SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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

Commission file number   0-21304

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


         Delaware                                 22-3206429
  (State or Other Jurisdiction            (I.R.S. Employer Identification No.)
of Incorporation or Organization)

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

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

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

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

Shares of Beneficial Interest
(Title of Class)


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

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

     There is no market for the Shares.  The aggregate capital 
contributions made for the Registrant's voting Shares held by 
non-affiliates of the Registrant at March 21, 1997 was 
$23,426,700.




Exhibit Index is located on Page 55.
<PAGE>

PART I

Item 1.  Business.

Forward-looking statement advisory

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

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

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

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

(a)  General Development of Business.

     Ridgewood Electric Power Trust II, the Registrant hereunder 
(the "Trust"), was organized as a Delaware business trust on 
November 20, 1992 to participate in the development, construction 
and operation of independent power generating facilities 
("Independent Power Projects" or "Projects").  Ridgewood Energy 
Holding Corporation ("Ridgewood Holding"), a Delaware 
corporation, is the Corporate Trustee of the Trust.

     The Trust sold whole and fractional shares of beneficial 
interest in the Trust ("Investor Shares") at $100,000 per 
Investor Share.  The Trust terminated its private placement 
offering of Shares (the "Offering") on January 31, 1994, at which 
time it had raised approximately $23.5 million.  Net of offering 
fees, commissions and expenses, the Offering provided 
approximately $19.4 million of net funds available for 
investments in the development and acquisition of Independent 
Power Projects.  The Trust has 479 record holders of Investor 
Shares (the "Investors").  As described below in Item 1(c)(2), 
the Trust (and its subsidiaries) have invested  its net funds in 
five Independent Power Projects.

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

     The Trust made an election to be treated as a "business 
development company" under the Investment Company Act of 1940, as 
amended ( the "1940 Act").  On February 27, 1993, the Trust 
notified the Securities and Exchange Commission of such election 
and registered the Investor Shares under the Securities Exchange 
Act of 1934, as amended (the "1934 Act").  On April 29, 1993, the 
election and registration became effective.

(b)  Financial Information about Industry Segments.

     The Trust operates in only one industry segment:  investing 
in independent power generation and similar energy projects.

(c)  Narrative Description of Business.

(1)  General Description.

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

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

     The Trust has invested approximately $16.1 million of its 
funds in five Projects:  (i) a waste-to-energy generating 
facility located in Pittsfield, Massachusetts (the "Berkshire 
Project"); (ii) a district cooling facility located in downtown 
San Diego, California, that supplies chilled water for office 
building central air conditioning systems (the "San Diego 
Project"); (iii) a municipal waste transfer station located in 
Columbia County, New York, near the Berkshire Project (the 
"Columbia Project"); (iv) a natural gas-fired cogeneration 
facility located in Monterey County, California (the "Monterey 
Project") and (v) various natural gas-fueled engines used to 
power irrigation well pumps in Ventura County, California (the 
"Sunkist Project").  The Trust has also invested approximately 
$331,000 to acquire, store and transport used electric power 
generation equipment for future use at its Projects. 

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

(2)  The Trust's Investments.

(i)  Berkshire Project.  

     On January 4, 1994, the Trust made an approximately $2.3 
million equity investment in a limited partnership, Pittsfield 
Investors Limited Partnership, formed to acquire the Berkshire 
Project, including the assets and business of Pittsfield Resource 
Recovery Facility, from Vicon Recovery Associates ("Vicon"), the 
developer and former operator of the facility.  The Berkshire 
Project is a waste to energy plant located in Pittsfield, 
Massachusetts, which is in the Berkshire Mountains, approximately 
150 miles west of Boston and 175 miles north of New York City.  
The facility, which has been operating since 1981, burns 
municipal solid waste supplied by the City of Pittsfield 
("Pittsfield"), surrounding communities and other providers.

     The Berkshire Project receives "tipping fees" paid by the 
waste suppliers based on the number of tons of waste delivered to 
the facility.  Tipping fees paid by Pittsfield are determined 
under a long-term waste supply agreement which will remain in 
effect until November 2004.  Tipping fees paid by other waste 
suppliers are based on the spot market (i.e., current market 
prices).  The facility generates additional revenue by selling 
steam produced from the waste burning process to a nearby paper 
mill owned by Crane & Co., Inc. ("Crane") under a long-term 
contract which will remain in effect until November 2004.  The 
Crane paper mill is the only facility in the United States which 
manufactures currency paper stock used to print United States 
currency (as well as currency paper stock for other governments). 
 Crane has had an exclusive currency contract for 114 years, 
although the U.S. Treasury is taking steps to create a competing 
supplier under legislation requiring the U.S. Government to 
create competition wherever possible.

     The Trust's partners in the Berkshire Project are 
subsidiaries of Energy Answers Corporation (collectively, "EAC"). 
 EAC made an equity investment of approximately $1.3 million in 
the Berkshire Partnership and also serves as manager and operator 
of the facility.  

     The investment structure affords the Trust a preferred 15% 
annual return on its investment plus a potential share of any 
additional cash flow.  More specifically, the Trust is entitled 
to an annual preferred distribution of available cash flow, 
representing revenue from the Berkshire Project, (after funding 
debt service, debt service reserves and operating and maintenance 
expenses) in an amount equal to 15% of its investment.  In the 
event that distributions are insufficient to pay the 15% 
preferred distribution in any given year, the shortfall will be 
payable out of distributions, if any, in subsequent years.  After 
the Trust has received its 15% preferred distribution in any 
given year, EAC is entitled to an annual management fee for 
operating and managing the facility in an amount equal to 
$300,000, escalating with inflation.  After these initial 
distributions have been made, the Trust is entitled to receive an 
additional amount equal to 5% of its investment and then EAC is 
entitled to receive an additional amount equal to 10% of the 
amount previously distributed to it.  Any remaining distributable 
cash flow for the year will be shared equally by the Trust and 
EAC.

     Ownership rights to the Berkshire Project are held under a 
long term lease purchase agreement and related non recourse 
industrial revenue bond financing agreements among the Berkshire 
Project, Pittsfield's industrial development authority and 
others. The remaining principal amount of the bonds was 
approximately $6.2 million at December 31, 1996.  In addition, 
the Berkshire Project is subject to additional subordinated debt 
obligations of approximately $1.8 million which were issued to 
Vicon in connection with the acquisition of the facility.

     Distributions to the Trust from the Berkshire Project in 
1996 totalled $351,000 (a 14.9% annual return), down from 
$447,000 in 1995 and $482,000 in 1994.  A decision to retain cash 
flow for capital expenditures, as described at Item 7 - 
Management's Discussion and Analysis of Results of Operations, 
caused the decrease from 1995 to 1996.

(ii)  Columbia Project.

     On August 31, 1994, the Trust entered into a partnership, B-
3 Limited Partnership with affiliates of EAC, the same firm with 
which the Trust participates in the Berkshire Project.  The Trust 
made an investment of approximately $4 million into the B-3 
Limited Partnership to construct a municipal waste transfer 
station located in Columbia County, New York.

     The purpose of a transfer station like the Columbia Project 
is to provide a facility where municipal waste collected from 
nearby towns by smaller, short haul trucks can be transferred to 
larger, long haul trucks for more efficient transportation of the 
waste to distant landfills. The primary customers for the 
Columbia Project are local waste haulers who dispose of waste at 
local landfills scheduled for closing under state and federal 
requirements.  Although one-year extensions of the closing 
deadlines for some local landfills have temporarily reduced 
anticipated demand at the facility, the process of closing many 
municipal landfills in the Albany area and the Berkshire region 
is expected to reduce the number of alternative disposal sites 
and increase the costs of alternative sites relative to the 
Columbia Project.  Although designed to operate as a stand-alone 
facility, the additional capacity of the Columbia Project may 
support expanded operations of the Berkshire Project.

