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   0-23432

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

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


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


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

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

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

Shares of Beneficial Interest(Title of Class)

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

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


     There is no market for the Shares. The aggregate capital contributions made
for the Registrant's  voting Shares held by  non-affiliates of the Registrant at
April 9, 1999 was $39,034,440.


Exhibit Index is located on page 52.


<PAGE>
PART I

Item 1.  Business.

Forward-looking statement advisory

     This Annual Report on Form 10-K, as with some other  statements made by the
Trust  from  time to time,  has  forward-looking  statements.  These  statements
discuss business trends, year 2000 remediation and other matters relating to the
Trust's  future  results and the  business  climate  and are found,  among other
places,  at Items 1(c)(3),  1(c)(4),  1(c)(6)(ii)  and 7. In order to make these
statements,  the Trust has had to make assumptions as to the future. It has also
had to make estimates in some cases about events that have already happened, and
to rely on data  that may be found to be  inaccurate  at a later  time.  Because
these  forward-looking  statements  are  based  on  assumptions,  estimates  and
changeable  data,  and  because  any attempt to predict the future is subject to
other  errors,  what  happens  to the  Trust  in the  future  may be  materially
different from the Trust's statements here.

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

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

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

(a)  General Development of Business.

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

     The Trust sold whole and  fractional  shares of beneficial  interest in the
Trust  ("Investor  Shares") at $100,000 per Investor  Share,  and terminated its
private  placement  offering  on May 31,  1995,  at  which  time  it had  raised
approximately $39.2 million. Net of Offering fees, commissions and expenses, the
Offering  provided  approximately  $32.9  million  of net  funds  available  for
investments in the development and acquisition of Independent Power Projects and
associated  expenses.  The Trust has 943 record holders of Investor  Shares (the
"Investors").  As  described  below in Item  1(c)(2),  the  Trust  has  invested
substantially all of its net funds in seven sets of Independent Power Projects.

     The Trust is organized similarly to a limited partnership.

     Ridgewood  Power  Corporation  (the  "Managing  Shareholder"),  a  Delaware
corporation, is the Managing Shareholder of the Trust.

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


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


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

(b)  Financial Information about Industry Segments.

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

(c)  Narrative Description of Business.

(1)  General Description.

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

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


     The Trust has invested its funds in seven Projects or groups of Projects:

     (i) a 5.7 megawatt cogeneration facility located in Byron,  California (the
"Byron Project");
     (ii) an 8.5 megawatt cogeneration  facility located in Atwater,  California
(the "San Joaquin Project");
     (iii) a  portfolio  of what  were 35  cogeneration  facilities  located  in
California, New York, Massachusetts, Connecticut and Rhode Island, purchased
from Eastern Utilities Associates, Inc. (the "On-site
Cogeneration Projects");
     (iv)  an  additional  cogeneration  project  located  at  an  airline  food
preparation facility in Los Angeles, California (the "El Segundo Project");
     (v)  Ridgewood/AES  Power Partners,  L.P., a joint venture that operates 10
small  cogeneration  projects in New York and New  Jersey;
     (vi)  a 13.8  megawatt
electric  generation  plant  fueled by gas drawn from a sanitary  landfill  near
Providence,  Rhode Island (the  "Providence  Project")  and 
    (vii) a portfolio of seven power modules (each having a diesel engine and 
electric  generator mounted on a skid with  necessary  control and  transformer
equipment)  which are being marketed and operated by Hawthorne Power Systems,
Inc., Los Angeles,  California (the "Hawthorne Equipment Project").


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

(2)  The Trust's Investments.

(i)  San Joaquin Project.

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

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


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


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


     Distributions from the Project to the Trust for 1998 totalled $1,051,000 (a
17.3% annual  return),  down slightly from  $1,152,000 in 1997. The decrease was
largely  the  result  of  increased  operating  costs  from the move to 12 month
operation  from nine  months in 1997,  and of a brief  shutdown to install a new
boiler at JRW.


(ii)  Byron Project.

