            
Ridgewood Power Management Corporation.  Incorporated by 
reference to Exhibit 10E to Registrant's Annual Report on Form 
10-K for the year ended December 31, 1996.

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

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

     24.   Powers of Attorney                         Page 69

     27.   Financial Data Schedule                    Page 72

<PAGE>


SIGNATURES

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

Signature                      Title                        Date

RIDGEWOOD ELECTRIC POWER TRUST III (Registrant)

By:/s/ Robert E. Swanson    President and Chief    April 15, 1998
       Robert E. Swanson     Executive Officer

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

By:/s/ Robert E. Swanson    President and Chief    April 15, 1998
       Robert E. Swanson     Executive Officer

By:/s/ Martin V. Quinn      Senior Vice President and
       Martin V. Quinn   Chief Financial Officer   April 15, 1998

By:/s/ Kathleen P. McSherry     Controller         April 15, 1998
       Kathleen P. McSherry

RIDGEWOOD POWER CORPORATION  Managing Shareholder  April 15, 1998

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

     /s/ Robert E. Swanson  * Independent Trustee  April 15, 1998
        Ralph O. Hellmold 

    /s/ Robert E. Swanson     Independent Trustee  April 15, 1998
       Jonathan C. Kaledin 

*  As attorney-in-fact for the Independent Trustee


<PAGE>


Ridgewood Electric Power Trust III

Financial Statements

December 31, 1997, 1996 and 1995




















                             -F1-

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

[Letterhead of Price Waterhouse LLP]

Report of Independent Accountants       
April 2, 1998

To the Shareholders and Trustees of 
Ridgewood Electric Power Trust III

In our opinion, the accompanying balance sheets and the related statements of 
operations, changes in shareholders' equity and of cash flows present fairly, 
in all material respects, the financial position of Ridgewood Electric Power 
Trust III at December 31, 1997 and 1996, and the results of its operations and 
its cash flows for each of the three years in the period ended December 31, 
1997, in conformity with generally accepted accounting principles.  These 
financial statements are the responsibility of the Trust's management; our 
responsibility is to express an opinion on these financial statements based on 
our audits.  We conducted our audits of these statements in accordance with 
generally accepted auditing standards which require that we plan and perform 
the audit to obtain reasonable assurance about whether the financial 
statements are free of material misstatement.  An audit includes examining, on 
a test basis, evidence supporting the amounts and disclosures in the financial 
statements, assessing the accounting principles used and significant estimates 
made by management, and evaluating the overall financial statement 
presentation.  We believe that our audits provide a reasonable basis for the 
opinion expressed above.

As explained in Note 3, the financial statements include investments, valued 
at $24,613,978 and $28,158,835 (91% and 90% of shareholders' equity, 
respectively) as of December 31, 1997, and 1996, respectively, whose values 
have been estimated by management in the absence of readily ascertainable 
market values.  We have reviewed the procedures used by management in arriving 
at their estimate of value and have inspected underlying documentation, and, 
in the circumstances, we believe the procedures are reasonable and the 
documentation appropriate.  However, those estimated values may differ 
significantly from the values that would have been used had a ready market
for the investments existed, and the differences could be material to the 
financial statements.

/s/  Price Waterhouse LLP

                           -F2-

<PAGE>
Ridgewood Electric Power Trust III
Balance Sheet

                                                            December 31,
                                                     1997                1996
               
Assets:
Investments in power generation projects    $  24,613,978       $  28,158,835
Cash and cash equivalents                       2,687,626           2,959,240
Due from affiliates                                20,458               1,000
Deferred due diligence costs                          ---              30,000
Other assets                                       14,162             281,000
               
    Total assets                            $  27,336,224       $  31,430,075
               
Liabilities and Shareholders' Equity:               
               
Accounts payable and accrued expenses         $    38,537       $      41,136
Due to affiliates                                 340,373                 ---
   Total         liabilities                      378,910              41,136
               
Commitments and Contingencies

Shareholders' equity:               
Shareholders' equity
 (391.8444 shares issued
 and outstanding)                              27,018,776          31,406,084
Managing shareholder's
 accumulated deficit                              (61,462)            (17,145)
               
    Total shareholders' equity                 26,957,314          31,388,939
               
    Total liability and
     shareholders' equity                     $27,336,224       $  31,430,075
               
See accompanying notes to financial statements.