     During the construction period, the Trust received interest 
on its investment at the rate of 12% per annum.  The Columbia 
Project commenced operations in January 1995.  The Trust is 
entitled to receive a cumulative priority return on the Trust 
investment of 18% per annum, with any shortfalls being carried 
forward into subsequent years.  Thereafter, EAC affiliates will 
be entitled to receive a management fee of $175,000 escalating 
with inflation.  Any additional cash flow will be split 50/50 
between the Trust and EAC affiliates.  Distributions to the Trust 
from the Columbia Project during 1996 totalled $515,000 
(approximately a 12.9% return).  For the period ended December 
31, 1995, the Trust had received approximately $510,000 in 
distributions from the Columbia Project.

(iii)  San Diego Project.

     On March 21, 1994, the Trust made an investment of 
approximately $2.3 million to acquire an 80% interest in a 
limited partnership, RSD Power Partners, L.P. (the "San Diego 
Partnership"), formed to acquire the San Diego Project, including 
the assets and business of San Diego Central Cooling Company, 
from a subsidiary of Pacific Generating Corporation, the former 
owner and operator of the limited partnership.  The Trust made 
additional capital contributions, totaling approximately $1.2 
million, to the San Diego Partnership to fund working capital and 
to purchase various leased equipment.  The San Diego Project has 
been in continuous operation since 1972 and currently sells 
chilled water to over 10 commercial, retail and government office 
buildings connected to the facility by a closed underground 
pipeline loop owned and used exclusively by the facility.  The 
San Diego Project is a fundamental part of the infrastructure of 
downtown San Diego in that the chilled water provided by the 
facility is used in the central air conditioning systems of a 
significant portion of the downtown commercial space.  The San 
Diego Project has 24 years remaining on its franchise with the 
City of San Diego for the continued use of the space beneath the 
city streets for the pipeline system.  The facility has the 
potential to substantially expand its number of customers and 
volume of chilled water sales.  The underground pipeline loop, 
which is approximately 2.5 miles in length, is capable of 
providing chilled water to 25 customers or more in a 50 block 
area.

     The Trust's partner in the San Diego Project is Wilton 
Technology Associates ("Wilton"), which is owned by Steven Jay 
Mueller.  The investment structure affords the Trust a preferred 
25% annual return on its investment plus a potential share of any 
additional net cash flow.  More specifically, the Trust is 
entitled to an annual preferred distribution of available cash 
flow attributable to the facility (after funding, operating and 
maintenance expenses and reserves) in an amount equal to 25% of 
its investment.  In the event that distributions are insufficient 
to pay the 25% preferred distribution in any given year, the 
shortfall will be payable out of any distributions in subsequent 
years.  After the Trust has received its 25% preferred 
distribution in any given year, Wilton will be entitled to 
receive any further distributions during the year until it has 
received an amount equal to 25% of the amount distributed to the 
Trust.  Thereafter, distributions will be shared on a basis of 
80% to the Trust and 20% to Wilton.  Wilton also managed the 
facility on a turnkey basis for a fixed payment of $100,000 per 
year, terminable annually by the Trust if performance targets 
were not met.  During 1996, the Trust's affiliate, Ridgewood 
Power Management Corporation ("RPMC"), began taking on 
responsibility for operation and maintenance and Wilton's 
activities were focused on marketing and expansion planning.

     Distributions to the Trust from the Project in 1996 totaled 
$618,000 (a 17.6% annual return on investment), down from 
$1,027,000 in 1995 and $435,000 in 1994.  The decrease reflected 
the loss of a significant customer, higher natural gas prices and 
a relatively cool summer.  In early 1997 the Trust entered into 
discussions with Wilton about modifying or terminating the 
management agreement and the prospects for obtaining additional 
customers (which might require a material expansion of the 
Project).

(iv)  Monterey Project.

     On January 9, 1995, the Trust purchased 100% of the equity 
interests in the Monterey Project, which is an operating 5.5 
megawatt cogeneration project located in the City of Salinas, 
Monterey County, California, for a cash purchase price of 
approximately $3.8 million plus the contribution of four 
engine/generator sets, valued at $1.3 million, which were owned 
by the Trust and cost approximately $1.6 million.  The Monterey 
Project has been operating since 1991 and uses natural gas fired 
reciprocating engines to generate electricity for sale to Pacific 
Gas and Electric Company under a long term contract (the "Power 
Contract").  Thermal energy from the Monterey Project is used to 
provide warm water to an adjacent greenhouse under a long term 
contract. For 1996, the Trust had received approximately $757,000 
in distributions (a 14.3% annual return) from the Monterey 
Project, up from $607,000 in 1995.  The Trust's investment in 
operating and maintenance improvements was the primary reason for 
the increase.

(v) Sunkist Project

     In March 1995, the Trust purchased 100% of the equity 
interests in the Sunkist Project, which is an irrigation service 
Project located in Ventura County, California, for a cash 
purchase price of approximately $732,000. The Trust has made 
additional investments of $220,000 to purchase additional engines 
and expand the Project.  The Sunkist Project has been operating 
since 1992 and uses natural gas fired reciprocating engines to 
provide power for irrigation wells which furnish water for 
orchards of lemon and other citrus trees.  The power is purchased 
by local farmers and farmers' co-operatives at a price which 
represents a discount from the equivalent price the customers 
would have paid to purchase electric power.  The Sunkist Project 
will provide power equivalent to approximately .3 megawatts. 

     The Trust has entered into a management contract with the 
prior operator of the Project based on the amount of pumping 
power provided by each engine, computed on the basis of the 
equivalent amount of kilowatt-hours of electricity that would 
have been needed to provide that amount of pumping power.  The 
Trust receives all cash flow from the engines up to $.02 per 
equivalent kilowatt-hour for the first 3,000 kilowatt-hours per 
year, and $.01 per additional kilowatt-hour in that year.  The 
operator, which is responsible for all operating costs, receives 
the remainder.  In 1996, the Project paid $129,000 to the Trust 
(a 13.6% annual return), up from $105,742 in 1995. 

(vi)  Discontinued Investments 

     The Trust made an investment of $811,000 in a partnership 
organized for the purpose of pursuing the acquisition of existing 
larger Projects.  The Trust also made equity investments of 
totalling $254,000 in two other partnerships organized for the 
purpose of pursuing the development and construction of larger 
Projects.  Despite substantial efforts, none of these 
partnerships produced an investment opportunity which was 
satisfactory to the Trust, and the Trust terminated its 
participation in these partnerships and wrote off those 
investments in December 1994.  Further, in 1994 the Trust wrote 
off an additional $332,000 with respect to development for a 
Project which failed to meet the requirements for construction.

     Additional information regarding the Projects is found in 
the Notes to the Financial Statements.


(3) Project Operations.

     The Monterey Project's revenue from its Power Contract 
consists of two components, energy payments and capacity 
payments.  Energy payments are based on a facility's net electric 
output, with payment rates usually indexed to the fuel costs of 
the purchasing utility or to general inflation indices.  Capacity 
payments are based on either a facility's net electric output or 
its available capacity.  Capacity payment rates vary over the 
term of a Power Contract according to various schedules.

     The San Diego Project sells its output to private customers 
under long-term contracts that have similarities to Power 
Contracts in that they provide for continuous sales and earnings 
over a sustained period of time.  However, the Trust may be at 
somewhat greater risk of default from these customers as compared 
to sales to utilities, which until recently had a relatively low 
risk of default.  Further, because customers have the option of 
installing or continuing to operate their own air conditioning 
and heating equipment, and because customers often prefer to 
operate themselves to assure control, it can be difficult to 
obtain new customers.

The Berkshire Project obtains waste for fuel under a long term 
contract providing it with revenues from tipping fees, which are 
subject to the default risks of dealing with municipalities and 
small trash haulers, and sells steam to Crane under a long-term 
contract. 