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

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

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


     Distributions  to the Trust from the Byron Project in 1998 were $465,000 (a
15.5% annual return), down from $572,000 in 1997. The decrease was the result of
increased  operating costs from the shift to 12 month operation from nine months
in 1997. See Item 7 - Management's Discussion and Analysis.


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

(iii)  On-site Cogeneration Projects


     In September  1995,  the Trust  purchased  the  ownership  interests in the
On-Site Cogeneration Projects, a portfolio of 35 "inside the fence" cogeneration
Projects owned by affiliates of Eastern Utilities Associates,  Inc. ("EUA"), for
an  aggregate  purchase  price of  approximately  $11.3  million.  The Trust has
invested an additional $1.4 million for capital improvements in the Projects and
has  expended  additional  amounts  on  remediation.  The  On-site  Cogeneration
Projects  use natural gas fired  turbines  or  reciprocating  engines to provide
electrical  energy and/or heat for industrial uses or air conditioning  purposes
under contracts with a variety of industrial customers. The On-site Cogeneration
Projects were located on 35 sites in  California  (18 sites),  Connecticut  (six
sites),  Massachusetts (two sites), New York (eight sites) and Rhode Island (one
site). The purchase  agreement provided that the acquisition would take place as
of September 30, 1995, and  accordingly the Trust assumed the benefits and risks
of the On-site  Cogeneration  Projects  accruing after that date.  Distributions
from the  On-site  Cogeneration  Projects  began  in 1996  and in 1998  totalled
$632,000  (a 15.2%  annual  return  based on the  investment  after  significant
writedowns), down from $1,424,000 in 1997.

     Returns from the On-site  Cogeneration  Projects  have  deteriorated  since
their  purchase and  beginning in the third quarter of 1997 the Trust has closed
the majority of the Projects for unprofitability or because of contract 
expirations.  As of March 1, 1999, only
12 of the  Projects  are still in  operation.  Because of closures  and contract
expirations,  the Trust has written down the value of its investment  from $13.1
million to $4.2 million.  See Note 3 to the Financial Statements for the details
of the  writedowns.  In the  future,  the Trust may  decide to close  additional
Projects because of contract expirations, unprofitability and other factors.

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

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

     The remaining 31 On-site  Cogeneration  Projects,  all of which are or were
natural-gas-fueled, were located in California and New York and had an aggregate
rated capacity of 5.5 Megawatts.  In 1996, the Trust  discontinued  operation of
and wrote off four  small  On-Site  Cogeneration  Projects  in this group with a
total rated  capacity of .24  Megawatts  of  electricity,  which had book values
totalling $113,000.  The discontinued Projects had produced nominal cash flow or
losses. In 1997 the Trust discontinued  operation of and wrote off 15 additional
Projects with a rated  capacity of 2.1  Megawatts in this group,  for a total of
$4.8 million.  After further  review in 1998,  the Trust wrote down the value of
the remaining 12 Projects by an additional  $4.1 million.  The Trust received an
arbitration award of $2.6 million against EUA for misrepresentations made by EUA
as to the  condition of certain of the On-Site  Cogeneration  Projects and other
misrepresentations, as described at Item 3 - Legal Proceedings.


     In purchasing the On-site Cogeneration  Projects,  the Managing Shareholder
concluded  that the costs of  engaging  third  party  managers  to operate  many
smaller  Projects  would  significantly  reduce total returns to the Trust.  The
Managing  Shareholder,  after reviewing the  alternatives,  elected to create an
in-house management capability as a means of limiting costs,  acquiring valuable
operating  and industry  knowledge and  increasing  efficiency.  It  accordingly
organized  an  affiliate,   Ridgewood  Power  Management   Company.   Management
responsibility   for  the  On-site   Cogeneration   Projects  was  substantially
transferred to the Managing  Shareholder and Ridgewood Power Management  Company
at the end of 1995.

     In January  1999 five of the  remaining  12  Projects  in this  group,  all
located on Long  Island in New York State,  were  transferred  to  Ridgewood/AES
Power  Partners,   L.P.   ("Ridgewood  AES"),  as  described  in  the  following
paragraphs.

(iv) Ridgewood/AES Power Partners, LLC.