                               -F3-

<PAGE>

Ridgewood Electric Power Trust III
Statement of Operations

                                               Year Ended December 31,
                                     1997               1996             1995
Revenue:
 Income from power
  generation projects        $  4,075,390       $  3,525,613     $  1,317,287
 Interest and dividend
  income                          152,005            247,762        1,059,570
   Total revenue                4,227,395          3,773,375        2,376,857
               
Expenses:               
 Investment fee                       ---                ---          343,779
 Project due diligence
  costs                             3,692            258,378            8,210
 Management fee                   766,866            794,026          482,309
 Accounting and legal fees         46,869             48,231           90,043
 Miscellaneous                     22,203             18,012           11,966
 Writedown of investments in
  power generation projects     4,743,631            113,042              ---
   Total expenses               5,583,261          1,231,689          936,307
               
    Net income (loss)        $ (1,355,866)      $  2,541,686      $ 1,440,550

See accompanying notes to financial statements.

                                -F4-


<PAGE>
Ridgewood Electric Power Trust III
Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 1997, 1996 and 1995

                                                    Managing     
                             Shareholders        Shareholder            Total

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

Cash distributions             (3,045,001)           (30,758)      (3,075,759)

Net loss for the year          (1,342,307)           (13,559)      (1,355,866)

Shareholders' equity,
 December 31, 1997
 (391.8444 shares)            $27,018,776           $(61,462)     $26,957,314

See accompanying notes to financial statements.


                             -F5-

<PAGE>
Ridgewood Electric Power Trust III
Statement of Cash Flows

                                              Year Ended December 31,
                                     1997               1996             1995
Cash flows from
 operating activities:
  Net income (loss)         $  (1,355,866)     $   2,541,686    $   1,440,550
                  
Adjustment to reconcile
 net income (loss) to net
 cash provided by (used in)
 operating activities:                
  Writedown of power
   generation project
   investments                  4,743,631            113,042              ---
  Investment in working
   capital of power
   generation projects, net      (593,840)               ---              ---
  Capital expenditures for
   power generation projects   (1,369,934)               ---              ---
  Purchase of investments
   in power generation
   projects                      (135,000)        (7,279,299)     (20,884,493)
  Proceeds from sale or
   transfer of investment         900,000            353,619              ---

Changes in assets
 and liabilities:               
  Decrease (increase) in
   due to from affiliates         320,915           (109,085)        (299,194)
  Decrease (increase) in
   deferred due diligence costs    30,000            273,213         (140,683)
  Decrease (increase) in
   interest receivable                ---             51,233          (51,233)
  Decrease (increase) in
   other assets                   266,838           (140,041)        (135,959)
  Increase in accounts payable
   and accrued expenses        $   (2,599)        $  (85,731)     $   (61,347)
               
Total adjustments               4,160,011         (6,823,049)     (21,572,909)
                  
Net cash provided by (used in)
 operating activities           2,804,145         (4,281,363)     (20,132,359)
                             
Cash flows from financing
 activities:               
  Proceeds from shareholders'
   contributions                      ---                ---       17,527,545
  Selling commissions and
   offering costs paid                ---                ---       (2,332,545)
  Cash distributions to
   shareholders                (3,075,759)        (3,731,973)      (2,327,680)
Net cash provided by
 (used in) financing
 activities                    (3,075,759)        (3,731,973)      12,867,320 
               
                                -F6-

<PAGE>

Ridgewood Electric Power Trust III
Statement of Cash Flows (continued)


                                              Year Ended December 31,
                                     1997               1996             1995

Net decrease in
 cash and cash equivalents       (271,614)        (8,013,336)      (7,265,039)
               
Cash and cash equivalents,
 beginning of year              2,959,240         10,972,576       18,237,615
               
Cash and cash equivalents,
 end of year                $   2,687,626      $   2,959,240    $  10,972,576
               
See accompanying notes to financial statements.

