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, 1998


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. [ X ]

     There is no market for the Shares. The aggregate capital contributions made
for the Registrant's  voting Shares held by  non-affiliates of the Registrant at
April 9, 1999 was $23,426,700.


Exhibit Index is located on Page __.

<PAGE>
PART I

Item 1.  Business.

Forward-looking statement advisory

     This Annual Report on Form 10-K, as with some other  statements made by the
Trust  from  time to time,  has  forward-looking  statements.  These  statements
discuss  business  trends, year 2000 remediation and other  matters  relating  
to the  Trust's  future
results,  year 2000  remediation 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 "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  shares of  beneficial  interest  in the Trust  ("Investor
Shares")in a private placement  offering (the "Offering") which ended 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 580 record holders of
Investor Shares (the "Investors"). As described below in Item 1(c)(2), the Trust
(and its subsidiaries)  owns equity interests in four Independent Power Projects
and a debt interest in another.


     The Trust is organized similarly to a limited partnership.  Ridgewood Power
Corporation (the "Managing  Shareholder"),  a Delaware Corporation
is the Managing Shareholder of the Trust.  

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


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

     The  Trust  made an  election  to be  treated  as a  "business  development
company" under the Investment Company Act of 1940, as amended ( the "1940 Act").
On February 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  power  projects that generate  electricity or related
forms of energy for sale to manufacturers,  utilities and other users. The Trust
also may invest in facilities related to those projects.


     The Trust has equity investments  totaling  approximately  $10.6 million in
four Projects: (i) a waste-to-energy  generating facility located in Pittsfield,
Massachusetts (the "Berkshire Project"); (ii) a municipal waste transfer station
located in Columbia County,  New York, near the Berkshire Project (the "Columbia
Project");  (iii) a natural gas-fired  cogeneration facility located in Monterey
County,  California (the "Monterey Project") and (iv) various natural gas-fueled
engines used to power  irrigation well pumps in Ventura County,  California (the
"California Pumping Project").


     The Trust also invested $3.5 million in 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").  The Trust
sold its interest in the San Diego  Project in June 1997 for $6.15  million to a
subsidiary of a  Minnesota-based  utility.  A portion ($2.7 million) of the sale
price is  represented  by an 8%  secured  promissory  note of the buyer  payable
monthly through June 25, 2003.

     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  currently  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, 1997.  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 1998  totalled
$176,000 (a 7.5% annual return based on the pre-writedown  investment level), as
compared to $360,000 in 1997. . Distributions from the Berkshire Project,  after
continuing  at  approximately  the 1997 levels for the first six months of 1998,
ceased in the third quarter of 1998. In the third quarter of 1998,  EAC informed
the Trust that  significant and undisclosed cost overruns in the construction of
an ash handling  system for the  Berkshire  Project had  depleted the  Project's
funds, including reserve funds for closure of a landfill and other reserves. EAC
believed  that  Berkshire  could not  continue  operations  without  significant
capital injections from its two limited partners,  one of whom is the Trust. EAC
further  advised the Trust that even if the Project were to continue  operations
with additional  contributed capital, in that event distributions from Berkshire
to the Trust would cease for an indefinite period.

     The Trust requested detailed additional information and a revised operating
plan from EAC. The Trust also  conducted  on-site  reviews by its  financial and
engineering  personnel.  In early  November  1998, EAC installed a new financial
team for the  Project  and  offered  to  contribute  additional  capital  to the
Project.  EAC has proposed to the Trust that EAC would contribute the additional
capital  necessary  to keep  the  Project  solvent  and  that  the  Trust  would
subordinate  its rights to  distributions  from the Project until the additional
capital  contributed  by EAC was  recouped.  The  Trust  has not  agreed  to the
proposal and the parties are in contact with each other.  The Project remains in
operation  but has  ceased  distributions  to the Trust and EAC.  Based on EAC's
business plan and  projections  for the Project,  the Trust does not  anticipate
that distributions to it from the Project will resume during 1999 and that it is
unlikely  that any  material  amounts  will be received by the Trust until 2004,
which is the year in which the solid waste supply  agreement and the steam sales
agreement expire.  Accordingly, as described at Item 7 - Management's Discussion
and Analysis of Financial  Condition and Results of Operations,  the Trust wrote
down the estimated fair value of the Project to zero as of December 31, 1998.

(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 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  1998  totalled
$250,000 (a 6.2% annual return), down from $265,000 in 1997.

     Returns at the  Columbia  Project have been  impaired by repeated  one-year
extensions of the closing  deadlines for some local  landfills.  If waste can be
cheaply  deposited at local landfills,  there is no demand for consolidating the
waste for transfer to distant sites.  Further,  in early 1998 a competing  waste
management company has announced its intention to acquire or develop a competing
facility  nearby,  although the Trust believes that the competitor has suspended
its  planning  for the  moment.  Because  of the  extensions  and the  potential
competitive threat, the Trust anticipates that volume and prices at the Columbia
Project  will be  adversely  affected  for the  foreseeable  future.  See Item 7
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations for additional information.


(iii)  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 expiring
in 2020 (the "Power Contract"). Thermal energy from the Monterey Project is used
to provide warm water to an adjacent  greenhouse under a long term contract that
also terminates in 2020. For 1998, the Trust received  approximately $515,000 (a
10.1%  annual  return),  up from  $784,000  for 1997 and  $757,000 in 1996.  The
decline in distributions  reflected  increased  maintenance costs at the Project
from a periodic overhaul of the engines and a loss of revenues for the period of
the overhaul.

     The Monterey  Project is operated on behalf of the Trust by Ridgewood Power
Management Corporation,  a New Jersey Corporation ("RPMCo").  RPMCo is a service
company affiliated with the Managing  Shareholder,  as further described at Item
10(g) - Directors and Executive Officers of the Registrant - RPMCo.


     The Monterey  Project is a "Qualifying  Facility"  under the Public Utility
Regulatory  Policies  Act  of  1978,  as  amended  ("PURPA"),  because  it  is a
cogeneration  facility that meets PURPA  standards.  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.  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 Monterey  Project  sells its output to
Pacific Gas & Electric  Company under the long-term  contract at a formula price
set  by  the  California  Public  Utilities  Commission  that  approximates  the
utility's avoided cost.  Currently,  the formula consists of a fixed payment for
the plant's  capacity and a payment per unit of energy delivered that is tied to
85% of the  cost of  natural  gas,  the fuel  used at the  plant.  The  capacity
payments vary  seasonally  and are  significantly  higher during the summer peak
season.


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

         See Item 1(a)(3) - Project Operations below for additional  information
concerning a potential adverse event affecting the Project's revenues and Item 3
regarding related legal proceedings.

(iv) California  Pumping Project 

In  March  1995,  the  Trust  purchased  100%  of the  equity  interests  in the
California  Pumping 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  California  Pumping  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  California  Pumping  Project
provides power equivalent to approximately 3 megawatts.

     Until  October  1998,  the Trust had a management  contract  with the prior
operator of the Project.  The prior operator  received a fee 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.  Until January 1998, the Trust received
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, received
the  remainder.  Beginning  in January  1998,  the Trust  received  one-half  of
revenues after deduction of a 6/10 cent per equivalent kilowatt-hour maintenance
fee and  costs of fuel for the  engines.  In  October  1998  the  Trust  and the
operator  terminated  the  management  agreement and the Trust paid the operator
$105,840 to reimburse it for installation costs advanced by the operator.  RPMCo
has operated  the project  since that time and the Trust  reimburses  it for its
costs and expenses.

     In 1998 the Project paid $12,000 to the Trust (a 1.0% annual return),  down
from $184,000 in 1997.


     Ridgewood  Power IV owns a package of similar  engines located on different
sites and  operated  under  identical  terms by the same  operator.  The engines
operate independently of each other and revenues and expenses for each Trust are
segregated from those of the other.

 (v)  San Diego Project.

     On June 25,  1997 the  Trust  sold its  entire  interest  in its San  Diego
Project to subsidiaries of NRG Energy,  Inc. of Minneapolis,  Minnesota ("NRG").
The San Diego  Project is a district  cooling  system  located in  downtown  San
Diego, California,  that generated and supplied chilled water through sub-street
piping to approximately 10 large office  buildings.  The sale took the form of a
sale  of  all  of the  Trust's  limited  partnership  interest  in  the  limited
partnership that owned the Project and its interest in the general partner.  The
sale price was $6,200,000,  of which $3,500,000 was paid in cash at the closing.
The  remaining  $2,700,000  was paid by  delivery of a secured,  purchase  money
promissory note of the principal NRG subsidiary purchasing the Project. The note
bears  interest at 8% per year and is payable in equal monthly  installments  of
principal  and  interest  through  its  maturity on June 25,  2003.  The note is
secured by the partnership interests sold by the Trust to the NRG subsidiaries.

     NRG  and  its  subsidiaries  participating  in  the  transaction  were  not
affiliated with and had no material  relationships  with the Trust, its Managing
Shareholder  or their  affiliates,  directors,  officers or  associates of their
directors and officers.  The sales price and the terms of the  acquisition  were
determined in arm's length negotiations  between the Managing Shareholder of the
Trust and NRG. In late 1997,  a subsidiary  of NRG and the Managing  Shareholder
entered into negotiations for the investment by Ridgewood  Electric Power Trusts
IV and V (which are also  managed by the  Managing  Shareholder)  of up to $32.5
million in up to 17 landfill-gas fueled generating plants being developed by the
NRG subsidiary.  No binding agreement has been reached. The Trust is not a party
to the proposed transaction and will have no interest therein.