     Instead of operating eight of the smallest  On-Site  Cogeneration  Projects
located in New York and Connecticut  itself or through RPMCo,  the Trust engaged
AES-NJ Cogen, Inc., a small operator of cogeneration plants in that area ("AES")
that is not  affiliated  with the  Trust to  operate  them  under  contract.  In
September  1997 the Trust and AES  created a joint  venture,  Ridgewood  AES, to
develop  additional  small  cogeneration  projects in the New York  metropolitan
area.  The Trust supplies  capital and AES supplies  development  services.  AES
receives a  operating  and  maintenance  fee of 1.1 cents per  kilowatt-hour  of
electricity  produced and is responsible for routine  maintenance;  the Trust is
entitled  to all  distributions  until it receives a  preferred,  non-cumulative
annual  return  of  16%  on  its  capital  investment,   and  then  any  further
distributions  are shared  equally with AES. At December 31, 1998  Ridgewood AES
owned five  cogeneration  projects at hotels and  hospitals  in New York and New
Jersey.  Distributions  from Ridgewood AES to the Trust in 1998 were $34,000 and
were $4,000 in 1997.  At December  31, 1998 the  Trust's  total  investment  was
$472,000.

     In January 1999 the Trust transferred five small  cogeneration  projects to
Ridgewood AES. Those projects had previously been operated by AES under contract
with the Trust.

(v)  Ridgewood El Segundo, LLC

         In April 1998 the Trust  purchased an additional  cogeneration  project
located at a food preparation facility for the Los Angeles International Airport
from a private  developer.  The project is located within one mile of an On-Site
Cogeneration  Project  also  owned  by the  Trust  at  the  Airport.  The  total
investment was $692,000 at December 31, 1998. No distributions were made in 1998
from the Project to the Trust.

(vi)  Providence Project


     The  Trust  and  Ridgewood  Electric  Power  Trust  IV, a  similar  program
organized by the Managing Shareholder  ("Ridgewood Power IV"), acquired in April
1996 all of the equity  interest in the  Providence  State Landfill Power Plant,
located near  Providence,  Rhode Island.  The Trust invested $7.1 million in the
Project  and  Ridgewood  Power IV  supplied  the  remainder  of the $20  million
investment in the Project.  The acquisition cost was approximately $15.5 million
(including  a $3 million  partial  prepayment  of Project debt as a condition of
obtaining the lenders'  consents and transaction  costs)and the remainder of the
investment  by the programs  represents  funds  applied to  operating  reserves,
working capital and reserves for capital improvements and expansion. The Project
is encumbered by $5.4 million of debt maturing in installments  through 2004. In
1997, as described below,  capital  improvements  were completed and the Trust's
total investment in the Project  increased to $7,504,000.  At December 31, 1998,
intercompany transfers had reduced that amount to $7,310,000.


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

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


     Since the Trust  purchased the Project in April 1996,  average  output from
the existing eight engine-generator sets has risen by approximately 25% from 9.2
Megawatts in the first three months of 1996 to 12.2  Megawatts in December  1996
and 11.5 Megawatts in 1997. Since August 1997,  monthly sales have approached or
equalled  the 12.0  Megawatt  maximum  under  the  Power  Contract.  In order to
increase  output to the maximum and to allow engines to be rotated  off-line for
preventative maintenance,  an additional engine and generator set were installed
at the Project in spring 1997.  Although this increased nominal Project capacity
by  approximately  1/8,  the actual  benefit  is the  ability to have one engine
off-line at any time for maintenance and still produce the entire 12.0 Megawatts
that can be sold  under the  existing  Power  Contract.  Distributions  from the
Project for 1998 to the Trust totalled $547,000 (a 7.5% annual return) down from
$923,000  for  1997.   The  decrease  is  primarily   the  result  of  increased
expenditures   in  1998  for  regularly   scheduled   overhauls  and  preventive
maintenance of engines.  