The Sunkist Project sells its power to the farmers on whose land 
its engines are situated under contracts terminable at any time 
on 60 days' prior notice to the Trust.  Although the Trust thus 
is at risk if many customers concurrently terminate contracts, as 
might happen if an electric utility or other supplier were to 
offer substantially discounted rates, the Trust believes that it 
is currently a competitive supplier even as California begins 
deregulation of electricity rates and that alternate customers 
can be secured in the event contracts are terminated.  The 
Columbia Project obtains its revenues from spot and contract 
sales of transfer station services which are dependent upon the 
volume of waste delivered to it and which are sensitive to the 
prices of alternative disposal methods and local economic 
activity.

     The major costs of a Project while in operation will be debt 
service (if applicable), fuel, taxes, maintenance and operating 
labor.  The ability to reduce operating interruptions and to have 
a Project's capacity available at times of peak demand are 
critical to the profitability of a Project.  Accordingly, skilled 
management is a major factor in the Trust's business.  The 
Berkshire, Columbia and Sunkist Projects are managed by the 
development companies that were responsible for developing those 
Projects, as described above.  Each development company also has 
an equity or an income interest in its Project subordinated to 
the Trust's preferred rights, which may create an additional 
incentive for the manager.  The Trust monitors their performance 
using its own personnel and outside consultants.  At the San 
Diego Project, a similar arrangement was in place, but the Trust 
has taken on the major portion of the operating and management 
responsibility beginning in 1996.

     The Trust has owned and managed the Monterey Project through 
a subsidiary since its acquisition in 1994.  The costs of 
operating this Project had been wholly borne by the Trust as 
operating expenses and have not been borne by the Managing 
Shareholder.  Effective January 1, 1996, the Managing Shareholder 
organized RPMC and has caused the Trust's subsidiaries to hire 
RPMC to provide management, purchasing, engineering, planning and 
administrative services for the Monterey Project and operating, 
administrative and maintenance functions for the San Diego 
Project.  RPMC also provides accounting support for the Sunkist 
Project.  The Managing Shareholder believes that for these 
Projects, where RPMC has necessary skills, having RPMC manage the 
Projects benefits the Trust by creating clear responsibilities 
and by capturing the profit component of the management contract 
for the Trust. 

     See Item 10 - Directors and Officers and Item 13 - Certain 
Relationships and Related Transactions for further information 
regarding RPMC and for the cost reimbursements received by RPMC.

     Electricity produced by a Project is typically delivered to 
the purchaser through transmission lines which are built to 
interconnect with the utility's existing power grid.  Chilled 
water produced by the San Diego Project and steam produced by the 
Berkshire Project are conveyed directly to the user by pipeline 
and the energy produced by the engines in the Sunkist Project is 
applied directly to pumps.  

     The overall demand for electrical energy is somewhat 
seasonal, with demand usually peaking in the summertime as a 
result of the increased use of air conditioning.  Greenhouse 
demand for hot water from the Monterey Project peaks in the 
winter and spring months, while demand for the San Diego 
Project's chilled water for building cooling peaks in the summer 
and early fall.  The impact of fluctuations in the demand or 
supply of electrical or thermal products generated upon the 
revenues of any particular Project is usually dependent on the 
terms of the Power Contract pursuant to which the energy is 
purchased.

     Generally, revenues from the sales of electric energy from a 
cogeneration facility will represent the most significant portion 
of the facility's total revenue.  However, to maintain its status 
as a Qualifying Facility under PURPA, it is imperative that the 
Monterey Project continue to satisfy PURPA cogeneration 
requirements as to the amount of thermal products generated.  
Therefore, since the Monterey Project has only two customers (the 
electric energy purchaser and the thermal products purchaser), 
loss of either of these customers would probably have a material 
adverse effect on the Project.

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

     Hydrocarbon fuels, such as natural gas, coal and fuel oil, 
have been generally available in recent years for use by 
Independent Power Projects, although there have been serious 
supply impairments for both oil and natural gas at times during 
the last 20 years.  Market prices for natural gas, oil and, to a 
lesser extent, coal have fluctuated significantly over the last 
few years.  See Item 7 - Management's Discussion and Analysis of 
Results of Operation for additional information regarding the 
effects of natural gas price increases on certain Projects owned 
by the Trust.  Such fluctuations may directly inhibit the 
development of Projects because of the anticipated effects on 
Project profitability and may deter lenders to Projects or result 
in higher costs of financing. The Berkshire Project uses 
municipal wastes as fuel and the Columbia Project charges on the 
basis of volume of waste.  The availability of spot waste (waste 
delivered otherwise than under contract) depends on the costs of 
other disposal alternatives.

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

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

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


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

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

Continued Deregulation of the Generating Market.  

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

Wholesale-level Access to Transmission Capacity.  

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

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

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

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

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

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

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

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

Proposals to Modify PURPA and Existing Power Contracts.

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

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

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

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


Retail-level Competition

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

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

Initial Effects of Trends

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

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

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

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

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

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

5.  Competition

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

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

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

6.  Regulatory Matters.

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

(i)  Energy Regulation.

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

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

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

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

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

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

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

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

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

(ii)  Environmental Regulation.

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

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

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

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

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

(iii)  The 1940 Act

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

     On February 27, 1993, the Trust notified the Securities and 
Exchange Commission (the "Commission") of its election to be a 
"business development company" and registered its Shares under 
the 1934 Act.  On April 29, 1993, the election and registration 
became effective.  As a "business development company," the Trust 
is a closed-end company (defined by the 1940 Act as a company 
that does not offer for sale or have outstanding any redeemable 
security) that is regulated under the 1940 Act only as a business 
development company.  The act contains prohibitions and 
restrictions on transactions between business development 
companies and their affiliates as defined in that act, and 
requires that a majority of the board of the company be persons 
other than "interested persons" as defined in the act.  The board 
of the Trust is comprised of Ridgewood Power and two individuals, 
Ralph O. Hellmold and Jonathan C. Kaledin, who also serve as 
independent trustees of Ridgewood Electric Power Trust III, and 
who are Independent Panel Members for Ridgewood Electric Power 
Trust V but who are not otherwise affiliated with the Trust, 
Ridgewood Power or any of their affiliates.  See Item 10 - 
Directors and Executive Officers of the Registrant.

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

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

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

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

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

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

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

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

(iv)  Potential Legislation and Regulation.

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

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

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

(e)  Employees.

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

Item 2.  Properties.

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

     The following table shows the material properties (relating 
to Projects) owned or leased by the Trust's subsidiaries or 
partnerships in which the Trust has an interest.  Ownership 
rights to the property associated with the Berkshire Project are 
held under a long-term lease-purchase agreement and related non-
recourse industrial revenue bond financing agreements among the 
City of Pittsfield's industrial development authority and others. 
 Upon repayment of the bonds and the satisfaction of other 
conditions, the partnership which operates the facility and in 
which the Trust owns an interest, will have the option to acquire 
the facility for nominal consideration.  The other properties are 
not subject to any mortgages, liens or encumbrances.  All of the 
Projects are described in further detail at Item 1(c)(2).

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

Berkshire   Pittsfield, 
            Massachusetts  Leased  2004         5        30,000      Waste-to-
                                                               energy facility
                                                                  in operation
San Diego   San Diego,
            California     Leased  2023         .3       12,000      Gas-fired
                                                                power facility
                                                                  in operation 
                                                                which produces 
                                                                 chilled water 
                                                                for customers' 
                                                               office building 
                                                                   central air 
                                                                  conditioning 
                                                                       systems
Columbia    Columbia,
            New York       Owned   __           44       25,000      Municipal 
                                                                         waste 
                                                                      transfer 
                                                                    station in 
                                                                     operation
Monterey    Monterey,
            California     Leased  2021          2       10,000      Gas-fired 
                                                                  cogeneration 
                                                                      facility
Sunkist     Ventura        Leased  N/A         N/A        N/A          Natural
            County,         or                                       gas fired
            California     licensed                                    engines
                                                                      powering 
                                                                    irrigation 
                                                                 pumps located 
                                                                    on various 
                                                                         farms


Item 3.  Legal Proceedings.