     The Trust acquired its interest in the San Diego Project on March 21, 1994,
when it made an  investment  of  approximately  $2.3  million  to acquire an 80%
interest  in the  Project.  The Trust  made  additional  capital  contributions,
totaling  approximately $1.2 million, to the Project to fund working capital and
to  purchase  various  leased  equipment.  The Trust was  entitled  to an annual
cumulative  preferred  distribution  of available cash flow  attributable to the
facility (after funding,  operating and maintenance expenses and reserves) equal
to 25% of its investment. Any additional cash flow went first to the operator of
the  Project  until it  received  20% of the  annual  distribution  and then the
remainder, if any, would go to the Trust. The operator 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.


     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 has 22 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  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.

         Distributions to the Trust from the Project for the period from January
1, 1997 to June 25, 1997 (the date the Trust sold its  interest in the  Project)
were $50,000. Distributions for all of 1996 totalled $618,000.


(vi)  Discontinued Investments

     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  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 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 California Pumping 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 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
Project 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 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 California  Pumping  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
(which at the Berkshire and Columbia  Projects are  subordinated  to the Trust's
preferred rights), which may create an additional incentive for the manager. The
Trust monitors their performance using RPMCo personnel and outside consultants.

     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.  RPMCo  provides  operations,   management,   purchasing,
engineering,  planning  and  administrative  services  for the Projects and also
assisted in managing the San Diego  Project  during the first six months of 1997
prior to sale. The Managing Shareholder believes that for these Projects,  where
RPMCo has necessary skills,  having RPMCo 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 Executive  Officers of the  Registrant and Item
13 - Certain  Relationships  and Related  Transactions  for further  information
regarding RPMCo and for the cost reimbursements received by RPMCo.

     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.  Steam  produced  by the  Berkshire  Project is  conveyed
directly to the user by pipeline  and the energy  produced by the engines in the
California Pumping 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.  See
Item   1(c)(6)   -   Regulatory   Matters,   for   an   explanation   of   these
requirements.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.


         From time to time Pacific Gas and Electric  Company,  the  purchaser of
the electricity  generated at the Monterey Project,  has questioned  whether the
Project is delivering  sufficient  thermal energy to its greenhouse  customer to
meet  PURPA  requirements  for  Qualifying  Facility  status  and has  installed
metering  devices to provide data.  These  inquiries are in large part caused by
the  monitoring  program  that Pacific Gas and Electric  Company  undertakes  as
required  by the  California  Public  Utilities  Commission  for data on thermal
deliveries.


         The Project  currently  benefits from discounted  natural gas rates for
its fuel  supply.  If it is  determined  that the Project did not meet PURPA and
California  efficiency  standards,  the Project  would be required to refund the
discount to Pacific Gas and Electric  Company.  Further,  the  electric  company
would be able to exclude a  proportionate  part of its purchases of  electricity
from the long-term power contract and pay at substantially  lower spot rates for
that part of its purchases. This would require the Project to refund substantial
amounts.  Finally,  it is possible that the Power Contract could be invalidated,
which might make the Project uneconomic to operate. See Item 1(c)(4) - Trends in
the Electric Utility and Independent Power Industries for further information.

         In February 1999,  Pacific Gas and Electric  Company notified the Trust
that it had concluded that the Monterey  Project had not met those  requirements
by an  unspecified  amount  and on April 1, 1999 it  brought  legal  proceedings
against the Trust's  subsidiary  that owns the  Project,  as described at Item 3
Legal  Proceedings.  The complaint only requests that the Project refund the gas
price  discounts  received,  but an  adverse  decision  might  affect
subsequent  years and might also serve as the basis for an action to  invalidate
the Power  Contract.  The Trust is  investigating  the matter  and is  retaining
counsel.  The Trust  believes that the Project has met and continues to meet the
PURPA  requirements  and that the utility's  conclusion can be supported only by
improper action by the utility.  In particular,  the Trust believes that Pacific
Gas and  Electric  Company has chosen a new location at which it is metering and
computing efficiency  standards.  That location is materially different from the
location at which  efficiency was measured from the inception of the Project and
is  located  at a point  where  efficiency  measurements  necessarily  would  be
materially lower. The Trust also is investigating whether there are systemic and
other problems with the utility's data. Although it is too early to estimate the
precise impact of this lawsuit on the Trust,  the Trust may incur material costs
in  defending  this  proceeding  and other  potential  action by Pacific Gas and
Electric Company.


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

<TABLE>
<CAPTION>

                                           Calendar year
                                   1998          1997          1996

<S>                             <C>             <C>          <C>
Crane & Co., Inc.                  18.0%         21.0%        14.8%
Pacific Gas & Electric Co.         54.0%         45.7%        31.9%

</TABLE>

     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 Financial Condition and 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.  The
Trust  currently  does  not  anticipate  that  it will  have  to  make  material
additional  investments for environmental  compliance.  The process of preparing
the new Title V applications for air pollution licensing of existing facilities,
however,   is  protracted  and  requires  modest  additional   expenditures  for
consultants.  If future  environmental  standards  require that a Project  spend
increased  amounts for  compliance,  such increased  expenditures  could have an
adverse  effect  on the Trust to the  extent  it is a holder  of such  Project's
equity securities. See Item 1(c)(6) Business - Narrative Description of Business
- Regulatory Matters.

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

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

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

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

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


     In recent years,  many  electric  utilities  have  attempted to exploit all
possible means of terminating  Power Contracts with independent  power projects,
including  requests to  regulatory  agencies  and  alleging  violations  of even
immaterial terms of the Power Contracts as justification  for terminating  those
contracts.  See the discussion at Item 1(c)(3) above as to a possibility of such
action  at the  Monterey  Project.  Even if an  attempt  to  invalidate  a Power
Contract were  unsuccessful,  the Trust might face material  costs in contesting
those utility  actions.  Other  utilities  have from time to time made offers to
purchase and terminate Power  Contracts for lump sums. The Managing  Shareholder
has  indicated  its  interest in selling  the Power  Contract  for the  Monterey
Project and Power  Contracts for two other  California  cogeneration  facilities
owned by  Ridgewood  Power III,  and  preliminary  contacts  have been made with
Pacific Gas and Electric Company. No negotiations have resulted.

     Finally,  the Power Contract is subject to modification or rejection in the
event that the utility  purchaser enters  bankruptcy.  There can be no assurance
that utility purchasers would not declare bankruptcy.

     After the Power  Contract  expires in 2020 or terminates for other reasons,
the Monterey  Project under currently  anticipated  conditions  would be free to
sell its  output on the  competitive  electric  supply  market,  either in spot,
auction or short-term  arrangements or under long-term  contracts if those Power
Contracts  could be obtained.  There is no assurance that the Project could sell
its output or do so  profitably.  Because  the  Project is fueled by natural gas
purchased at market prices and because the Projects is  relatively  small-scale,
it might have cost  disadvantages in competing  against larger  competitors that
would  enjoy  economies  of scale.  The Trust is  unable to  anticipate  whether
thermal sales from cogeneration  would offset any possible cost disadvantages in
electric generation or whether in fact the Project would have cost disadvantages
after the Power  Contract  ends in 2020.  It is thus  impossible  to predict the
profitability  of the  Project  after  the  scheduled  termination  of the Power
Contract.  If the Power Contract were to be terminated now, the short-term rates
available in California's  competitive electricity market are substantially less
than the costs of  operation  of the  Monterey  Project  and the  Project  would
probably be forced to close.


     The  Berkshire  Project's  contract  to supply  steam  terminates  in 2004.
Because it is normally  inefficient to transport steam over long distances,  the
Trust  believes  that so long as the cost of suitable  municipal  waste does not
substantially  increase or the costs of  alternate  fuels does not  decrease far
below current levels, the Berkshire Project should be able to renew its contract
at a price  comparable  to or lower than the cost to Crane & Co. of running  its
own boilers or using a new cogeneration facility. There is no assurance that the
Project can do so or that the customer will be financially capable of doing so.

     The  Columbia  and  California  Pumping  Projects  do  not  have  long-term
contracts  with any of  their  customers  and are thus  exposed  to  short-  and
long-term market fluctuations.


(5)  Competition

     The Monterey and Berkshire Projects,  as described above, are not currently
subject to  competition  because  those  Projects  have entered  into  long-term
agreements  to sell their  output at  specified  prices.  However,  the Monterey
Project could be subject to future  competition to market its electricity output
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;  because of the failure of a Project to comply with
the terms of the Power  Contract;  regulatory  changes;  or other  reasons.  The
Monterey Project would then face significant  competition to market its capacity
and energy output in the newly developing  competitive  market in California and
would face material cost pressures.  The Berkshire  Project may face competition
after 2004 from fuel suppliers  offering  alternative  means of providing energy
and possibly from other cogeneration or waste-to-energy providers.


     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.

     The Columbia Project, as described above, faces competition from a national
waste management company much larger than itself,  from local landfill operators
(if their permits to receive  waste are again  extended) and possibly from other
local  entrepreneurs.  There are few barriers to entry in the waste transfer and
management  industry.  The California  Pumping Project is subject to competition
from the local electric  utility,  which serves much of Southern  California and
which offers  electricity at discounted  rates to operate  electric pumps rather
than the natural  gas-fueled  pumps operated by the Project.  As deregulation of
the  electricity  market  proceeds in  California,  the  Project  will also face
competition from power marketers and independent generating companies.  Barriers
to entry into the electric or gas-fueled  irrigation  pumping  industry are also
low.


(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,  is a  Qualifying  Facility.  The San  Diego  Project,  which did not
ordinarily sell  electricity,  was also a Qualifying  Facility.  Maintaining the
Qualified  Facility  status  of an  electric  generating  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 or  reduction  of rates  payable  for  output,  and there is an
ongoing  risk that the utility will assert that the Project does not qualify for
any given year. As discussed above, the Trust believes that the Monterey Project
has  qualified  and will  continue  to 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  Monterey  Project is  coal-capable  and thus
qualifies for exemption from the Fuel Use Act.