                                 -F7-

<PAGE

Ridgewood Electric Power Trust III
Notes to Financial Statements

1.	Organization and Purpose

Nature of business

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

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

"Business Development Company" election

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

Summary of Significant Accounting Policies

Use of estimates

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

Investments in power generation projects

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

Revenue recognition

     Income from investments is recorded when distributions are declared.  
Interest income is recorded as earned.

Offering costs

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

                                   -F8-

<PAGE>

Ridgewood Electric Power Trust III
Notes to Financial Statements

Cash and cash equivalents

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

Due diligence costs relating to potential power project investments

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

Income taxes

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

Reclassifications

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

3.	Investments in Power Generation Projects

     The Trust had the following investments in power generation projects:

                            Fair Values as of December 31,
                                      1997            1996
   
JRW Associates, L.P.            $5,391,361      $5,305,298
Byron Power Partners, L.P.       2,824,156       3,138,072
Ridgewood Providence Power 
 Partners, L.P.                  7,504,792       7,167,242
On-site Cogeneration Projects:
 Ridgewood/Rhode Island PPLP           ---       3,722,618
 Ridgewood/Mass PPLP             3,731,067       3,223,881
 Ridgewood/Elmsford PPLP         1,756,416       1,430,136
 Other On-site Cogeneration 
  Project Partnerships           3,406,186       4,171,588
                               $24,613,978     $28,158,835

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

     On January 17, 1995, the Trust acquired 100% of the existing partnership 
interests of JRW Associates, L.P., which owns and operates an 8.5 megawatt 
("MW") electric cogeneration facility, located in Atwater, California.  The 
aggregate cost of the investment was $5,391,361 and $5,305,298 at December 31, 
1997 and 1996, respectively.  The Trust received distributions of $1,152,013, 
$779,409 and $982,076 from the project in 1997, 1996 and 1995, respectively.

                                   -F9-

<PAGE>

Ridgewood Electric Power Trust III
Notes to Financial Statements

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

     In January 1995, the Trust caused the formation of Byron Power Partners, 
L.P. in which the Trust owns 100% of the existing partnership interests.  On 
January 17, 1995, Byron Power Partners, L.P. acquired a 5.7 MW electric 
cogeneration facility, located in Byron, California.  As of December 31, 1997 
and 1996, the aggregate cost of the Trust's investment in the partnership was 
$2,824,156 and $3,138,072, respectively.  The Trust received distributions of 
$571,576, $428,540 and $335,211 from the project in 1997, 1996 and 1995, 
respectively.

Ridgewood Providence Power Partners, L.P. (known as the Providence Project)

     In 1996, Ridgewood Providence Power Partners, L.P. was formed as a 
Delaware limited partnership ("Providence Power").  The Trust owns a 35.7% 
limited partnership interest in Providence Power.  In addition, Ridgewood 
Providence Power Corporation was formed as a Delaware corporation ("RPPCorp.") 
and the Trust owns 35.7% of the outstanding common stock of RPPCorp., which is 
the sole general partner of Providence Power.  At  December 31, 1997 and 1996, 
the total cost of the Trust's investment was $7,504,792 and $7,167,242, 
respectively.

     On April 16, 1996, Providence Power purchased substantially all of the 
net assets of Northeastern Landfill Power Joint Venture.  The assets acquired 
included a 12.3 MW capacity electrical generating station, located at the 
Central Landfill in Johnston, Rhode Island (the "Providence Project").  In 
1997, the capacity was increased to 13.8 MW.  

     The Providence Project includes nine reciprocating electric generator 
engines which are fueled by methane gas produced and collected from the 
landfill.  The electricity generated is sold to New England Power Corporation 
under a long-term contract.  The purchase price was $15,533,021 in cash, 
including transaction costs and repayment of $3,000,000 of principal on senior 
secured non-recourse notes payable.  In addition, Providence Power assumed the 
obligation to repay the remaining principal outstanding of $6,310,404 on the 
senior secured non-recourse notes payable.