(vii) Hawthorne Equipment

     In  January  1999  the  Trust  agreed  to  purchase  for  $2,361,000  seven
Caterpillar  unified power modules  (consisting  of a diesel engine and a linked
generator on a single skid, with control equipment) for delivery in June 1999. A
deposit of  $590,000  was paid in  February  1999.  The  purchase  is being made
through  Hawthorne Power Systems,  Inc. of Los Angeles,  California,  which is a
dealer of  Caterpillar  power systems and which also maintains a rental fleet of
similar power modules.  Hawthorne will market the Trust's modules along with its
own fleet for  emergency,  temporary or peak power  supplies for  industrial and
commercial  customers,  both domestic and  international,  and will maintain the
modules.  Hawthorne  will charge the Trust its customary  fees, not in excess of
those  applicable to its own fleet, for marketing and maintenance and all profit
or loss after  payment  of those  fees and taxes will be for the  account of the
Trust.

     Except for possible additional investments through Ridgewood AES, the Trust
does not expect to make further investments.


(3)  Project Operation.

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

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


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


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


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

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

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

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

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

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

<TABLE>
<CAPTION>
                                           Calendar year
                                   1998          1997          1996
<S>                             <C>             <C>          <C>
Pacific Gas & Electric Co.          56%           42.3%        34.3%
 (San Joaquin & Byron Projects)
New England Electric System         20%           22.6%        16.0%
 (Providence Project)
Globe Manufacturing Co.             12%           18.3%        18.7%
 (Massachusetts Projects)
The Worcester Company                0%            6.9%        16.3%
 (Rhode Island Project)
</TABLE>


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


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

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

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

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

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

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

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


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


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

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

     In recent years,  many  electric  utilities  have  attempted to exploit all
possible means of terminating  Power Contracts with independent  power projects,
including  requests to  regulatory  agencies  and  alleging  violations  of even
immaterial terms of the Power Contracts as justification  for terminating  those
contracts.  An affiliate  of the Trust,  Ridgewood  Electric  Power Trust II, is
facing  litigation from Pacific Gas and Electric Company  challenging the status
of that trust's Monterey Project,  a sister project to the Byron and San Joaquin
Projects. No action against the Trust's Projects is anticipated at this time. If
such an  attempt  were to be  made,  the  Trust  might  face  material  costs in
contesting  those utility  actions.  Other utilities have from time to time made
offers to purchase and  terminate  Power  Contracts for lump sums. No such offer
has been  suggested  or made to the  Trust,  although  the Trust is  considering
making such an offer to Pacific Gas & Electric.


     Finally,  the Power  Contracts are subject to  modification or rejection in
the  event  that  the  utility  purchaser  enters  bankruptcy.  There  can be no
assurance that the utility purchaser will not declare bankruptcy.

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


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


(5)  Competition

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

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

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

(i)  Potential Legislation and Regulation.

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

(6)  Regulatory Matters.

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

(i)  Energy Regulation.

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

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

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


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

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

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

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

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

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

(ii)  Environmental Regulation.

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


     In September  1998 the  Environmental  Protection  Agency  ("EPA")  brought
administrative  proceedings  against the  Providence  Project for  violations of
training, recordkeeping and signage requirements. The alleged violations and the
proceedings are described at Item 3 - Legal Proceedings, below.


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

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

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

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

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

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

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

(iii)  The 1940 Act

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

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

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

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

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

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

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

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

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

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

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

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

(E)  Employees.

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


Item 2.  Properties.

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

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



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


Byron         Byron,      Leased    2021         2      28,000      Gas-fired
            California                                            cogeneration
                                                                      facility
San Joaquin  Atwater,     Leased    2021         1      25,000       Gas-fired
            California                                            cogeneration
                                                                      facility

On-Site      7 sites     Leased   various       n/a       n/a     Inside-the-
 Cogen-        in CA,       or                                          fence,
 eration      CT, MA,   licensed                                    gas-fired
              and NY                                                or diesel-
                                                                       fueled
                                                                 cogeneration
                                                                  engines and
                                                                    generators
Providence   Providence,  Leased    2020         4      10,000       Landfill
             Rhode Island                                            gas-fired
                                                                    generation
                                                                      facility

Ridgewood    10 sites in  Licensed  various     n/a       n/a      Inside-the-
 AES          NY and NJ                                             fence, gas-
                                                                        fired
                                                                   cogeneration
                                                                   engines and
                                                                    generators
Ridgewood    Los Angeles, Licensed              n/a        n/a   Inside-the-
 El Segundo   CA                                                  fence, gas-
                                                                    fired
                                                                 cogeneration
                                                                    facility


Item 3.  Legal Proceedings.