(E) State  Regulation.  State public utility  regulatory  commissions have broad
jurisdiction over Independent Power Projects which are not Qualifying Facilities
under PURPA, and which are considered public utilities in many states. In states
where the wholesale or retail  electricity  market remains  regulated,  Projects
that are not  Qualifying  Facilities  may be  subject to state  requirements  to
obtain  certificates of public convenience and necessity to construct a facility
and 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.  In recent  years,  supply of  allowances  has tended to
exceed  demand,  primarily  because of  improved  control  technologies  and the
increased use of natural gas.

     The  Berkshire  Project is not a Qualifying  Facility and does not generate
electricity.  However,  it was operating  prior to November 15, 1990 and is thus
currently exempt from the requirement to obtain sulfur dioxide allowances.

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

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

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

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

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

     Based  on  current   trends,   the   Managing   Shareholder   expects  that
environmental and land use regulation will become more stringent.  The Trust and
the Managing  Shareholder  have  developed  limited  expertise and experience in
obtaining necessary licenses, permits and approvals and may rely on co-owners of
Projects.  The Trust  will rely upon  qualified  environmental  consultants  and
environmental  counsel  retained  by it or by  Project  co-owners  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 operating personnel of the Monterey and California Pumping Projects are
employed  by RPMCo  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  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).

<TABLE>
<CAPTION>



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

<S>         <C>                       <C>      <C>          <C>       <C>        <C>
Berkshire   Pittsfield, Massachusetts  Leased   2004          5        30,000    Waste-to energy
                                                                                 facility
Columbia    Columbia, New York         Owned     __          44        25,000    Municipal waste
                                                                                 transfer station
Monterey    Monterey, California       Leased   2020          2        10,000    Gas-fired
                                                                                 cogeneration
                                                                                 facility
Cal. Pumping Ventura County,          Leased   N/A         N/A        N/A        Natural gas fired
              California               or                                        engines powering
                                      licensed                                   irrigation pumps
                                                                                 located on various
                                                                                 farms


</TABLE>

Item 3.  Legal Proceedings.

         On April 1, 1999,  Pacific Gas and Electric  Company,  the purchaser of
the  electricity  generated by the Trust's  Monterey  Project,  sued the Trust's
subsidiary  that owns the Project in the Superior  Court of  California  for the
City and County of San  Francisco.  Pacific Gas and  Electric  alleged  that the
Project  did not  meet  federal  and  state  efficiency  requirements  and  that
accordingly  the Project was not entitled to the benefit of  discounted  natural
gas fuel rates  allowable to  qualifying  cogeneration  facilities.  The lawsuit
claimed an  unspecified  amount of  damages.  The Trust will  defend the lawsuit
vigorously. See also the discussion at Item 1(c)(3) above.

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 1998.

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.


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


(b)  Holders

     As of the date of this Form 10-K,  there are 580 recordholders of Investor
Shares.

(c)  Dividends


     The Trust made distributions as follows for the years 1997 through 1998:

                                          Year ended             Year ended
                                          December 31,           December 31,
                                             1997                   1998


Total distributions to Investors          $4,634,952             $1,412,273
Distributions per Investor Share            $ 19,692                 $6,000
Distributions to Managing Shareholder       $ 46,818                $14,265 

     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.  See Item 7 - Management's  Discussion
and Analysis.


      The Trust's cash flow comes  primarily from  distributions  from Projects.
Those distributions are from cash flow of the Projects, which includes income of
Projects plus funds representing  depreciation and amortization charges taken by
the Projects.  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 or other
non-cash charges against  earnings.  Investors should be aware that the Trust is
organized to return net cash flow rather than accounting income to Investors.

Item 6.  Selected Financial Data.

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

<TABLE><CAPTION>



Supplemental Information
Schedule
Selected Financial Data                          As of and for the years ended December 31,
                                  1998          1997         1996          1995          1994
<S>                          <C>           <C>            <C>           <C>          <C>

Total Fund Information:
Net revenue from
 operating projects             $  953,576   $ 1,715,860    $2,371,208    $2,696,578      $916,588
Net income (loss)               (1,704,811)    3,591,765     1,970,401     2,149,184    (1,698,844)
Net assets
 (shareholders' equity)         12,132,405    15,263,754    16,353,759    16,477,149    16,760,003
Investments in Project
 development and power
 generation limited
 partnerships                  10,594,402     12,733,179    16,116,582   16,056,151      9,236,653
Note receivable                 2,140,866      2,521,001             0            0              0
Total assets                   12,747,675     15,432,434    16,466,241   16,521,944     16,791,571
Per Investor Share:
  Revenues                          4,886       $ 18,674       $10,076      $11,456         $3,894
  Expenses                         12,129          3,415         1,705        2,473         12,368
  Net income (loss)                (7,243)        15,260         8,371        9,131         (7,218)
  Net asset value                  51,544         64,848        69,639       70,158         71,345
Distributions to
 Investors                          6,000         19,692        $8,849      $10,440         $5,285

</TABLE>


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


Introduction

     The following  discussion and analysis  should be read in conjunction  with
the Trust's  financial  statements  and the notes  thereto  presented  elsewhere
herein.  The Trust's financial  statements are prepared under generally accepted
accounting principles applicable to business development companies. Accordingly,
the Trust carries its  investment in the Projects it owns at fair value and does
not  consolidate its financial  statements with the financial  statements of the
Projects. Revenue is recorded by the Trust as cash distributions are declared by
the Projects.  Trust revenues may fluctuate  from period to period  depending on
the  operating  cash  flow  generated  by the  Projects  and the  amount of cash
retained to fund capital  expenditures.  Dollar  amounts in this  discussion are
generally rounded to the nearest $1,000.

Outlook

     The U.S.  electricity  markets are being  restructured and there is a trend
away from regulated electricity systems towards deregulated,  competitive market
structures.  California, where the Trust's Monterey Project operates, has passed
new  legislation  that permits  utility  customers  to choose their  electricity
supplier  in  a  competitive  electricity  market.  The  Monterey  Project  is a
"Qualified Facility" as defined under the Public Utility Regulatory Policies Act
of 1978 and currently  sells its electric  output to a utility under a long-term
contract expiring in 2021.  During the term of the contract,  the utility may or
may not attempt to buy out the contract prior to  expiration.  At the end of the
contract,  the Monterey  Project will become a merchant plant and may be able to
sell  the  electric  output  at then  current  market  prices.  There  can be no
assurance  that future  market  prices will be  sufficient to allow the Monterey
Project  to  operate  profitably.  See  Item  1(c)(3)  -  Plant  Operations  for
information concerning a potential challenge to the Project's Power Contract.

     The  Berkshire  Project  receives  revenue in the form of tipping  fees for
waste  delivered to the facility and from steam sold under a long-term  contract
which  expires in 2004.  Tipping fees are based on spot market  prices which may
fluctuate from time to time. The Project's  steam customer may or may not extend
its purchases beyond the year 2004.

     The Columbia Project receives revenue in the form of tipping fees for waste
delivered to the facility by local waste  haulers and  transferred  to long haul
trucks for delivery to distant landfills. The Project's profit margins have been
reduced due to competition from national waste management companies operating in
the same region.

     The  California  Pumping  Project  owns  irrigation  well  pumps in Ventura
County, California which supply water to farmers. The demand for water pumped by
the project varies inversely with rainfall in the area.

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

Results of Operations

Year ended December 31, 1998 compared to year ended December 31, 1997

     Total revenue  decreased 73.8% to $1,150,000 in 1998 compared to $4,395,000
in 1997,  primarily due to lower income from power  generation  projects and the
absence of a $2,546,000 gain from the sale of the San Diego Project. The Project
was sold in June 1997 for $6,150,000  and the Trust received  $3,450,000 in cash
and $2,700,000 in the form of an 8% promissory  note payable over six years.  In
July 1997, the Trust made a special distribution to shareholders of $2,942,000.

     As summarized below,  income from power generation projects decreased 44.4%
to $954,000 in 1998 compared to $1,716,000 in 1997:

Project                             1998                1997
-------                             ----                ----

Monterey                          $515,000         $   784,000
Berkshire                          176,000             360,000
Columbia                           250,000             265,000
San Diego                             ---               50,000
California Pumping                  13,000             184,000
Other                                  ---              73,000
                             -------------       -------------

Total                             $954,000          $1,716,000 
                                  ========          ==========-

     The  decline  from the  Monterey  Project  was  attributable  to  increased
maintenance  costs from a periodic  overhaul of its engines and reduced revenues
because of the scheduled shutdown.

     The decline in revenue at Berkshire was a result of distributions  from the
project  ceasing in the third quarter of 1998. In the third quarter of 1998, the
manager of Berkshire  informed the Trust that  significant  cost overruns in the
construction  of an ash handling  system for the Berkshire  project had depleted
Berkshire's  funds,  including reserve funds for closure of a landfill and other
reserves.  The project  manager  believed that Berkshire could not continue long
term  operations  without  significant  capital  injections from its two limited
partners,  one of whom is the Trust.  The project  manager  further  advised the
Trust that  distributions  from Berkshire to the Trust would cease.  The Trust's
managing  shareholder  requested detailed  additional  information and a revised
operating  plan from the project  manager and conducted  on-site  reviews by its
financial and engineering  personnel.  The Trust has reviewed the short-term and
long-term  viability of the Berkshire  project and wrote down the carrying value
of the investment from $2,347,000 to zero.

     The California  Pumping Project  suffered from the  extraordinary  rainfall
that occurred in  California in the first half of 1998. In addition,  on October
1, 1998,  the Trust  terminated  the  operating  agreement  with the third party
manager and Ridgewood Power Management Corporation, an affiliate of the managing
shareholder,  began operating the project.  The Trust paid $106,000 to the third
party manager to terminate the operating  agreement,  further reducing  revenues
from the project.