     Through ownership in RPPCorp. and Providence Power, the Trust owns 35.7% 
of the Providence Project.  The remaining 64.3% is owned by Ridgewood Electric 
Power Trust IV ("Trust IV").  Ridgewood Power Corporation is the managing 
partner of the Trust and Trust IV.  In 1997 and 1996, the Trust received 
distributions of $922,941 and $562,427, respectively, from the Providence 
Project.

On-site Cogeneration Projects

     On September 29, 1995, the Trust acquired a portfolio of 35 projects from 
affiliates of Eastern Utilities Associates ("EUA"), which sell electricity and 
thermal energy to industrial and commercial customers.  The projects are held 
in eight limited partnerships of which the Trust is the sole limited partner 
and is the sole owner of each of the general partners.  In the aggregate, the 
projects had 13.7 MW of base load and 5.7 MW of backup and standby capacity.  
The Trust paid a total of $11,300,000 for the projects and has invested 

                                    -F10-

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

additional amounts for rehabilitation, capital improvements and working 
capital.  EUA operated the projects under a transition agreement until January 
1, 1996, at which time Ridgewood Power Management Corporation ("RPMC"), an 
affiliate of the Trust, assumed operational control.  No distributions were 
made by these projects in 1995.  The Trust received distributions of 
$1,428,860 and $1,755,237 from these projects in 1997 and 1996, respectively.

Ridgewood/Rhode Island Power Partners L.P.

     Ridgewood/ Rhode Island Power Partners Limited Partnership (the 
"Partnership") leased three 1.4 MW Cooper Superior gas fired generator sets 
with heat recovery to a Rhode Island manufacturing company under a lease 
expiring in 2006.  Two engines were in regular use and one engine was on 
standby.  The partnership received a monthly fixed lease payment and a 
maintenance payment, which escalated over the term of the lease.  The 
Partnership was responsible for maintaining the engines and related equipment.  
At the expiration of the lease, the lessee had the right to purchase the 
equipment from the partnership for its fair market value.  As of December 31, 
1996, the total cost of the Trust's investment in the partnership was 
$3,722,618.  The Trust received distributions of $282,943 and $572,970 from 
the project in 1997 and 1996, respectively.

     During 1997, the lessee experienced severe financial difficulties and 
repeatedly defaulted on its payment obligations.  In response, the lessee 
alleged violations by the Partnership of the lease and requested renegotiation 
of the lease.  In the course of the negotiations, the lessee's principal 
creditor threatened to place the lessee in Chapter 11 bankruptcy, which would 
result in a cancellation of the lease.  In December 1997, the lessee purchased 
the facility (the "Worcester Project") and terminated the lease in exchange 
for a single cash payment of $900,000.  Accordingly, the Trust wrote down its 
investment in the Partnership and recorded a loss of $2,752,168.  See Note 6 - 
Arbitration and Litigation, for additional information relating to arbitration 
proceedings against EUA.

Ridgewood/Massachusetts Power Partners L.P.

     Ridgewood/ Massachusetts Power Partners L.P. (the "Partnership") owns two 
projects.  The first is a 3.5 MW base load, single cycle, dual-fuel, 
combustion turbine powered plant with a heat recovery steam generator which 
sells electric power and steam to a manufacturing facility on whose site the 
plant is located.  The project includes two 1.6 MW Caterpillar diesel engine 
generator sets to provide backup power.  The project sells electric and 
thermal energy to the manufacturing facility at the project's production cost 
(as defined in the Energy Service Agreement) plus a share of the savings (the 
difference between what the electric and thermal energy would have cost the 
company absent the cogeneration plant).  The Energy Service Agreement expires 
at the end of 2005.  As of  December 31, 1997 and 1996, the total cost of the 
Trust's investment in the partnership was $3,731,065 and $3,223,881 
respectively.  The Trust received distributions of $745,005 and $660,201 from 
the project in 1997 and 1996, respectively.  The Partnership also owns a 
smaller group of four cogeneration generator sets totaling 255 kilowatt ("KW") 

                                    -F11-


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

serving a residential complex in Worcester, Massachusetts.  The energy 
services agreement ("ESA") provides that the partnership receives from the 
customer the cost to purchase electricity and natural gas from the local 
utility, less a guaranteed savings based on the utility's current rates.  The 
ESA expires in 2004. 