     There are no legal proceedings involving the Trust.

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

     The Trust did not submit any matters to a vote of the 
Investors during the fourth quarter of 1996. 
PART II

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

(a)  Market Information.  

     The Trust sold 235.3775 Investor Shares of beneficial 
interest in the Trust in its private placement offering of 
Investor Shares which closed on January 31, 1994.  There is 
currently no established public trading market for the Investor 
Shares and the Trust does not intend to allow a public trading 
market to develop.  As of the date of this Form 10-K, all such 
Investor Shares have been issued and are outstanding.  There are 
no outstanding options or warrants to purchase, or securities 
convertible into, Investor Shares and the Trust has no intention 
to make any public offering of Investor Shares.

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

(b)  Holders

     As of the date of this Form 10-K, there are 479 record 
holders of Investor Shares.

(c)  Dividends

     The Trust made distributions as follows for the years 1994 
through 1996:


                     Year ended      Year ended        Year ended
                     December 31,    December 31,    December 31,
                       1996            1995             1994

Total distributions
 to Investors          $2,082,754      $2,457,231      $1,243,907
Distributions per
 Investor Share             8,924          10,450           5,285
Distributions to
 Managing Shareholder     $21,037          24,807          11,626


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

     Subject to the other factors described in this Annual Report 
on Form 10-K, the Trust's goal is to provide Investors with 
annual distributions of net cash flow, as defined in the 
Declaration of Trust, of 15% of their Capital Contributions to 
the Trust.  Because the Trust's objective is to distribute net 
cash flow, a substantial portion of many distributions will 
include cash flow that represents depreciation and amortization 
charges against assets at the Project level.  Nevertheless, 
because the Projects are not consolidated with the Trust for 
accounting purposes, all funds received from Projects are 
considered to be revenue to the Trust for accounting purposes.  
Occasionally, distributions may also include funds derived from 
operating or debt service reserves, Trust-level depreciation or 
amortization, or other non-cash charges against earnings.  For 
purposes of generally accepted accounting principles, amounts of 
distributions in excess of accounting income may be considered to 
be capital in nature.  Investors should be aware that the Trust 
is organized to return net cash flow rather than accounting 
income to Investors.

Item 6.  Selected Financial Data.

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


Supplemental Information  As of and     As of and    As of and       As of and
 Schedule                  for the       for the      for the          for the
Selected Financial Data   Year Ended    Year Ended   Year Ended     Year Ended
                        December 31,  December 31,  December 31,  December 31,
                           1996          1995          1994           1993

Total Fund Information:
Net revenue from
 operating projects     $2,371,208     $2,696,578     $916,588             $0
Net income (loss)        1,970,401      2,149,184   (1,698,844)      (444,284)
Net assets
 (shareholders'
 equity)                16,353,759     16,477,149   16,760,003     15,163,680
Investments in
 Project development 
 and power
 generation limited
 partnerships           16,116,582     16,056,151    9,236,653      1,443,119
Total assets            16,466,241     16,521,944   16,791,571     15,792,506
Per Investor Share:
  Revenues                 $10,076        $11,456       $3,894           $397
  Expenses                   1,705          2,473       12,368         (2,285)
  Net income (loss)          8,371          9,131      $(7,218)       $(1,888)
  Net asset value           69,639         70,158      $71,345        $64,380
Distributions to
 Investors                  $8,849        $10,440       $5,285             $0

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

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

Results of Operations.

Income of the Trust from Projects was as follows:

Project                 1996          1995            1994
Berkshire           $351,451      $446,888        $481,588
Columbia             515,000       510,000               0
San Diego            618,080     1,027,412         435,000
Monterey             757,498       606,536               0
Sunkist              129,179       105,742               0

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

     Net income for 1996 was $1,970,000, which was $179,000 
(8.3%) less than the $2,149,000 recorded in 1995.  There was a 
$360,000 decline in revenues (13.2%) from 1995 to 1996, which was 
partially offset by a $181,000 (31.1%) decrease in Trust expenses 
from 1996 to 1995.

     The decline in revenues was primarily the result of a 
$409,000 (39.8%) decrease in distributions from the San Diego 
Project.  A major customer, the old San Diego County Courthouse 
was closed in early 1996 and replacement customers have not been 
obtained, although the Project is in active discussions with 
several office building owners and developers.  Cool summer 
weather also reduced demand.  The Trust's other Projects had 
mixed results.  The Berkshire Project's distributions declined 
$95,000, reflecting its management's decision to retain cash flow 
at the Project level to fund capital expenditures, while 
increases in operating efficiencies and preventative maintenance 
caused the Monterey Project's distributions to increase by 
$51,000.  The Columbia and Sunkist Projects' distributions 
remained approximately level.  Because substantially all Trust 
cash flow was distributed, interest and dividend income was 
nominal in 1996.

     The major element of the decline in Trust expenses was a 
$165,000 (33.4%) decrease in the management fee caused by the 
Managing Shareholder's decision to waive a portion of its fees.  
Accounting and legal expenses fell by $27,000 (45.6%), although 
adoption of a comprehensive insurance program caused insurance 
expenses to increase by $22,000 (608.4%).

     12 months ended December 31, 1995 versus 12 months ended 
December 31, 1994.
     Net income for calendar 1995 was $2,149,000 as compared to a 
net loss of $1,699,000 for 1994.  The improvement came from both 
revenue and expense items.  Gross revenue increased $1,520,000 
(125.3%) as Trust investments were acquired and began earning 
income, while operating expenses decreased by $2,329,000 (80.0%) 
as expenditures for project due diligence ended and no additional 
writedowns of Trust assets were incurred. 
     Income from Projects rose by 194.2% from 1994 to 1995, as 
the Trust enjoyed a full year of income from the Columbia and San 
Diego Projects (which were acquired in 1994) and the Monterey and 
Sunkist Projects were acquired.  Interest and dividend revenues 
in 1995 decreased by 93.8%, attributable to the application of 
the Trust's remaining uninvested funds to purchasing the Monterey 
and Sunkist Projects.  
     The 80.0% decrease in operating expenses was primarily 
caused by a $510,000 decrease (97.5%) in due diligence expenses 
for Project investments, which reflects the conclusion of the 
Trust's investment program. No writedowns were recorded in 1995, 
as opposed to $1,697,000 in 1994.  No investment fee was charged 
in 1995 because the Trust's offering had concluded, which 
resulted in a $59,000 decrease in expenses.  Equipment storage 
also decreased by $55,000 as purchased equipment was installed 
and left storage, and insurance costs decreased by $9,000 as the 
result of a consolidation of coverage.  

Liquidity and Capital Resources.

     The Trust has completed the investment of its funds and does 
not contemplate that it will make any significant capital 
investments from Trust-level funds in 1997.  However, significant 
capital improvements, which are being financed from Project cash 
flow, are underway at the Berkshire Project to improve ash 
handling and allow use of ash as aggregate for concrete block 
production.  The Trust is also considering expansions to the San 
Diego Project in order to extend its lines to additional 
customers and possibly to increase capacity, but no decision has 
been made to do so.  The Trust may also undertake additional 
repairs to and improvements to the Monterey Project as may be 
determined by an engineering study in progress, and routine 
maintenance expenses for the San Diego Project.  The Trust 
expects to fund these from cash reserves or current operating 
cash flow.  