     The Columbia  Project's  1998 and 1997 operating  results were  consistent.
Operating  cash flow from the San  Diego  Project  ended as a result of the 1997
sale of the Project,  but  interest  income on the note was earned in the latter
portion  of 1997 and all of 1998.  In  addition,  in 1997 the Trust  received  a
$73,000  distribution from a project  development  limited partnership for which
the Trust had previously written off its investment.

     Total expenses increased $2,054,000 (255.7%) to $2,858,000 in 1998 compared
to $804,000 in 1997,  primarily due to the $2,347,000 writedown of the Berkshire
Project in 1998,  partially  offset by the 1997 writedown of $331,000 of certain
electric power equipment. In 1998, the Trust recorded $7,000 of interest expense
on its borrowings  under its line of credit.  All other 1998 Trust expenses were
comparable to 1997.

Year ended December 31, 1997 compared to year ended December 31, 1996

     Total revenue  increased 85.3% to $4,395,000 in 1997 compared to $2,372,000
in 1996,  primarily  due to the  $2,546,000  gain on the  sale of the San  Diego
Project.

     As summarized below,  income from power generation projects decreased 27.6%
to $1,716,000 in 1997 compared to $2,371,000 in 1996:

Project                               1997                1996
-------                               ----                ----

Monterey                       $   784,000         $    757,000
Berkshire                          360,000              352,000
Columbia                           265,000              515,000
San Diego                           50,000              618,000
California Pumping                 184,000              129,000
Other                               73,000                 --- 
                             -------------       --------------

Total                           $1,716,000           $2,371,000
                                ==========           ==========

     The  Monterey,  Berkshire  and  California  Pumping  Projects  had improved
operating  results in 1997. The Columbia  Project's profit margin was negatively
impacted  due to increased  competition  from other waste  management  companies
operating in the region.  Operating cash flow  distributions  from the San Diego
Project were suspended in 1997 pending the sale of the Project. In addition, the
Trust  received  a  $73,000  distribution  from a  project  development  limited
partnership  for  which the Trust had  previously  written  off its  investment.
Interest and dividend income increased to $134,000 in 1997 compared to $1,000 in
1996. Interest income increased because cash was consolidated at the Trust level
in early 1997 and invested in higher yielding investment accounts.

     Total expenses  increased $403,000 (100.5%) to $804,000 in 1997 compared to
$401,000 in 1996,  primarily due to the $331,000  write-off of certain  electric
power equipment. Management fee expense increased $72,000 (21.9%) to $401,000 in
1997  compared to  $329,000 in 1996  because  the  Managing  Shareholder  waived
certain  management  fees in 1996. All other 1997 Trust expenses were comparable
to 1996.

Liquidity and Capital Resources

     During 1998, the Trust's operating  activities  generated  $951,000 of cash
compared to $4,857,000 of cash during 1997. The change is primarily attributable
to the  $3,353,000  of cash  received  from the sale of the San Diego Project in
1997. Cash  distributions  to shareholders  decreased to $1,427,000 in 1998 from
$4,858,000  in 1997 due to the absence of the  $2,942,000  special  distribution
from the proceeds  from the sale of the San Diego  Project and  decreases in the
monthly cash distribution rate in 1998.

     In 1997,  the  Trust and Fleet  Bank,  N.A.  (the  "Bank")  entered  into a
revolving  line of credit  agreement,  whereby  the Bank  provides  a three year
committed  line of credit  facility of  $750,000.  Outstanding  borrowings  bear
interest at the Bank's prime rate or, at the Trust's choice, at LIBOR plus 2.5%.
The credit  agreement  requires  the Trust to  maintain a ratio of total debt to
tangible net worth of no more than 1 to 1 and a minimum  debt  service  coverage
ratio of 2 to 1. The credit facility was obtained in order to allow the Trust to
operate using a minimum amount of cash, maximize the amount invested in Projects
and maximize cash distributions to shareholders.  The Trust borrowed $200,000 in
August 1998, $100,000 in October 1998 and an additional $50,000 in January 1999.
The current  interest rate is 7.73% per year.  The Trust  anticipates  that cash
flows from operations, other financing sources and reduced distributions will be
sufficient to repay these borrowings.

     Obligations of the Trust are generally limited to payment of the management
fee to the  Managing  Shareholder,  repayment  of  borrowings  under the line of
credit,  payments for certain accounting and legal services to third persons and
distributions to shareholders of available  operating cash flow generated by the
Trust's  investments.  The Trust's  policy is to  distribute  as much cash as is
prudent to  shareholders.  Accordingly,  the Trust has not found it necessary to
retain a material  amount of  working  capital.  The  amount of working  capital
retained is further reduced by the availability of the line of credit facility.

The Trust anticipates that its cash flow from operations during 1999 and line of
credit facility will be adequate to fund its obligations.


Year 2000 Remediation.


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

     The accounting,  network and financial packages for the Ridgewood companies
are basically  off-the-shelf packages that will be remediated,  where necessary,
by obtaining patches or updated versions.  The Managing Shareholder expects that
updating  will be  complete  before  the end of April  1999 with  ample time for
implementation,  testing  and  custom  changes  to  some  modifications  made by
Ridgewood to those programs.  To a large extent,  these software  packages would
have been upgraded within a three to five year time frame,  even absent the Year
2000 problem.  The Managing  Shareholder  estimates  that the Trust's  allocable
portion of the cost of upgrades that were  accelerated  because of the Year 2000
problem is approximately $300.

     The Managing  Shareholder  has identified  two major systems  affecting the
Trust that rely on custom-written software, the subscription/investor  relations
and investor  distribution  systems,  which maintain individual investor records
and effect  disbursement  of  distributions  to  Investors.  In late  1998,  the
Managing  Shareholder's  outside  computer  consultant  reviewed the remediation
completed for those systems and advised the Managing  Shareholder  that material
additional work was required for these systems to work  efficiently  after 1999.
The Managing  Shareholder  accordingly  employed a new  specialist for Year 2000
remediation  of those  systems and other  software and for  information  systems
support generally. Changes to the distribution system and testing of that system
were  completed by the end of the first quarter of 1999,  on schedule.  The plan
also  targets  completion  by the end of the  second  quarter  of 1999 of  minor
changes to the elements of the subscription/investor  relations system that will
allow it to handle individual  investors'  records,  and of all testing of those
modifications.  Elements of that system used to generate  internal sales reports
and other  internal  reports (but which do not affect  investors'  records) will
require  major  remediation.  Remediation  of  the  internal  report  generating
programs  is expected to be  completed  by the end of the third  quarter of 1999
with testing and any additional  modifications to be completed no later than the
end of 1999.

     The Managing  Shareholder is confident that all software systems  necessary
to maintain  investor  records will be remediated and tested well before the end
of  1999.   If  the  systems  used  to  generate   internal   reports  from  the
subscription/investor  relations  system are not  remediated by the end of 1999,
the Managing  Shareholder  is developing a contingency  plan to use the existing
systems  together  with  manual  entry of data and  checking  of  results  until
remediation is complete. The Managing Shareholder has done this in the past when
system  problems  have  occurred  and it thus  believes  that  there  will be no
material or  noticeable  effect on the accuracy of its records or  generation of
internal  reports,  although it may  experience  delays in  generating  internal
reports of a few days.

     Some systems are being remediated using the "sliding window" technique,  in
which two digit  years less than a  threshold  number  are  assumed to be in the
2000's and higher two digit  numbers are  assumed to be in the 1900's.  Although
this will allow  compliance  for several years beyond the year 2000,  eventually
those  systems  will  have to be  rewritten  again  or  replaced.  The  Managing
Shareholder expects that the ordinary course of system upgrading will eventually
cure this problem.

     The Trust's share of the incremental cost for Year 2000 remediation of this
custom written  software and related items for 1998 and prior years is estimated
at no more than $5,000 and is estimated to be not more than approximately $4,500
for 1999.

     Each of the Trust's  facilities is being reviewed  during the first quarter
of 1999 by an outside  consultant or by personnel of Ridgewood Power  Management
Corporation  to determine if its electronic  control  systems  contain  software
affected by the Year 2000 problem or contain  embedded  components  that contain
Year 2000 flaws.  The Trust owns one small  electric  generating  facility and a
number  of  pumping   equipment  sets,  and  interests  in  two  waste  disposal
facilities.  These assets rely on mechanical and analog  systems,  many of which
are not expected to be  vulnerable to Year 2000  problems.  The  facilities  use
personal computers running packaged software for routine  recordkeeping and data
logging,  which have been  upgraded as  described  above.  To date the Trust has
discovered no other systems  having a material  impact on output,  environmental
compliance,  recordkeeping  or any  other  material  impact  that have Year 2000
concerns.  The Trust's share of the estimated costs of the  consultant's  review
and of any minor upgrades or rehabilitation is estimated at less than $25,000.