     In December 1996 the Trust's subsidiaries that own the on-site cogeneration
projects  brought an  arbitration  proceeding  against  EUA before the  American
Arbitration Association in Boston,  Massachusetts as provided in the acquisition
agreement, claiming that EUA had breached its representations in the acquisition
agreement and had also defrauded the Trust through misrepresentations,  improper
billing  practices,  fraud and  violations of state fair trade practice laws. In
October  1998,  the  arbitrators  awarded  the Trust  damages  of  approximately
$2,605,000   on  certain  of  its  claims  of   misrepresentation   and  awarded
approximately $395,000 to EUA for alleged unpaid management services thereon. In
November  1998,  EUA made a payment of  $2,210,000 to the Trust to liquidate the
claims.  After deducting costs associated with the arbitration  proceeding,  the
Trust recognized income of $1,265,000.

     The  arbitration  panel  also  awarded  the Trust its  attorneys'  fees and
expenses incurred in prosecuting its case in chief,  which the Trust computed at
approximately  $997,000,  and  awarded  EUA its  attorneys'  fees  and  expenses
incurred in prosecuting its  counterclaim.  The panel is expected to rule by the
end of April 1999 on  objections  raised by each party to the  others'  fees and
expenses and to make a final award.  EUA has also refused to pay interest at 12%
per year  awarded  by the panel on the  Trust's  award  from  September  1995 to
November 1998 until a final ruling by the panel.

     The Trust has brought a motion in the United States  District Court for the
District  of  Massachusetts  to confirm  the  award,  which will await the final
ruling  of the  panel on the  attorneys'  fees and  expenses.  The Trust has not
recorded any potential  recovery on fees,  expenses and interest pending a final
ruling or payment.

     In September 1998 the Region I office of the U.S. Environmental  Protection
Agency  (the  "EPA")  filed  an  administrative   proceeding  against  Ridgewood
Providence Power Partners,  L.P. ("RPPP"), a subsidiary of the Trust, seeking to
recover civil penalties of up to $190,000 for alleged  violations of operational
recordkeeping and training requirements at the Providence Project. RPPP answered
and the matter has been referred to an alternative dispute resolution  procedure
within  the EPA.  In the  course of  discussions  with the EPA and  through  the
alternative dispute resolution procedure,  EPA has offered to reduce the penalty
to $88,750.  Further, EPA is discussing with RPPP a proposal to offset a portion
of  the  penalty  by  crediting  RPPP  with  certain   environmental  audit  and
remediation  expenditures,  over and above those required by law, that the Trust
and other Ridgewood Power Trusts may agree to make. RPPP expects to resolve this
matter in the second quarter of 1999 and does not  anticipate  that it will have
to make further material capital  expenditures to remedy the items identified by
the EPA or that this proceeding  will have a material  adverse impact on it. The
Trust does not anticipate  that it will be liable or will have to fund the costs
of this proceeding. Costs of defense and settlement will be paid by the Project.

     On  December  31,  1998  the  Trust,  through  subsidiaries,  filed a legal
complaint in the  Superior  Court of  California  for  Monterey  County  against
Waukesha-Pierce,  Inc. and subsidiaries,  alleging that the subsidiaries had not
disclosed the existence of an obligation of the Monterey  Project to Pacific Gas
and  Electric  Company  and  therefore  breached a warranty  in the  acquisition
agreement.  The claim was for approximately $273,000 plus interest and expenses.
Waukesha-Pierce, Inc. was included in the proceeding as a contractual guarantor.
On January 17, 1999, a separate action against  Waukesha-Pierce,  Inc. was filed
by the Trust's subsidiaries in the United States District Court for the Northern
District  of  Texas  to  enforce  the  guaranty.  The  parties  are  considering
settlement  negotiations  but the Trust will vigorously  pursue these actions if
settlement is not promptly achieved.