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

     In addition to the industry trends discussed above at Item 
1(c)(4) - Business --Trends in the Electric Utility and 
Independent Power Industries, as described above several of the 
Trust's Projects are experiencing significant pressures on their 
profitability and operations.  Recent increases in natural gas 
prices during the winter months of 1996 and early 1997 impaired 
profitability at the Monterey, Sunkist and San Diego Projects, 
although prices began to fall toward prior levels in February 
1997.  The Managing Shareholder is considering entering into 
long-term gas supply arrangements to reduce exposure to these 
fluctuations, but the relatively small size of each Project may 
limit its ability to do so. 

Item 8.  Financial Statements and Supplementary Data.

Index to Financial Statements

Report of Independent Accountants                            F-2
Statement of Operations For
 the Three Years Ended December 31, 1996                     F-3
Balance Sheet at December 31, 1996 and 1995                  F-4
Statement of Changes in Shareholders'
 Equity For the Three Years
 Ended December 31, 1996                                     F-5
Statement of Cash Flows For the
 Three Years Ended December 31, 1996                         F-6
Notes to Financial Statements                        F-7 to F-10

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

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

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

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

PART III

Item 10.  Directors and Executive Officers of the Registrant.

(a)  General.

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

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

(b)  Managing Shareholder.

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

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

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

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

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

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

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

     Martin V. Quinn, age 48, assumed the duties of Chief 
Financial Officer of the Managing Shareholder, the Trust, the 
other four trusts organized by the Managing Shareholder and RPMC 
in November 1996.  Under a consulting arrangement, Mr. Quinn will 
devote a majority of his time to the business of the Managing 
Shareholder and RPMC while continuing his other activities, which 
are expected to conclude in the spring of 1997.  Thereafter, he 
expects to become a full-time officer of the Managing Shareholder 
and RPMC.  

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

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

(c)  Management Agreement.

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

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

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

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

(d)  Executive Officers of the Trust.

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

(e)  The Trustees.

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

     The Independent Trustees of the Trust are Ralph O. Hellmold 
and Jonathan C. Kaledin.  Set forth below is certain information 
concerning Mr. Hellmold and Mr. Kaledin, who also serve as 
independent trustees of Ridgewood Power III and as independent 
panel members of Ridgewood Power V.  Both are independent power 
programs sponsored by Ridgewood Power. Independent panel members 
must approve transactions between their program and the Managing 
Shareholder or companies affiliated with the Managing 
Shareholder, but have no other responsibilities.  Neither Mr. 
Hellmold nor Mr. Kaledin is otherwise affiliated with the Trust, 
any of the Trust's officers or agents, the Managing Shareholder, 
any other Trustee, any affiliates of the Managing Shareholder and 
any other Trustees, or any director, officer or agent of any of 
the foregoing.  Mr. Hellmold made a late filing in March 1997 
under Section 16 of the 1934 Act to report director status and 
beneficial ownership of Investor Shares.

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

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

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

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

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

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

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

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

(g)  RPMC.

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

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

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

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

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

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

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

Item 11.  Executive Compensation.

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

     As compensation for services rendered to the Trust, pursuant 
to the Declaration, each Independent Trustee is entitled to be 
paid by the Trust the sum of $5,000 annually and to be reimbursed 
for all reasonable out-of-pocket expenses relating to attendance 
at Board meetings or otherwise performing his duties to the 
Trust.  Accordingly, in January 1996 the Trust paid each 
Independent Trustee $5,000 for his services.  The Board of the 
Trust is entitled to review the compensation payable to the 
Independent Trustees annually and increase or decrease it as the 
Board sees reasonable.  The Trust is not entitled to pay the 
Independent Trustees compensation for consulting services 
rendered to the Trust outside the scope of their duties to the 
Trust without prior Board approval.

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

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

     The Trust sold 235.3775 Investor Shares (approximately $23.5 
million of gross proceeds) of beneficial interest in the Trust 
pursuant to a private placement offering under Rule 506 of 
Regulation D under the Securities Act.  The offering closed on 
January 31, 1994.  Further details concerning the offering are 
set forth above at Item 1 -- Business.

     The Managing Shareholder  purchased for cash in the offering 
1.45 Investor Shares (.6 of 1% of the outstanding Investor 
Shares).  Ralph O. Hellmold, an Independent Trustee of the Trust, 
purchased for cash in the offering one-half of a full Investor 
Share.  By virtue of their purchases of Investor Shares, the 
Managing Shareholder and Mr. Hellmold are entitled to the same 
ratable interest in the Trust as all other purchasers of Investor 
Shares.  No other Trustees or executive officers of the Trust 
acquired Investor Shares in the Trust's offering.

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

Item 13.  Certain Relationships and Related Transactions.

     The Declaration provides that cash flow of the Trust, less 
reasonable reserves which the Trust deems necessary to cover 
anticipated Trust expenses, is to be distributed to the Investors 
and the Managing Shareholder (collectively, the "Shareholders"), 
from time to time as the Trust deems appropriate.  Prior to 
Payout (the point at which Investors have received cumulative 
distributions equal to the amount of their capital 
contributions), each year all distributions from the Trust, other 
than distributions of the revenues from dispositions of Trust 
Property, are to be allocated 99% to the Investors and 1% to the 
Managing Shareholder until Investors have been distributed during 
the year an amount equal to 15% of their total capital 
contributions (a "15% Priority Distribution"), and thereafter all 
remaining distributions from the Trust during the year, other 
than distributions of the revenues from dispositions of Trust 
Property, are to be allocated 80% to Investors and 20% to the 
Managing Shareholder.  Revenues from dispositions of Trust 
Property are to be distributed 99% to Investors and 1% to the 
Managing Shareholder until Payout.  In all cases, after Payout, 
Investors are to be allocated 80% of all distributions and the 
Managing Shareholder 20%.    

     For any fiscal period, the Trust's net profits, if any, 
other than those derived from dispositions of Trust Property, are 
allocated 99% to the Investors and 1% to the Managing Shareholder 
until the profits so allocated offset (1) the aggregate 15% 
Priority Distribution to all Investors and (2) any net losses 
from prior periods that had been allocated to the Shareholders.  
Any remaining net profits, other than those derived from 
dispositions of Trust Property, are allocated 80% to the 
Investors and 20% to the Managing Shareholder.  If the Trust 
realizes net losses for the period, the losses are allocated 80% 
to the Investors and 20% to the Managing Shareholder until the 
losses so allocated offset any net profits from prior periods 
allocated to the Shareholders.  Any remaining net losses are 
allocated 99% to the Investors and 1% to the Managing 
Shareholder.  Revenues from dispositions of Trust Property are 
allocated in the same manner as distributions from such 
dispositions.  Amounts allocated to the Investors are apportioned 
among them in proportion to their capital contributions. 

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

     In 1995, 1994 and 1993, the Trust made distributions to the 
Managing Shareholder (which is a member of the Board of the 
Trust) as stated at Item 5 - Market for Registrant's Common 
Equity and Related Stockholder Matters.  In addition, the Trust 
paid fees to the Managing Shareholder and its affiliates as 
follows:

Fee              Paid to           1996         1995        1994         1993
Management       Managing
 fee             Shareholder    $328,952     $494,000    $495,000          $0
Cost
 reimburse-
 ments*          RPMC          1,207,252            0           0           0
Investment       Managing
 fee             Shareholder           0            0      59,000     388,000
Placement        Ridgewood
 agent fee       Securities
 and sales       Corporation
 commissions                           0            0       4,000     245,000
Organizational,  Managing
 distribution    Shareholder
 and offering
 fee                                   0            0     149,000   1,014,000

* Prior to 1996, these costs were either absorbed by the Trust or by the 
Projects directly.  These include all payroll, fuel and other expenses of 
operating Projects that are not operated by non-affiliated managers, and an
allocation of RPMC's overhead costs.

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

     The management fee, payable monthly under the Management 
Agreement at the annual rate of 2.5% of the Trust's net asset 
value, began on the date the first Project was acquired and 
compensates the Managing Shareholder for certain management, 
administrative and advisory services for the Trust.