     The Managing  Shareholder and its affiliates do not  significantly  rely on
computer input from  suppliers and customers and thus are not directly  affected
by other companies' year 2000 compliance. However, if customers' payment systems
or suppliers' systems were adversely  affected by year 2000 problems,  the Trust
could be  affected.  For  example,  if the utility  that  purchases  the Trust's
electricity  output  were  unable  to  accept  electricity   because  of  system
malfunctions or transmission failures caused by Year 2000 non-compliance by them
or other persons,  the Trust would lose revenues that could not be recouped at a
later date.  Similarly,  if utility  payment  systems were to  malfunction,  the
Trust's revenues might be delayed. Based on published reports the Trust believes
that it is now very unlikely that utilities will fail to accept  electricity for
more than a very short  time  because  of  malfunctions  caused by the Year 2000
problem.  Although the Trust also  believes  that utility  payment  problems are
unlikely  and,  if they occur,  will not exceed a month or two,  there can be no
assurance  that  payments  to the Trust will not be  interrupted.  The Trust has
established  a line  of  credit,  described  above  at  "Liquidity  and  Capital
Resources,"  to cover this  contingency  and  others.  The  Trust's  non-utility
customers  are being  contacted  during  the first  quarter  of 1999.  The Trust
anticipates  that the customers will advise it that they do not anticipate  that
their own Year 2000  problems,  if any, will interfere with taking or paying for
the Trust's  outputs of  electricity or heat, but that they will decline to give
any  assurance  that  they will be able to do so if third  persons  fail to meet
their obligations to those non-utility customers.

     The Trust's main supply contingency is the availability of natural gas from
pipelines for fueling the Monterey electric  generating plant and the irrigation
pumping sets. Accordingly the Trust is exposed to a possible interruption of gas
supply  if year 2000  problems  interfere  with  pipeline  service.  There is no
reasonably  available alternate source of gas and accordingly an interruption of
supply would necessarily close the plant or halt the pumping sets. The Berkshire
and Columbia  facilities burn or process municipal trash, the supply of which is
unlikely to be affected by year 2000  problems.  Availability  of other supplies
such as spare parts and consumables  may be affected by year 2000 problems;  the
Trust purchases these items from many different sources,  no single one or group
of which  could have a material  effect on the Trust if it or they were not Year
2000 compliant.

     Because the Trust and the Managing Shareholder are extremely small relative
to the size of their  material  customers and suppliers and are paid or supplied
using the same systems as larger companies,  requests for written  assurances of
compliance  from those customers or suppliers are not  cost-effective.  Instead,
the Managing  Shareholder  is monitoring  industry  trends and compliance and is
working to assure the Trust's  continued  operations.  Similarly,  as  described
above, in most cases there are no cost-effective  contingency  measures that can
be taken against the major risks to the Trust that  utilities  will fail to take
or fail to pay for the Trust's  electricity output or that natural gas pipelines
will fail to deliver gas as the result of Year 2000 problems. The Trust believes
that in the event that any  embedded  components  or other  systems are found to
have Year 2000  problems at its power plants it will be able to  remediate  them
promptly  and  before  the end of 1999.  It is  preparing  contingency  plans to
operate the plants with manualor  analog  control  systems if Year 2000 problems
cannot be remediated.  Becausethe  plants are small and use simple  technologies
that are not  dependent on computers or  date-sensitive  electronics,  the Trust
believes  that it is  unlikely  that any of its  facilities  would be  unable to
operate because of Year 2000 problems at the facility.

     Based on its internal  evaluations and the risks and contexts identified by
the  Commission in its rules and  interpretations,  the Trust believes that Year
2000  issues  relating  to its assets and  remediation  program  will not have a
material effect on its facilities,  financial  position or operations,  and that
the costs of addressing the Year 2000 issues will not have a material  effect on
its future  consolidated  operating results,  financial condition or cash flows.
However,  this  belief is based upon  current  information,  and there can be no
assurance that unanticipated problems will not occur or be discovered that would
result in material adverse effects on the Trust.

     The Trust is unable to predict  reliably  what,  if  anything,  will happen
after  December  31,  1999  with  regard  to Year  2000  problems  caused by the
inability of other  businesses  and  government  agencies to complete  Year 2000
remediation.  The Trust knows of no specific problems identified by customers or
suppliers that would have a material adverse effect on the Trust.

     The  reasonable  worst case scenario  anticipated  by the Trust is that the
Monterey, Berkshire and Columbia facilities will be able to operate on and after
January  1,  2000 but  that  there  may be some  short-term  inability  of their
customers  to  pay  promptly.   In  that  event,   the  Trust's  revenues  could
bematerially  reduced for a temporary  period and it might have to draw upon its
credit line to fund  operating  expenses  until the utility makes up any payment
arrears. In addition,  the Monterey and Pump Services facilities rely on natural
gas pipelines for fuel.  If the  pipelines do not function  properly  because of
year 2000 problems,  these facilities would have to reduce or cease  operations.
In 1998, the Monterey and Pump Services facilities contributed approximately 58%
of the Trust's revenues.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk. 
   
Qualitative Information About Market Risk.

     The Trust's investments in financial instruments are short-term investments
of working capital or excess cash. Those  short-term  investments are limited by
its  Declaration of Trust to investments in United States  government and agency
securities  or to  obligations  of banks  having at least $5  billion in assets.
Because the Trust invests only in short-term  instruments  for cash  management,
its exposure to interest rate changes is low. The Trust has limited  exposure to
trade accounts  receivable and believes that their carrying amounts  approximate
fair value.

     The Trust's  primary  market risk  exposure is limited  interest  rate risk
caused  by  fluctuations  in  short-term  interest  rates.  The  Trust  does not
anticipate  any changes in its primary market risk exposure or how it intends to
manage it. The Trust does not trade in market risk sensitive instruments.

     Quantitative Information About Market Risk

     This table provides  information  about the Trust's  financial  instruments
that are  defined by the  Securities  and  Exchange  Commission  as market  risk
sensitive instruments.  These include only short-term U.S. government and agency
securities and bank  obligations.  The table  includes  principal cash flows and
related weighted average interest rates by contractual maturity dates.

                                        December 31, 1998
                                      Expected Maturity Date
                                               2003
                                             (U.S. $)

Note receivable from NRG                      $ 2,140,866
  Interest rate                                     8%


Item 8.  Financial Statements and Supplementary Data.

Index to Financial Statements


Report of Independent Accountants                            F-2
Balance Sheet at December 31, 1998 and 1997                  F-3
Statement of Operations For the Three Years
  Ended December 31, 1998                                    F-4
Statement of Changes in Shareholders' Equity For
  the Three Years Ended December 31, 1998                    F-5
Statement of Cash Flows For the Three Years
  Ended December 31, 1998                                    F-6
Notes to Financial Statements                        F-7 to F-11


     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, PricewaterhouseCoopers 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  Holding,  which was incorporated in April 1992, is the Corporate
Trustee of the Trust.

(b)  Managing Shareholder.

     Ridgewood Power Corporation 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.   It  organized  the  Trust  and  is  its managing
shareholder.

     Ridgewood Power Corporation 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"),  Ridgewood
Electric Power Trust V ("Ridgewood Power V") and The Ridgewood Power Growth Fund
(the  "Growth  Fund")  as  Delaware   business  trusts  to  participate  in  the
independent  power industry.  Ridgewood Power Corporation is also their managing
shareholder.  The business  objectives of these five trusts are similar to those
of the Trust.

     The Managing  Shareholder is an affiliate of Ridgewood  Energy  Corporation
("Ridgewood  Energy"),  which through its predecessor  organized and operated 48
limited  partnership  funds and one  business  trust  over the last 17 years (of
which 25 have terminated) and which had total capital contributions in excess of
$190 million. The programs operated by Ridgewood Energy have invested in oil and
natural  gas  drilling  and  completion  and  other  related  activities.  Other
affiliates of the Managing Shareholder include Ridgewood Securities  Corporation
("Ridgewood Securities"),  an NASD member which has been the placement agent for
the private  placement  offerings  of the six trusts  sponsored  by the Managing
Shareholder  and the funds  sponsored by  Ridgewood  Energy;  Ridgewood  Capital
Corporation  ("Ridgewood  Capital"),  which  assists  in  offerings  made by the
Managing  Shareholder and which is the sponsor of two privately  offered venture
capital  funds   (Ridgewood   Capital  Venture   Partners,   LLC  and  Ridgewood
Institutional Venture Partners, LLC); and Ridgewood Power VI Corporation ("Power
VI Corp."),  which is a managing  shareholder of the Growth Fund and RPMCo. Each
of these  companies  are  controlled  by Robert E.  Swanson,  who is their  sole
manager or  director.  For  convenience,  the  discussion  below of the  limited
liability  companies,  all of which are recently organized,  treats each of them
and their corporate predecessor as a single entity.

     Robert  E.  Swanson  has  been  the  President,   sole  director  and  sole
stockholder of Ridgewood Power Corporation 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 52, has also served as President of the Trust since
its  inception in November  1992 and as President of RPMCo,  Ridgewood  Power I,
Ridgewood Power III,  Ridgewood Power IV, Ridgewood Power V and the Growth Fund,
since their respective inceptions. Mr. Swanson has been President and registered
principal of Ridgewood  Securities since it was organized in 1983. He became the
Chairman of the Board of Ridgewood  Capital on its  organization  in 1998 and is
the  Chairman  of the  Board of  Ridgewood  Capital  Venture  Partners,  LLC and
Ridgewood  Institutional  Venture  Partners,  LLC, the two venture capital funds
managed by  Ridgewood  Capital.  In  addition,  he has been  President  and sole
stockholder  of Ridgewood  Energy since its inception in October 1982.  Prior to
forming  Ridgewood  Energy in 1982,  Mr. Swanson was a tax partner at the former
New York and Los  Angeles law firm of Fulop & Hardee and an officer in the Trust
and Investment  Division of Morgan  Guaranty Trust Company.  His specialty is in
personal tax and financial planning,  including income, estate and gift tax. Mr.
Swanson is a member of the New York State and New Jersey bars,  the  Association
of the Bar of the City of New York and the New York State Bar Association. He is
a graduate of Amherst College and Fordham University Law School.