Ridgewood/Elmsford Power Partners, L.P. 

     Ridgewood/Elmsford Power Partners, L.P. (the "Partnership") owns one 
cogeneration project consisting of two 665 KW (1,330 KW total) dual-fuel 
Cooper Superior engine generator sets with heat recovery and a Caterpillar 600 
kilowatt standby diesel generator set.  The Energy Location Services Agreement 
("ESA") expires in 2005 and provides that the Partnership receives its 
production costs (as defined in the ESA) plus a share of the excess of the 
customer's avoided cost over production costs.  As of December 31, 1997 and 
1996, the total cost of the Trust's investment in the partnership was 
$1,756,416 and $1,430,136, respectively.  The Trust received distributions of 
$292,543 and  $160,940 from the project in 1997 and 1996, respectively. 

The "Other On-site Cogeneration Project Partnerships"

     The "other on-site cogeneration project partnerships" include five 
partnerships, which owned 31 of the 35 projects acquired from Eastern 
Utilities Associates.  These 31 projects represented approximately one-third 
of the Trust's original investment in the on-site cogeneration projects.  All 
thirty-one were gas-fired cogeneration projects, located in California, 
Connecticut or New York.  Their energy service agreements had terms expiring 
between September 1996 and 2011.  The projects represented 5.5 MW of base load 
capacity.  The largest project was 660 KW or 12% of the capacity.  The 
projects ranged in size from 30 KW to 660 KW.  In 1996, the Trust wrote-off 
four small projects amounting to $113,042.  In 1997, the Trust wrote-off an 
additional fifteen projects with 2.1 MW of base load capacity amounting to 
$1,991,463.  The Trust received distributions of $108,369 and $361,126 from 
the projects in 1997 and 1996.  In September 1997, the Trust entered into an 
agreement with Alternate Energy Systems, Inc. ("AES") to invest in three co-
generation facilities operated by AES.  All three facilities are located in 
New York.  As of December 31, 1997 and 1996, the total cost of the Trust's 
investment in the other On-site Cogeneration Partnerships was $3,406,184 and 
$4,171,588, respectively.

California Pumping Project

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

4.	Transactions With Managing Shareholder And Affiliates

     The Trust also pays to the managing shareholder a distribution and 
offering fee up to 5% of each capital contribution made to the Trust.  The fee 
is intended to cover legal, accounting, consulting, filing, printing, 
distribution, selling and closing costs for the offering of the Trust.  

                                   -F12-

<PAGE>

Ridgewood Electric Power Trust III
Notes to Financial Statements

     For the year ended December 31, 1995, the Trust paid fees for these 
services to the managing shareholder totaling $860,195.  These fees were 
recorded as a reduction in shareholders' capital contributions.

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

     The Trust entered into a management agreement with the managing 
shareholder, under which the managing shareholder renders certain management, 
administrative and advisory services and provides office space and other 
facilities to the Trust.  As compensation to the managing shareholder, the 
Trust pays the managing shareholder an annual management fee equal to 2.5% of 
the net asset value of the Trust payable monthly upon the closing of the 
Trust.  For the years ended December 31, 1997, 1996 and 1995, the Trust paid 
management fees to the managing shareholder of $766,866, $794,026 and 
$482,309, respectively.

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

     Where permitted, in the event the managing shareholder or an affiliate 
performs brokering services in respect of an investment acquisition or 
disposition opportunity for the Trust, the managing shareholder or such 
affiliate may charge the Trust a brokerage fee.  Such fee may not exceed 2% of 
the gross proceeds of any such acquisition or disposition.  No such fees have 
been paid through December 31, 1997.