     In addition to the foregoing, the Trust reimbursed the 
Managing Shareholder at cost for expenses and fees of 
unaffiliated persons engaged by the Managing Shareholder for 
Trust business and in years before 1996 for payroll and other 
costs of operation of the Monterey and Sunkist Projects. In 1996, 
these reimbursements were paid to RPMC.  The reimbursements to 
RPMC, which do not exceed its actual costs and allocable 
overhead, are described at Item 10(f) - Directors and Executive 
Officers of the Registrant -- RPMC.

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


PART IV

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

(a)  Financial Statements.

     See the Index to Financial Statements in Item 8 hereof.

(b)  Reports on Form 8-K.

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

(c)  Exhibits

     3A.  Certificate of Trust of the Registrant, is incorporated 
          by reference to Exhibit 3A to the Registrant's 
          Registration Statement on Form 10 filed with the 
          Commission on February 27, 1993.

     3B.  Amended and Restated Declaration of Trust of the 
          Registrant, is incorporated by reference to Exhibit 4 
          to the Quarterly Report on Form 10Q of the Registrant 
          for the quarter ended September 30, 1993.

     10A.  Management Agreement dated as of January 4, 1993 
           between the Registrant and Ridgewood Power 
           Corporation, is incorporated by reference to Exhibit 
           10 to the Registrant's Registration Statement on Form 
           10 filed with the Commission on February 27, 1993.

     10B.  Limited Partnership Agreement of Pittsfield Investors 
           Limited Partnership (without exhibits), is 
           incorporated by reference to Exhibit 2(i) to the Form 
           8-K of Registrant filed with the Commission on January 
           19, 1994.

     10C.  Asset Purchase Agreement between EAC Systems, Inc. and 
           Vicon Recovery Associates ("Vicon") dated as of 
           December 23, 1992 (the "Asset Purchase Agreement") 
           (without exhibits), is incorporated by reference to 
           Exhibit 2(ii) to the Form 8-K of Registrant filed with 
           the Commission on January 19, 1994.

     10D.  First Amendment of Asset Purchase Agreement dated as 
           of December 30, 1993 (without exhibits), is 
           incorporated by reference to Exhibit 2(ii) to the Form 
           8-K of Registrant filed with the Commission on January 
           19, 1994.

     10E.  Lease dated as of September 1, 1979 between the City 
           of Pittsfield, Massachusetts (acting by and through 
           its Industrial Development Financing Authority), is 
           incorporated by reference to Exhibit 2(iv) to the Form 
           8-K of Registrant filed with the Commission on January 
           19, 1994.

     10F.  Amended and Restated Solid Waste Disposal and Resource 
           Recovery Agreement dated August 6, 1979 by and among 
           the City of Pittsfield, Vicon and others (together 
           with amendments dated October 26, 1984, July 28, 1989 
           and December 29, 1993), is incorporated by reference 
           to Exhibit 2(v) to the Form 8-K of Registrant filed 
           with the Commission on January 19, 1994.

     10G.  Steam Purchase Agreement by and between Crane & Co., 
           Inc. and Vicon dated as of February 1, 1979 (with 
           amendments), is incorporated by reference to Exhibit 
           2(vi) to the Form 8-K of Registrant filed with the 
           Commission on January 19, 1994.

     10H.  Asset Purchase Agreement dated as of December 15, 1993 
           between San Diego Central Cooling Company ("SDCCC") 
           and RSD Power Partners, L.P. is incorporated by 
           reference to Exhibit 10M to the Form 10K of Registrant 
           filed with the Commission on March 30, 1994.

     10I.  RSD Power Partners, L.P. Agreement of Limited 
           Partnership dated as of January 7, 1994 is 
           incorporated by reference to Exhibit 10N to the form 
           10K of Registrant filed with the Commission on March 
           30, 1994.

     10J.  Lease dated June 7, 1983 between San Diego Gas & 
           Electric Company ("SDG&E") and Applied Energy, 
           Incorporated ("AEI") is incorporated by reference to 
           Exhibit 10O to the Form 10K of Registrant filed with 
           the Commission on March 30, 1994.

     10K.  Assignment and Consent among AEI, Energy Factors, 
           Incorporated, SDCCC and SDG&E is incorporated by 
           reference to Exhibit 10P to the form 10K of Registrant 
           filed with the Commission on March 30, 1994.

     10L.  Memorandum and Lease and Assignment of Lease dated as 
           of July 3, 1989 among SDG&E, AEI and SDCCC is 
           incorporated by reference to Exhibit 10Q to the form 
           10K of Registrant filed with the Commission on March 
           30, 1994.

     10M.  Letter Agreement dated July 7, 1989 between Energy 
           Factors Incorporated and SDG&E is incorporated by 
           reference to Exhibit 10R to the form 10K of Registrant 
           filed with the Commission on March 30, 1994.

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

     10O.  Acquisition Agreement, dated as of March 31, 1995, by 
           and among the Trust and its subsidiary, Pump Services 
           Corporation, as purchasers and Donald C. Stewart, 
           Union Energy Corp. and Donald A. Sherman as sellers.  
           Incorporated by reference to Exhibit 10O to the Annual 
           Report on Form 10-K of the Registrant for the year 
           ended December 31, 1995.

     21.   Subsidiaries of the Registrant.  Incorporated by 
           reference to Exhibit 21 to the Annual Report on Form 
           10-K of the Registrant for the year ended December 31, 
           1996.

     24.   Powers of Attorney                        Page 72

     27.   Financial Data Schedule                   Page 73


SIGNATURES

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

Signature                         Title                     Date

RIDGEWOOD ELECTRIC POWER TRUST II
 (Registrant)


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


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


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


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


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

RIDGEWOOD POWER CORPORATION  Managing Shareholder  April 14, 1997

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



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


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


*  Robert E. Swanson, as attorney-in-fact for the Independent 
Trustee

<PAGE>










Ridgewood Electric Power Trust II

Financial Statements

December 31, 1996, 1995 and 1994
















                              -F1-


<PAGE>




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

Report of Independent Accountants

March 24, 1997

To the Shareholders and Trustees of 
Ridgewood Electric Power Trust II

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

As explained in Note 4, the financial statements include 
investments, valued at $16,116,582 and $16,056,151 (99% and 97% 
of shareholders' equity, respectively) as of December 31, 1996 
and 1995, respectively, whose values have been estimated by 
management in the absence of readily ascertainable market values. 
 We have reviewed the procedures used by management in arriving 
at their estimate of value and have inspected underlying 
documentation, and, in the circumstances, we believe the 
procedures are reasonable and the documentation appropriate.  
However, because of the inherent uncertainty of valuation, those 
estimated values may differ significantly from the values that 
would have been used had a ready market for the investments 
existed, and the differences could be material to the financial 
statements.

/s/  Price Waterhouse LLP
                            -F2-
<PAGE>
Ridgewood Electric Power Trust II
Statement of Operations

                               Year Ended         Year Ended       Year Ended
                             December 31,       December 31,     December 31,
                                     1996               1995             1994


Revenue:
 Income from power
  generating projects        $  2,371,208       $  2,696,578      $   916,588
 Interest and dividend
  income                              540             18,401          295,623
 Other income                         ---             16,325              ---

                                2,371,748          2,731,304        1,212,211

               
Expenses:               
 Investment fee                       ---                ---           59,400
 Project due diligence
  costs                               ---             13,068          523,104
 Management fee                   328,952            494,023          494,820
 Equipment storage costs              ---              1,755           56,700
 Accounting and legal fees         31,750             58,331           54,698
 Insurance                         25,501              3,600           12,450
 Writedown of limited
  partnership investments             ---                ---        1,397,350
 Writedown of electric
  power equipment                     ---                ---          299,940
 Miscellaneous                     15,144             11,343           12,593
               
                                  401,347            582,120        2,911,055
               
               
    Net income (loss)        $  1,970,401       $  2,149,184    $  (1,698,844)


Allocation to:               
 Shareholders                $  1,950,697       $  2,127,692    $  (1,681,856)
 Managing shareholder              19,704             21,492          (16,988)
                             $  1,970,401       $  2,149,184    $  (1,698,844)
               









See accompanying notes to financial statements.