     Robert L. Gold,  age 40,  has served as  Executive  Vice  President  of the
Managing Shareholder,  RPMCo, Ridgewood Power I, the Trust, Ridgewood Power III,
Ridgewood Power IV, Ridgewood Power V and the Growth Fund since their respective
inceptions,  with primary responsibility for marketing and acquisitions.  He has
been President of Ridgewood  Capital since its  organization in 1998 and as such
he is  President  of  Ridgewood  Capital  Venture  Partners,  LLC and  Ridgewood
Institutional Venture Partners, LLC. He has served as Vice President and General
Counsel of Ridgewood  Securities  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,  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 44, joined the Managing  Shareholder in November 1994
as Senior Vice  President and holds the same position with the Trust,  RPMCo and
each of the other trusts sponsored by the Managing Shareholder.  He became Chief
Operating Officer of the Managing  Shareholder,  RPMCo and the Ridgewood Power I
through V trusts in  October  1996,  and is the Chief  Operating  Officer of the
Growth Fund. He also is Senior Vice  President of Ridgewood  Capital and the two
venture capital funds it manages. Mr. Brown has over 20 years' experience in the
development  and  operation of power and  industrial  projects.  From 1992 until
joining the Managing Shareholder he was employed by Tampella Services,  Inc., an
affiliate of Tampella, Inc., one of the world's largest manufacturers of boilers
and related equipment for the power industry.  Mr. Brown was Project Manager for
Tampella's  Piney Creek  project,  a $100  million  bituminous  waste coal fired
circulating  fluidized  bed power  plant.  Between  1990 and 1992 Mr.  Brown was
Deputy Project  Manager at Inter-Power of  Pennsylvania,  where he  successfully
developed a 106 megawatt  coal fired  facility.  Between 1982 and 1990 Mr. Brown
was employed by  Pennsylvania  Electric  Company,  an integrated  utility,  as a
Senior Thermal  Performance  Engineer.  Prior to that, Mr. Brown was an Engineer
with  Bethlehem  Steel  Corporation.  He has an  Bachelor  of Science  degree in
Mechanical  Engineering from Pennsylvania State University and an MBA in Finance
from the University of  Pennsylvania.  Mr. Brown  satisfied all  requirements to
earn the Professional Engineer designation in 1985.

     Martin V. Quinn,  age 51, assumed the duties of Chief Financial  Officer of
the  Managing  Shareholder,  the Trust,  the other four trusts  organized by the
Managing Shareholder and RPMCo in November 1996 under a consulting  arrangement.
He became a full-time  officer of the  Managing  Shareholder  and RPMCo in April
1997 and is now also Chief Financial  Officer of the Growth Fund. He also is the
Chief Financial  Officer of Ridgewood  Capital and the two venture capital funds
it manages.

     Mr. Quinn has 30 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 46,  has  served  as Vice  President  of the  Managing
Shareholder,  RPMCo,  Ridgewood Capital, the Trust, Ridgewood Power I, Ridgewood
Power III,  Ridgewood  Power IV,  Ridgewood Power V, the Growth Fund and the two
venture  capital  funds  managed  by  Ridgewood  Capitalsince  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, 2000 and year to year  thereafter as long
as it is  approved  at least  annually by (i) either the Board of the Trust or a
majority  in interest of the  Investors  and (ii) a majority of the  Independent
Trustees.  The agreement is subject to termination at any time on 60 days' prior
notice by the Board,  a majority in interest of the  Investors  or the  Managing
Shareholder.  The  agreement  is subject to  amendment  by the parties  with the
approval of (i) either the Board or a majority in interest of the  Investors and
(ii) a majority of the Independent Trustees.


(d) Executive Officers of the Trust.

     Pursuant  to  the  Declaration,  the  Managing  Shareholder  has  appointed
officers of the Trust to act on behalf of the Trust and sign documents on behalf
of the Trust as authorized  by the Managing  Shareholder.  Mr.  Swanson has been
named the President of the Trust and the other  executive  officers of the Trust
are identical to those of the Managing Shareholder.

     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.


     Ralph O. Hellmold,  age 58, is founder,  sole  shareholder and President of
Hellmold  Associates,  Inc., an investment  banking firm 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.B.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 and of International Aircraft Investors,  Torrance,
California.

     Jonathan  C.  Kaledin,  age 41, 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 the  Executive  Director of the
National  Water  Funding  Council  ("NWFC"),  an  advocacy  and  public  affairs
organization representing municipalities, businesses, financial institutions and
others on the financial aspects of clean water infrastructure  projects required
by the federal Clean Water Act and the federal Safe Drinking  Water Act..  Prior
to running the NWFC,  Mr.  Kaledin  practiced law in both the private and public
sectors,  specializing in  environmental  and real estate  matters.  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

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


(g)  RPMCo.

     As  discussed  above at Item 1 -  Business,  RPMCo has  assumed  day-to-day
management  responsibility  for the Monterey Project,  effective January 1, 1996
and  operating  responsibility  for the Sunkist  Project in October 1998 and had
assumed certain  responsibilities  for the San Diego Project in early 1997 until
its  sale.  Like the  Managing  Shareholder,  RPMCo is  controlled  by Robert E.
Swanson.  It has  entered  into an  "Operation  Agreement"  with  certain of the
Trust's  subsidiaries,  effective January 1, 1996, under which RPMCo,  under the
supervision of the Managing  Shareholder,  provides 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,  RPMCo charges
the Trust at its cost for these services and for the Trust's allocable amount of
certain  overhead  items.  RPMCo shares space and  facilities  with the Managing
Shareholder  and its  Affiliates.  To the extent  that  common  expenses  can be
reasonably allocated to RPMCo, the Managing Shareholder may, but is not required
to, charge RPMCo 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 are borne by the Managing Shareholder.

     Initially,  the Managing Shareholder does not anticipate charging RPMCo for
the full amount of rent,  utility  supplies  and office  expenses  allocable  to
RPMCo.  As a  result,  both  initially  and on an  ongoing  basis  the  Managing
Shareholder  believes  that  RPMCo'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. RPMCo 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 RPMCo;  and allocations will be made in a manner  consistent
with generally accepted accounting principles.

     RPMCo 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.  RPMCo 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
RPMCo,  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 RPMCo;  however,  no amendment  that
materially  increases the obligations of the Trust or that materially  decreases
the  obligations  of RPMCo 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 executive officers of RPMCo 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) and Ms. 
Olin (Vice President).  Douglas V. Liebschner, Vice President - Operations, is a
key employee.

     Douglas V. Liebschner,  age 51, joined RPMCo in June 1996 as Vice President
of  Operations.  He has  over  28  years  of  experience  in the  operation  and
maintenance of power plants.  From 1992 until joining RPMCo,  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 RPMCo at allocable cost for services
provided by RPMCo's  employees;  no such  reimbursement  per  employee  exceeded
$60,000 in 1997 or 1998.  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).  Additional
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 1998 and  1997,  as stated at Item 5 - Market  for  Registrant's  Common
Equity and Related  Stockholder  Matters,  as well as in prior years,  the Trust
made  distributions to the Managing  Shareholder (which is a member of the Board
of the  Trust).  In  addition,  the  Trust  and its  subsidiaries  paid fees and
reimbursements to the Managing Shareholder and its affiliates as follows:


<TABLE>
<CAPTION>
Fee              Paid to            1998         1997          1996         1995        1994
<S>              <C>            <C>          <C>          <C>          <C>         <C>
Management       Managing

 fee             Shareholder      $  381,594  $  401,085     $328,952     $494,000    $495,000
Cost reimburse-
 ments*          RPMCo             1,470,207   1,610,806    1,207,252            0           0
Investment       Managing

 fee             Shareholder               0           0            0            0      59,000
Placement        Ridgewood
 agent fee       Securities
 and sales       Corporation
 commissions                               0           0            0            0       4,000
Organizational,  Managing
 distribution    Shareholder
 and offering
 fee                                       0           0            0            0      149,000


</TABLE>


* 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 RPMCo's overhead costs. These costs are almost exclusively paid by
the Projects and do not appear in the Trust's financial statements.


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


     The management fee,  payable monthly under the Management  Agreement at the
annual rate of 2.5% of the Trust's net asset value,  began on the date the first
Project was  acquired  and  compensates  the  Managing  Shareholder  for certain
management,  administrative  and  advisory  services  for the  Trust.  Under the
Declaration of Trust,  the annual rate fell to 1.5% per year beginning  February
1, 1999.

     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 California Pumping Projects.  In 1996 and
1997,  these  reimbursements  were paid to RPMCo. The  reimbursements  to RPMCo,
which do not exceed its actual costs and  allocable  overhead,  are described at
Item 10(g) - Directors and Executive Officers of the Registrant -- RPMCo.


     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, 1998.

(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.

     The Registrant is no longer a party to former Exhibits 10H
through 10M because of its sale of the San Diego Project.  See
Exhibits 10P-R.

     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.

     10P.  Partnership Interest Purchase Agreement, dated as of
            June 25, 1997, by and among the Trust, RSD Power
            Corp., NRG San Diego, Inc., and NRG del Coronado,
            Inc.  Incorporated by reference to Exhibit 2.A. of
            the Current Report on Form 8-K of the Registrant,
            dated June 25, 1997.  Exhibits and schedules are
            omitted, and a list of the omitted documents is found
            at page 20 of the Agreement.  The Registrant agrees
            to furnish supplementally a copy of any omitted
            exhibit or schedule to the Partnership Interest
            Purchase Agreement to the Commission upon request.

     10Q.  Purchase Money Promissory Note.  Incorporated by
            reference to Exhibit 2.B. of the Current Report
            on Form 8-K of the Registrant, dated June 25, 1997.

     10R.   Security and Pledge  Agreement,  dated as of June 25,  1997,  by and
            among the Trust, RSD Power Corp.,  NRG San Diego,  Inc., and NRG del
            Coronado,  Inc.  Incorporated  by  reference  to Exhibit 2.C. of the
            Current Report on Form 8-K of the Registrant, dated June 25, 1997.