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

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


     The Managing Shareholder is considering the possibility of a combination of
the Trust and five other investment programs sponsored by the Managing
Shareholder  (Ridgewood Electric Power Trusts I, II, 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  combined  entity 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 973 record holders of Investor
Shares.

(c)  Dividends


     The Trust made distributions as follows in the years 1997 and 1998:

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

Total distributions

 to Investors                $3,045,001                $2,352,106
Distributions per
 Investor Share                   7,771                     6,003
Distributions to
 Managing Shareholder            30,758                    23,759


     Distributions  have  been  made  on a  monthly  basis.  Because  of  recent
reductions in the rate of  distributions  to $500 per month,  effective  January
1999, the Trust has proposed  making future  distributions  on a quarterly basis
beginning at some time during the second quarter of 1999. 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.


     The Trust's cash flow comes  primarily  from  distributions  from Projects.
Those distributions are from cash flow of the Projects, which includes income of
Projects plus funds representing  depreciation and amortization charges taken by
the Projects.  Because the Trust's  objective is to distribute  net cash flow, a
substantial  portion of many  distributions  by the Trust will include cash flow
derived from depreciation and amortization charges against assets at the Project
level.  Nevertheless,  because the Projects are not consolidated  with the Trust
for accounting  purposes,  all funds received from Projects are considered to be
revenue to the Trust for accounting  purposes.  Occasionally,  distributions may
also include cash released from operating or debt service reserves,  Trust-level
depreciation  or  amortization,  or other  non-cash  charges  against  earnings.
Investors  should be aware that the Trust is  organized  to return net cash flow
rather than accounting income to Investors.

Item 6.  Selected Financial Data.

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

<TABLE>
<CAPTION>

Supplemental Information      As of and      As of and     As of and     As of and
Schedule                       for the        for the        for the      for the
Selected Financial Data      Year ended    Year Ended     Year Ended     Year Ended    Period Ended
                            December 31,  December 31,    December 31,   December 31    December 31,
                               1998          1997            1996          1995           1994

Total Fund Information:

<S>                         <C>           <C>               <C>              <C>             <C>



Net revenue from

 operating projects           $2,727,986     $4,075,390        $3,525,613       $1,317,287           $0
Net income (loss)               (798,415)    (1,355,866)(B)     2,541,686        1,440,550     (213,299)
                                  (A),(C)

Net assets

 (shareholders' equity)       23,783,034      26,957,314        31,388,939       32,579,226    18,671,356

Investments in project
 development and power
 generation limited

 partnerships                 21,714,050      24,613,978       28,050,750       20,884,493            0
Total assets                  24,257,396      27,336,224       31,430,075       32,651,668    18,405,145

Per Investor Share:

  Revenues                       $10,404        $10,788            $9,630           $6,066       $1,178
                                   (C)
  Expenses                        12,442         14,249(B)          3,143            2,389        2,144
                                   (A)
  Net income (loss)               (2,038)        (3,460)            6,486            3,676         (966)
                                (A)(B)(C)
  Net asset value                 60,695          68,796            80,106           83,143       84,598
Distributions to Investors         6,003          7,771             9,429            5,896            0


</TABLE>


 (A) After writedowns of investments in 1998 of $4,055,214 ($10,349 per Investor
Share).
 (B)  After writedowns of investments in 1997 of $4,743,631 ($12,106 per

Investor Share).

 (C) Includes  $1,265,122 ($3,229 per Investor Share) of income from arbitration
award.


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


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


Results of Operations

The year ended December 31, 1998 compared to the year ended December 31, 1997.

     In 1998  and  1997,  the  Trust's  net loss was  $798,000  and  $1,356,000,
respectively. The loss primarily resulted from 1998 and 1997 charges to earnings
of $4,055,000 and  $4,744,000,  respectively,  relating to the write-down to net
realizable value of the Trust's investment in the on-site cogeneration  projects
acquired from affiliates of EUA in 1995.