                             -F3


<PAGE>
Ridgewood Electric Power Trust II
Balance Sheet

                                                      Year Ended December 31,
                                                     1996                1995

Assets:

Investments in project development
 and power generation projects           $     16,116,582      $   16,056,151
Cash and cash equivalents                             ---             101,975
Electric power equipment                          331,018             331,018
Other assets                                       18,641              32,800
               
    Total assets                         $     16,466,241      $   16,521,944
               
               
               
               
Liabilities and Shareholders' Equity:               
               
Accounts payable and accrued
 expenses                                $        112,482      $       44,795
               
               
               
Shareholders' equity:               
Shareholders' equity (235.3775 shares
 issued and outstanding)                       16,391,464          16,513,521
Managing shareholder's accumulated deficit        (37,705)            (36,372)
                 
    Total shareholders' equity                 16,353,759          16,477,149
               
    Total liabilities and shareholders'
     equity                              $     16,466,241      $   16,521,944
               
               













See accompanying notes to financial statements.

                            -F4-

<PAGE


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


                                                    Managing     
                             Shareholders        Shareholder            Total
               
Shareholders' equity,
 December 31, 1993          $  15,158,123       $     (4,443)   $  15,153,680
Capital contributions,
 net (29.9 shares)              4,560,700                ---        4,560,700

Cash distributions             (1,243,907)           (11,626)      (1,255,533)

Net loss for the year          (1,681,856)           (16,988)      (1,698,844)
                  
Shareholders' equity,
 December 31, 1994                          
 (235.3775 shares)             16,793,060            (33,057)      16,760,003

Capital contributions,
 net                               50,000                ---           50,000

Cash distributions             (2,457,231)           (24,807)      (2,482,038)
               
Net income for the year         2,127,692             21,492        2,149,184
               
Shareholders' equity,
 December 31, 1995
 (235.3775 shares)             16,513,521            (36,372)      16,477,149
               
Capital contributions              10,000                ---           10,000
               
Cash distributions             (2,082,754)           (21,037)      (2,103,791)
               
Net income for the year         1,950,697             19,704        1,970,401
               
Shareholders' equity,
 December 31, 1996               
 (235.3775 shares)          $  16,391,464       $    (37,705)   $  16,353,759













See accompanying notes to financial statements.

                            -F5-



<PAGE>
Ridgewood Electric Power Trust II     
  Statement of Cash Flows     
     
                                                Year Ended December 31,
                                     1996               1995             1994
Cash flows from operating activities:
 Net income (loss)           $  1,970,401      $  (2,149,184)   $  (1,698,844)
               
Adjustments to reconcile
 net income (loss) to
 net cash (provided by)
 used in operating activities:               
  Proceeds from sale of
   electric power
   equipment                          ---            438,855              ---
  Purchase of electric
   power equipment                    ---                ---       (1,738,855)
  Writedown of limited
   partnership investments            ---                ---        1,397,350
  Purchase of investments
   in electric power projects     (60,431)        (5,519,498)      (9,190,884)
Changes in assets and
 liabilities:               
  Decrease in cash held
   in escrow for project 
   purchase                           ---                ---        2,343,000
  Decrease in deferred
   due diligence costs                ---             14,570          181,243
  (Increase) decrease in
   other assets                    14,159            (30,757)          18,826
  Increase (decrease) in
   accounts payable and
   accrued expenses                67,687             13,227         (607,258)
               
Total adjustments                  21,415         (5,083,603)      (7,596,578)
                  
Net cash provided by
 (used in) operating
 activities                     1,991,816         (2,934,419)      (9,295,422)
               
Cash flows provided by
 (used in) financing activities:               
  Proceeds from shareholders'
   contributions                   10,000             50,000        4,962,600
  Selling commissions and
   distribution and offering
   fees paid                          ---                ---         (401,900)
  Cash distributions to
   shareholders                (2,103,791)        (2,482,038)      (1,255,533)
  Net cash provided by
   (used in) financing
   activities                  (2,093,791)        (2,432,038)       3,305,167
               
  Net decrease in cash
   and cash equivalents          (101,975)        (5,366,457)      (5,990,255)
               
Cash and cash equivalents,
 beginning of period              101,975          5,468,432       11,458,687
Cash and cash equivalents,
 end of period               $        ---      $     101,975    $   5,468,432

See accompanying notes to financial statements.
                             -F6-

<PAGE>

Ridgewood Electric Power Trust II
Notes to Financial Statements

1.  Organization and Purpose

     Nature of business

     Ridgewood Electric Power Trust II (the "Trust") was formed 
as a Delaware business trust on November 20, 1992, by Ridgewood 
Energy Holding Corporation acting as the Corporate Trustee.  The 
managing shareholder of the Trust is Ridgewood Power Corporation. 
 The Trust began offering shares on January 4, 1993.  The Trust 
commenced operations on April 29, 1993 and discontinued its 
offering of Trust shares on January 31, 1994.

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

"Business Development Company" election

     Effective April 29, 1993, the Trust elected to be treated as 
a "Business Development Company" under the Investment Company Act 
of 1940 and registered its shares under the Securities Exchange 
Act of 1934.

2.  Summary of Significant Accounting Policies

Use of Estimates

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

Investments in project development and power generation limited 
projects    

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

Revenue recognition

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

Offering costs 

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

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


                                -F7-
<PAGE>




Ridgewood Electric Power Trust II
Notes to Financial Statements

Due diligence costs relating to potential power project 
investments

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

Income taxes

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

Reclassification

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

3.  Electric Power Equipment

     The Trust purchased various used electric power generation 
equipment to be used in potential power generation projects.  In 
January 1995, power generating equipment with a fair value of 
$1,300,000 was transferred to the Sunnyside (Monterey) project as 
part of its purchase price.  In October 1995, the Trust sold to a 
related party power generating equipment with a cost of $438,855 
for $455,182.  The remaining equipment is held in storage and 
depreciation is not recorded.  As of December 31, 1996, the cost 
of the remaining equipment was $331,018.

4.  Investments in Project Development and Power Generation 
Limited Projects

     The Trust had the following investments in power generation 
and waste transfer projects:

                                                Fair values as of December 31,

                                                     1996                 1995
Power generation and waste transfer projects:               
 Pittsfield Investors Limited Partnership   $   2,347,330        $   2,347,330
 RSD Power Partners, L.P.                       3,507,275            3,507,275
 B-3 Limited Partnership                        4,001,843            3,941,412
 Sunnyside Cogeneration Partners, L.P.          5,308,467            5,308,467
 California Pumping Project                       951,667              951,667
                                             $ 16,116,582         $ 16,056,151

Investments in power generation limited partnerships

Pittsfield Investors Limited Partnership (known as the Berkshire 
project)

     On January 4, 1994, the Trust made a limited partnership 
investment in this partnership, which was formed to acquire an 
operating facility, located in Pittsfield, Massachusetts.  The 
facility, which has been operating since 1981, burns municipal 
solid waste supplied by the City of Pittsfield and surrounding 
communities.  The facility has a long-term supply agreement with 
the City of Pittsfield, which expires in November 2004, under 
which the City makes payments to the facility for receiving the 
waste.  The facility generates additional revenue by selling 
steam produced from the waste burning process to a nearby paper 
mill under a long-term contract, which expires in November 2004.