     21.   Subsidiaries of the Registrant.           Page 66

     24.   Powers of Attorney                        Page 67

     27.   Financial Data Schedule                   Page 69



<PAGE>


SIGNATURES

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

Signature                         Title                     Date

RIDGEWOOD ELECTRIC POWER TRUST II (Registrant)


By: /s/Robert E. Swanson    President and Chief    April 14, 1999
      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, 1999
       Robert E. Swanson      Executive Officer

By: /s/Martin V. Quinn      Senior Vice President  April 14, 1999
      Martin V. Quinn      and Chief Financial Officer

By: /s/Kathleen P. McSherry   Controller           April 14, 1999
      Kathleen P. McSherry

RIDGEWOOD POWER CORPORATION  Managing Shareholder  April 14, 1999


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

/s/Robert E. Swanson   *    Independent Trustee    April 14, 1999
   Ralph O. Hellmold


 /s/Robert E. Swanson  *    Independent Trustee    April 14, 1999
    Jonathan C. Kaledin


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



<PAGE>

                        Ridgewood Electric Power Trust II

                              Financial Statements

                        December 31, 1998, 1997 and 1996

                                      -F1-
<PAGE>

PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10036

[Letterhead of PricewaterhouseCoopers LLP]



                        Report of Independent Accountants

  March 23, 1999

  To the Shareholders and Trustees of
  Ridgewood Electric Power Trust II


  In our opinion,  the accompanying balance sheets and the related statements of
  operations,  changes in shareholders' equity and of cash flows present fairly,
  in all material  respects,  the financial position of Ridgewood Electric Power
  Trust II (the  "Trust") at December 31, 1998 and 1997,  and the results of its
  operations  and its cash flows for each of the three years in the period ended
  December  31,  1998,  in  conformity   with  generally   accepted   accounting
  principles.  These financial  statements are the responsibility of the Trust's
  management;  our  responsibility  is to express an opinion on these  financial
  statements based on our audits. We conducted our audits of these statements in
  accordance with generally  accepted  auditing  standards which require that we
  plan and perform the audit to obtain  reasonable  assurance  about whether the
  financial  statements  are free of material  misstatement.  An audit  includes
  examining, on a test basis, evidence supporting the amounts and disclosures in
  the  financial  statements,  assessing  the  accounting  principles  used  and
  significant estimates made by management, and evaluating the overall financial
  statement presentation.  We believe that our audits provide a reasonable basis
  for the opinion expressed above.

  As explained in Note 3, the financial statements include  investments,  valued
  at  $10,594,402  and  $12,733,179  (87%  and  83%  of  shareholders'   equity,
  respectively)  as of December  31, 1998 and 1997,  respectively,  whose values
  have been  estimated  by  management  in the absence of readily  ascertainable
  market values.  We have reviewed the procedures used by management in arriving
  at their estimate of value and have inspected underlying  documentation,  and,
  in the  circumstances,  we  believe  the  procedures  are  reasonable  and the
  documentation   appropriate.   However,  those  estimated  values  may  differ
  significantly from the values that would have been used had a ready market for
  the  investments  existed,  and  the  differences  could  be  material  to the
  financial statements.

/s/  PricewaterhouseCoopers LLP
                                      -F2-
<PAGE>





Ridgewood Electric Power Trust II
Balance Sheet
-------------------------------------------------------------------------

                                                        December 31,
                                             ----------------------------
                                                 1998            1997
                                             ------------    ------------

Assets:
Investments in power generation projects .   $ 10,594,402    $ 12,733,179
Cash and cash equivalents ................           --           175,818
Notes receivable from sale of investment .      2,140,866       2,521,001
Due from affiliates ......................          8,819            --   
Other assets .............................          3,588           2,436
                                             ------------    ------------

         Total assets ....................   $ 12,747,675    $ 15,432,434
                                             ------------    ------------

Liabilities and Shareholders' Equity:

Liabilities:
Accounts payable and accrued expenses ....   $    100,897    $     32,186
Borrowings under line of credit facility .        300,000            --   
Due to affiliates ........................        214,373         136,494
                                             ------------    ------------

         Total liabilities ...............        615,270         168,680
                                             ------------    ------------

Commitments and contingencies

Shareholders' equity:
Shareholders' equity (235.3775 shares
   issued and outstanding)
                                               12,212,324      15,312,360
Managing shareholder's accumulated deficit        (79,919)        (48,606)
                                             ------------    ------------

         Total shareholders' equity ......     12,132,405      15,263,754
                                             ------------    ------------

         Total liabilities and
           shareholders' equity ..........   $ 12,747,675    $ 15,432,434
                                             ------------    ------------





















                 See accompanying notes to financial statements.
                                      -F3-
<PAGE>

Ridgewood Electric Power Trust II
Statement of Operations
--------------------------------------------------------------------------------

                                               Year Ended December 31,
                                   ----------------------------------------
                                       1998           1997          1996
                                   -----------    -----------   -----------

Revenue:
     Income from power
       generation projects .....   $   953,576    $ 1,715,860   $ 2,371,208
     Gain on sale of RSD
       Power Partners, L.P. ....          --        2,545,846          --
     Interest income ...........       196,480        133,770           540
                                   -----------    -----------   -----------
         Total revenue .........     1,150,056      4,395,476     2,371,748
                                   -----------    -----------   -----------



Expenses:
     Writedown of investment
       in Pittsfield Investors
       Limited Partnership .....     2,347,330           --            --
     Writedown of electric power
       equipment ...............          --          331,018          --
     Management fee ............       381,594        401,085       328,952
     Accounting and legal fees .        75,111         39,853        31,750
     Interest ..................         7,081           --            --
     Miscellaneous .............        43,751         31,755        40,645
                                   -----------    -----------   -----------
         Total expenses ........     2,854,867        803,711       401,347
                                   -----------    -----------   -----------


         Net (loss) income .....   $(1,704,811)   $ 3,591,765   $ 1,970,401
                                   -----------    -----------   -----------




























                       See accompanying notes to financial statements.

                                      -F4-
<PAGE>



Ridgewood Electric Power Trust II
Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 1998, 1997 and 1996
--------------------------------------------------------------------------------

                                           Managing
                        Shareholders     Shareholder        Total
                       -------------   --------------   ------------

Shareholders' equity,
  January 1, 1996 ...   $ 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 ..........      1,950,697          19,704       1,970,401
                        ------------    ------------    ------------

Shareholders' equity,
  December 31, 1996 .     16,391,464         (37,705)     16,353,759

Cash distributions ..     (4,634,952)        (46,818)     (4,681,770)

Net income ..........      3,555,848          35,917       3,591,765
                        ------------    ------------    ------------

Shareholders' equity,
  December 31, 1997 .     15,312,360      15,263,754
                                                             (48,606)

Cash distributions ..     (1,412,273)        (14,265)     (1,426,538)

Net loss ............     (1,687,763)        (17,048)     (1,704,811)
                        ------------    ------------    ------------

Shareholders' equity,
  December 31, 1998 .   $ 12,212,324    $    (79,919)   $ 12,132,405
                        ------------    ------------    ------------
























                 See accompanying notes to financial statements.

                                      -F5-
<PAGE>

Ridgewood Electric Power Trust II
Statement of Cash Flows
--------------------------------------------------------------------------------

                                               Year Ended December 31,
                                    -----------------------------------------
                                       1998            1997           1996
                                    -----------    -----------    -----------
Cash flows from operating activities:
  Net (loss) income .............   $(1,704,811)   $ 3,591,765    $ 1,970,401
                                    -----------    -----------    -----------

  Adjustments to reconcile net
    (loss) income to cash flows
    from operating activities:
    Writedown of investment in
      Pittsfield Investors
      Limited Partnership .......     2,347,330           --             --   
    Writedown of electric power
      equipment .................          --          331,018           --   
    Gain on sale of RSD Power
      Partners, L.P. ............          --       (2,545,846)          --   
    Proceeds from sale of
      investment in RSD Power
      Partners, L.P.,  net ......          --        3,353,121           --   
    Proceeds from note receivable       380,135        178,999           --   
    Investments in power
      generation projects .......      (208,553)      (123,872)       (60,431)
    Changes in assets and
      liabilities:
    (Increase) decrease in
      other assets ..............        (1,152)        16,205         14,159
    Increase in due from
      affiliates ................        (8,819)          --             --   
    Increase (decrease) in
      accounts payable and
      accrued expenses ..........        68,711        (80,296)        67,687
    Increase in due to affiliates        77,879        136,494           --   
                                    -----------    -----------    -----------

    Total adjustments ...........     2,655,531      1,265,823         21,415
                                    -----------    -----------    -----------

    Net cash provided
      by operating activities ...       950,720      4,857,588      1,991,816
                                    -----------    -----------    -----------
Cash flows from financing
  activities:
  Proceeds from shareholders'
    contributions ...............          --             --           10,000
  Borrowings under line of
    credit facility .............       300,000           --             --   
  Cash distributions to
    shareholders ................    (1,426,538)    (4,681,770)    (2,103,791)
                                    -----------    -----------    -----------

    Net cash used in financing
      activities ................    (1,126,538)    (4,681,770)    (2,093,791)
                                    -----------    -----------    -----------

    Net (decrease) increase  in
      cash and cash equivalents .      (175,818)       175,818       (101,975)

Cash and cash equivalents,
  beginning of year .............       175,818           --          101,975
                                    -----------    -----------    -----------

Cash and cash equivalents, end
  of year .......................   $      --      $   175,818    $      --   
                                    -----------    -----------    -----------

Non-cash activities:
Note received from sale of
  RSD Power Partners, L.P. ......   $      --      $ 2,700,000    $      --   
                                    -----------    -----------    -----------




                 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 and  discontinued  its offering of 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 and thermal energy and other power plants that use various fuel
     sources (except  nuclear).  The power plants sell  electricity and, in some
     cases,  thermal  energy to utilities and industrial  users under  long-term
     contracts.