     The managing shareholder owns one share of the Trust with a cost of 
$84,000.  In conjunction with the offering of the Trust shares, commissions 
and placement fees of $390,844 were earned by Ridgewood Securities 
Corporation, an affiliate of the managing shareholder.

     Effective from January 1, 1996, under an operating agreement with the 
Trust, Ridgewood Power Management Corporation ("Ridgewood Management"), an 
entity related to the managing shareholder through common ownership, provides 
management, purchasing, engineering, planning and administrative services to 
the power generation projects operated by the Trust.  Ridgewood Management 
charges the projects at its cost for these services and for the allocable 
amount of certain overhead items.  Allocations of costs are on the basis of 
identifiable direct costs, time records or in proportion to amounts invested 
in projects managed by Ridgewood Management.

                                    -F13-

<PAGE>

Ridgewood Electric Power Trust III
Notes to Financial Statements

5.	Line of Credit Facility

     During the fourth quarter of 1997, the Trust and the Trust's principal 
bank executed a revolving line of credit agreement, whereby the bank will 
provide a three year committed line of credit facility of $750,000.  At 
December 31, 1997, there were no borrowing outstanding under the credit 
facility.  Outstanding borrowings bear interest at the bank's prime rate or, 
at the Trust's choice, at LIBOR plus 2.5%.  The credit agreement will require 
the Trust to maintain a ratio of total debt to tangible net worth of no more 
than 1 to 1 and a minimum debt service coverage ratio of 2 to 1.

6.	Arbitration and Litigation

     The Trust's subsidiaries that own the on-site cogeneration projects have 
brought an arbitration proceeding against Eastern Utilities Associates, Inc., 
the former owner.  The Trust has claimed that the former owner defrauded the 
Trust by misrepresenting the financial status of the Worcester Project and its 
customer and by making other material misrepresentations.  The Trust also has 
claimed that the former owner breached numerous representations and warranties 
in the acquisition agreement and violated fair trade practice laws.  The trust 
has demanded the return of the entire $11.5 million paid for the On-Site 
Cogeneration Projects and additional compensatory damages.  The former owner 
has counterclaimed for approximately $550,000 for alleged unpaid management 
services.  The parties have selected arbitrators, limited discovery is 
underway and the arbitration hearing is scheduled for June 1998.  The Trust 
has not reflected the amounts claimed in its financial statements pending the 
outcome of the arbitration proceeding.

     In February 1997, the Trust's subsidiaries that own the San Joaquin and 
Byron projects filed suit in the Superior Court of California against Pacific 
Gas and Electric Company ("PG&E") for breach of the power sales contracts.  
The Trust argues PG&E has improperly withheld approximately $164,000 of 
capacity payments and also has asked for declaratory relief to require PG&E to 
conform to the contracts' terms in the future.  PG&E has answered the 
complaint and has counterclaimed for all payments made to these projects.  The 
parties are in settlement negotiations which contemplate the payment to the 
Trust of most of its claims.  The Trust has not reflected the withheld 
capacity payments in its financial statements pending the outcome of the suit.

     On February 28, 1997 Michael Cutbirth, an individual, sued the Managing 
Shareholder in the Superior Court of California, Kern County, claiming 
unspecified damages (including a claim to an equity interest) for breach of an 
alleged confidentiality agreement relating to the acquisition of the San 
Joaquin and Byron Projects.  The Managing Shareholder has successfully removed 
the lawsuit to the United States District Court for the Eastern District of 
California.  Discovery has concluded and motions for summary judgment are 
pending.  The Managing Shareholder believes that it has ample defenses to Mr. 
Cutbirth's claims and it will defend the action vigorously.  If the Managing 
Shareholder were held liable to Mr. Cutbirth, the Trust might be obligated to 
indemmify the Managing Shareholder if the Managing Shareholder had acted in 
good faith and in the Trust's best interests and the conduct was neither 
negligence or misconduct.

                                 -F14-