                              -F8-

<PAGE>


Ridgewood Electric Power Trust II
Notes to Financial Statements

     In exchange for its investment, the Trust is entitled to 
receive annually a preferred distribution from available cash 
from the facility equal to 15% of its investment.  In the event 
that in any given year available net cash flow from the project 
does not cover the amount of the preferred minimum return, the 
amount of such shortfall is payable on a priority basis out of 
any available net cash flow in subsequent years.  The Trust may 
be entitled to receive additional distributions from any 
additional net cash flow.  As of  December 31, 1996 and 1995, the 
total cost of the Trust's investment in the partnership was 
$2,347,330.  The Trust received distributions of $351,451, 
$446,888 and $481,588 from the project in 1996, 1995 and 1994, 
respectively.

RSD Power Partners, L.P. (known as the San Diego project)

     On March 21, 1994, the Trust made a limited partnership 
investment in the partnership, which was formed to acquire an 
operating facility, located in San Diego, California.  The 
facility, which has been operating since 1972, sells chilled 
water used in the central air conditioning of 13 commercial, 
retail and government office buildings connected by a closed 
underground pipeline loop owned and used exclusively by the San 
Diego project.

     In exchange for its investment, the Trust is entitled to 
receive annually the greater of either 80% of net profits from 
the project or a preferred minimum return of 25% on its total 
investment.  In the event in any given year all net profits from 
the project do not cover the amount of the preferred minimum 
return, the amount of such shortfall is payable on a priority 
basis out of any net profits in subsequent years.  As of December 
31, 1996 and 1995, the total cost of the Trust's investment in 
the partnership was $3,507,275.  The Trust received distributions 
of $618,080, $1,027,412 and $435,000 from the project in 1996, 
1995 and 1994, respectively.

B-3 Limited Partnership (known as the Columbia project)

     On August 31, 1994, the Trust made a limited partnership 
investment in this partnership, which was formed to construct and 
operate a municipal waste transfer station, located in Columbia 
County, New York.  The project commenced operations in January 
1995.

     In exchange for its investment, the Trust is entitled to 
receive annually a preferred distribution of available net cash 
flow from the facility equal to 18% of its investment.  In the 
event in any given year available net cash flow from the project 
does not cover the amount of the preferred minimum return, the 
amount of such shortfall is payable on a priority basis out of 
any available net cash flow in subsequent years.  The Trust may 
be entitled to receive additional distributions from any 
additional net cash flow.  As of December 31, 1996 and 1995, the 
total cost of the Trust's investment in the partnership was 
$4,001,843 and $3,941,412, respectively.  The Trust received 
distributions of $515,000 and $510,000 from the project in 1996 
and 1995, respectively.

Sunnyside Cogeneration Partners, L.P. (known as the Monterey 
project)

     On January 9, 1995, the Trust acquired 100% of the existing 
partnership interests of Sunnyside Cogeneration Partners, L.P., 
which owns and operates a 5.5 megawatt electric cogeneration 
facility, located in Monterey County, California.  The initial 
cost of the investment was $5,308,467, which consisted of 
$3,782,000 of cash, $226,467 of due diligence and other costs, 
and electric power equipment valued at $1,300,000.  The original 
cost of the equipment contributed by the Trust was $1,599,940.  
In 1994, the Trust wrote down the value of the equipment by 
$299,940.  The Trust received distributions of $757,498 and 
$606,536 from the project in 1996 and 1995, respectively.

                              -F9-

<PAGE>


Ridgewood Electric Power Trust II
Notes to Financial Statements

California Pumping Project

     On March 31, 1995, the Trust acquired a package of natural 
gas fueled diesel engines which drive deep irrigation well pumps 
in Ventura County, California.  The engines' shaft horsepower-
hours are sold to the operator at a discount from the equivalent 
kilowatt hours of electricity.  The Trust receives a distribution 
of $0.02 per equivalent kilowatt up to 3,000 running hours per 
year and $0.01 per equivalent kilowatt for each additional 
running hour per year.  Total investment at December 31, 1996 and 
1995, was $951,667 for an equivalent of 299.8 kilowatts of power. 
 The operator pays for fuel, maintenance, repair and replacement. 
 The Trust received distributions of $129,179 and $105,742 from 
the project in 1996 and 1995, respectively.

Investments in project development limited partnerships

     The Trust made investments in several limited partnerships 
with other major participants in the power industry to provide 
access to investments in larger projects in which these 
participants would take the leading role in the acquisition or 
development of such projects.  In 1994, the Trust wrote off its 
investment in these limited partnerhsips of $1,065,798.

RE Power Partners, L.P. (known as the Blue Ridge project)

     In 1993, the Trust entered into a limited partnership 
agreement to provide construction funding of a 3 megawatt natural 
gas-fueled cogeneration project.  During 1994, after further 
review of the project the Trust decided not to proceed with the 
construction funding.  Total costs, excluding equipment written 
down separately and transferred to the Sunnyside Cogeneration 
Partners, L.P., incurred by the Trust and subsequently written 
off in 1994 totaled $331,552.

5.  Transactions With Managing Shareholder And Affiliates

     The Trust also pays to the managing shareholder a 
distribution and offering fee in an amount up to 5% of each 
capital contribution made to the Trust.  This fee is intended to 
cover legal, accounting, consulting, filing, printing, 
distribution, selling and closing costs for the offering of the 
Trust.  For the year ended December 31, 1994, the Trust paid fees 
for these services to the managing shareholder of $148,500.  
These fees were recorded as a reduction in shareholders' capital 
contributions.

     The Trust pays to the managing shareholder an investment fee 
of 2% of each capital contribution made to the Trust.  The fee is 
payable to the managing shareholder for its services in 
investigating and evaluating investment opportunities and 
effecting transactions for investing the capital of the Trust.  
For the year ended December 31, 1994, the Trust paid investment 
fees to the managing shareholder of $59,400.

     The Trust entered into a management agreement with the 
managing shareholder, under which the managing shareholder 
renders certain management, administrative and advisory services 
and provides office space and other facilities to the Trust.  As 
compensation to the managing shareholder, the Trust pays the 
managing shareholder an annual management fee equal to 2.5% of 
the net asset value of the Trust payable monthly upon the closing 
of the Trust.  For the years ended December 31, 1996, 1995 and 
1994, the Trust paid management fees to the managing shareholder 
of $328,952, $494,023 and $494,820, respectively.

                              -F10-

<PAGE>


Ridgewood Electric Power Trust II
Notes to Financial Statements

     Under the Declaration of Trust, the managing shareholder is 
entitled to receive each year 1% of all distributions made by the 
Trust (other than those derived from the disposition of Trust 
property) until the shareholders have been distributed in respect 
of the year an amount equal to 15% of their equity contribution. 
 Thereafter, the managing shareholder is entitled to receive 20% 
of the distributions for the remainder of the year.  The managing 
shareholder is entitled to receive 1% of the proceeds from 
dispositions of Trust properties until the shareholders have 
received cumulative distributions equal to their original 
investment ("Payout").  In all cases, after Payout the managing 
shareholder is entitled to receive 20% of all remaining 
distributions of the Trust. 

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

     The managing shareholder purchased 1.45 shares of the Trust 
for $121,800.  Through the closing of the Trust's offering on 
January 3, 1994, commissions and placement fees of $248,807 were 
earned by Ridgewood Securities Corporation, an affiliate of the 
managing shareholder.

     In 1996, under an Operating Agreement with the Trust, 
Ridgewood Power Management Corporation ("Ridgewood Management"), 
an entity related to the managing shareholder through common 
ownership, provides management, purchasing, engineering, planning 
and administrative services to the power generation project 
operated by the Trust.  Ridgewood Management charges the project 
at its cost for these services and for the allocable amount of 
certain overhead items.  Allocations of costs are on the basis of 
identifiable direct costs, time records or in proportion to 
amount invested in projects managed by Ridgewood Management.  
During the year ended December 31, 1996, Ridgewood Management 
charged the Monterey project $60,139 for overhead items allocated 
in proportion to the amount invested in projects managed, and 
charged the Monterey project for all of the remaining direct 
operating and non-operating expenses incurred during the period.