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

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

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

     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.

     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 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  amounts  presented  in prior  years  have  been  reclassified  for
     comparative purposes.
                                      -F7-
<PAGE>

3.       Investments in Power Generation Projects

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

                                                  December       December
                                                  31, 1998       31, 1997
                                                 -----------   -----------

      Pittsfield Investors Limited Partnership   $      --     $ 2,347,330
      B-3 Limited Partnership ................     4,001,843     4,001,843
      Sunnyside Cogeneration Partners, L.P. ..     5,425,020     5,432,339
      California Pumping Project .............     1,167,539       951,667
                                                 -----------   -----------
                                                 $10,594,402   $12,733,179
                                                 -----------   -----------

     The Trust's distribution income from the projects was as follows:

                                              For the Year Ended December 31,
                                           -------------------------------------
                                              1998         1997         1996
                                           ----------   ----------   ----------
Pittsfield Investors Limited Partnership   $  175,725   $  359,494   $  351,451
B-3 Limited Partnership ................      250,000      265,000      515,000
Sunnyside Cogeneration Partners, L.P. ..      515,403      784,449      757,498
California Pumping Project .............       12,448      183,623      129,179
RSD Power Partners, L.P. ...............         --         50,000      618,080
Project development limited partnerships         --         73,294         --
                                           ----------   ----------   ----------
                                           $  953,576   $1,715,860   $2,371,208
                                           ----------   ----------   ----------

     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
     also expires in November 2004.

     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 at least equal 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 also
     be entitled to receive  additional  distributions from any net cash flow in
     excess  of the 15%  return on its  investment.  The  aggregate  cost of the
     Trust's  investment in the partnership  was $2,347,330.  The Trust received
     distributions  of $175,725,  $359,494 and $351,451 from the project for the
     years ended December 31, 1998, 1997 and 1996, respectively.

     In 1998,  the City of  Pittsfield  closed the nearby  landfill to which the
     project had sent the ash residue  from the burning of the  municipal  solid
     waste.  The additional cost of transporting  the ash to other landfills has
     significantly reduced the cash flows generated by the project. Although the
     project manager is actively seeking ways to enhance the project's  revenue,
     the ability of the project to make distributions to the Trust in the future
     is  questionable.  Accordingly,  in 1998 the Trust  recorded a writedown of
     $2,347,330 to reduce the estimated fair value of the project to zero.

     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.
                                      -F8-
<PAGE>

     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 that in any given year available net
     cash  flow  from the  project  does not at least  equal  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 also be entitled to receive additional distributions from any net
     cash flow in excess of the 18% return on its investment. The aggregate cost
     of the Trust's  investment in the  partnership  was  $4,001,843.  The Trust
     received distributions of $250,000,  $265,000 and $515,000 from the project
     for the years ended December 31, 1998, 1997 and 1996, 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.  Electricity  is sold to the Pacific Gas and  Electric  Company
     ("PG&E")  under a long term contract  expiring in 2020. 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  aggregate  cost of the Trust's  investment  at
     December 31, 1998 and 1997 was $5,425,020 and $5,432,339, respectively. The
     Trust received  distributions  of $515,403,  $784,449 and $757,498 from the
     project for the years ended December 31, 1998, 1997 and 1996, respectively.

     In February 1999, PG&E notified the Monterey  Project that it had concluded
     that the  Monterey  Project had not met  certain  thermal  energy  delivery
     requirements of a cogeneration  facility. On April 1, 1999 it brought legal
     proceedings  against  the Trust's  subsidiary  that owns the  Project.  The
     complaint  only  requests that the Project  refund the gas price  discounts
     received, but an adverse  decision might affect  subsequent  years
     and might  also  serve as the basis for an action to  invalidate  the Power
     Contract.  The Trust is investigating the matter and is retaining  counsel.
     The Trust  believes  that the  Project  has met and  continues  to meet the
     requirements  and that the utility's  conclusion  can be supported  only by
     improper action by the utility. In particular, the Trust believes that PG&E
     has chosen a new location at which it is metering and computing  efficiency
     standards. That location is materially different from the location at which
     efficiency was measured from the inception of the Project and is located at
     a point  where  efficiency  measurements  necessarily  would be  materially
     lower. The Trust also is investigating whether there are systemic and other
     problems with the utility's data.  Although it is too early to estimate the
     precise  impact of this lawsuit on the Trust,  the Trust may incur material
     costs in defending this  proceeding and other  potential  action by Pacific
     Gas and Electric Company.

     California Pumping Project
     On March 31, 1995,  the Trust  acquired a package of natural gas and 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.  Prior to
     September  30, 1998,  the project was operated by a third party manager and
     the Trust  received 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. On October 1, 1998, the Trust terminated
     the operating  agreement  with the third party manager and Ridgewood  Power
     Management  Corporation,  an affiliate of the managing  shareholder,  began
     operating  the project.  The Trust paid $105,840 to the third party manager
     to terminate the operating  agreement.  The total investment in the project
     at December 31, 1998 and 1997 was  $1,167,539  and $951,667 and the project
     has an  equivalent  of 3 megawatts of power.  The  operator  pays for fuel,
     maintenance,  repair and replacement.  The Trust received  distributions of
     $12,448,  $183,623,  and  $129,179  from the  project  for the years  ended
     December 31, 1998, 1997 and 1996, 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 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 was entitled to receive annually
     the greater of either 80% of net profits, as defined, from the project or a
     preferred minimum return of 25% on its total investment. The aggregate cost
     of the Trust's  investment in the  partnership  was  $3,507,275.  The Trust
     received  distributions  of $50,000 and  $618,080  from the project for the
     years ended December 31, 1997 and 1996, respectively.
                                      -F9-
<PAGE>

     On June 25,  1997,  the Trust sold its entire  partnership  interest in RSD
     Power Partners,  L.P. to  subsidiaries of NRG Energy,  Inc. of Minneapolis,
     Minnesota  for  $6,150,000.  The  Trust  received  $3,450,000  in cash  and
     $2,700,000  in the form of an 8% promissory  note payable  monthly over six
     years.  The  sale  resulted  in  a  gain  of  $2,545,846,  after  deducting
     transaction costs of $96,879.

     Investments in project development limited partnerships In prior years, 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 partnerships of $1,065,798.

     In 1997, a major participant  refunded $73,294 to the Trust of its original
     capital  investment  of  $101,850.  The refund was  recorded as income from
     power generating projects for the year ended December 31, 1997.

4.       Electric Power Equipment

     The Trust purchased various used electric power generation  equipment to be
     used in potential  power  generation  projects.  The  equipment was held in
     storage and depreciation was not recorded. In 1997, the Trust wrote-off the
     equipment and recorded a loss of $331,018.

5.       Line of Credit Facility

     During  the  fourth  quarter  of 1997,  the  Trust and its  principal  bank
     executed  a  revolving  line of  credit  agreement,  whereby  the bank will
     provide a three year  committed  line of credit  facility of  $750,000.  At
     December 31, 1997,  there were no borrowings  outstanding  under the credit
     facility.  In 1998, the Trust borrowed  $300,000 under the credit facility.
     Outstanding  borrowings bear interest at LIBOR plus 2.5% (7.73% at December
     31,  1998).  These  borrowing  must be repaid by July 1,  1999.  The credit
     agreement  will  require  the Trust to  maintain  a ratio of total  debt to
     tangible  net  worth  of no more  than 1 to 1 and a  minimum  debt  service
     coverage ratio of 2 to 1.

6.       Transactions With Managing Shareholder And Affiliates

     The Trust 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.
     These  fees  were  recorded  as  a  reduction  in   shareholders'   capital
     contributions.

     The Trust also 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.

     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  paid  to  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,
     1998,  1997 and  1996,  the  Trust  paid  management  fees to the  managing
     shareholder  of $381,594,  $401,085 and $328,952,  respectively.  Under the
     terms of the management  agreement,  the annual management fee decreases to
     1.5% of the net asset value of the Trust effective February 1, 1999.

     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
                  -F10- 
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     distributions  for the remainder of the year.  The managing  shareholder is
     entitled  to  receive  1%  of  the  proceeds  from  dispositions  of  Trust
     properties until the shareholders  have received  cumulative  distributions
     equal to their original investment  ("Payout").  After Payout, the managing
     shareholder  is entitled to receive 20% of all remaining  distributions  of
     the Trust.

     Where  permitted,  in the event the  managing  shareholder  or an affiliate
     performs  brokering  services in respect of an  investment  acquisition  or
     disposition  opportunity  for the Trust,  the managing  shareholder or such
     affiliate may charge the Trust a brokerage  fee. Such fee may not exceed 2%
     of the gross proceeds of any such acquisition or disposition.  No such fees
     have been paid through December 31, 1998.

     The  managing  shareholder  owns 1.45  shares  of the Trust  with a cost of
     $121,800. In conjunction with the offering of the Trust shares, 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,  1998,  1997  and  1996,   Ridgewood   Management   charged   Sunnyside
     Cogeneration  Partners  $119,823,  $94,516 and $92,015,  respectively,  for
     overhead items  allocated in proportion to the amount  invested in projects
     managed.  During the three month period ended December 31, 1998,  Ridgewood
     Management  charged the  California  Pumping  Project  $25,973 for overhead
     items allocated in proportion to the amount  invested in projects  managed.
     Ridgewood Management also charged Sunnyside  Cogeneration  Partners and the
     California  Pumping Project for all of the remaining  direct  operating and
     non-operating expenses incurred during the periods.
                                     -F11-

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