     The Trust's subsidiaries that own the on-site cogeneration projects brought
an  arbitration  proceeding  against  EUA,  as  described  at  Item  3  -  Legal
Proceedings.  The Trust has not recorded amounts of the award that are currently
being considered by the arbitration panel or that EUA has refused to pay.

     Without the  write-downs  of the on-site  cogeneration  projects and income
from the  arbitration  award,  net income for 1998 would have been $1,992,000 as
compared to $3,388,000 for 1997, a decrease of $1,396,000 (41.2%). This increase
reflects a $1,347,000  decrease in income  received  from  Projects in which the
Trust has invested and a decrease of $68,000 in interest income. The decrease in
interest income reflected the Trust's lower average cash balances.

As summarized below,  income from power generation  projects  decreased 33.1% to
$2,728,000 in 1998 compared to $4,075,000 in 1997:

Project                                1998               1997

On-site Cogeneration:
    Massachusetts                    $  324,000     $   745,000
    Rhode Island                          ---           283,000
    New York                            243,000         293,000
    Others                               65,000         104,000
    Subtotal                            632,000       1,425,000
Ridgewood AES                            34,000           4,000
San Joaquin                           1,051,000       1,152,000
Providence                              547,000         923,000
Byron                                   464,000         571,000

Total                               $ 2,728,000      $4,075,000

     In 1998,  income  from  the San  Joaquin,  Byron  and  Providence  Projects
decreased  by  $101,000  (8.8%),  $107,000  (40.7%)  and  $376,000  (18.7%)  and
respectively.  The  decrease  in income  from San  Joaquin  and Byron  reflected
reduced  margins from  operating  year round in 1998  compared to nine months of
operations in 1997. The change to year round  operations was  necessitated  by a
change in the structure of the capacity payments from the utility.  The decrease
in income from the  Providence  Project  reflects  the costs of periodic  engine
maintenance. In 1998, income from the On-Site Cogeneration Projects decreased by
$793,000 (55.6%) as a result of the problems discussed above.

     Excluding the writedown of investments, total expenses decreased by $20,000
(2.3%) to  $820,000  in 1998 from  $840,000 in 1997.  Management  fees  declined
$93,000  (12.1%) to $674,000 in 1998 from $767,000 in 1997  reflecting the lower
net  assets of the  Trust.  Accounting  and  legal  expenses  increased  $48,000
(102.1%)  from  $47,000 in 1997 to  $95,000  in 1998 as a result of legal  costs
associated with disputes that were resolved in 1998.

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

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

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

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

Project                                 1997               1996

On-site Cogeneration:
    Massachusetts                   $   745,000        $ 660,000
    Rhode Island                        283,000          573,000
    New York                            293,000          161,000
    Others                              104,000          362,000
    Subtotal                          1,425,000        1,756,000
Ridgewood AES                             4,000             ---
San Joaquin                           1,152,000          779,000
Providence                              923,000          562,000*
Byron                                   571,000          429,000

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


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


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


Liquidity and Capital Resources


     For 1998, net cash provided by operating  activities was $2,103,000,  which
included  deductions of $1,155,000 for additional  investments in projects.  For
1997,  net cash provided by operating  activities  was  $2,804,000.  This amount
included a  $900,000  termination  payment  from the Rhode  Island  cogeneration
project and a deduction of $2,099,000  for  additional  investments in projects.
Cash  distributions  to  shareholders  were  $2,376,000  in 1998 as  compared to
$3,076,000 in 1997. As a result of lower earnings from the On-site  Cogeneration
Projects, monthly cash distributions were reduced to $500 per share in July 1997
from an average of $800 per share during the first six months of the year.

     During 1998 the Trust  acquired an on-site  cogeneration  facility (the "El
Segundo Project") in Los Angeles,  California, for $692,000. In addition, during
1998,  the Trust  invested an  additional  $331,000 in a series of  cogeneration
projects in New York and New Jersey (the "Ridgewood/AES  Projects"). In February
1999, the Trust made a $590,000 deposit for seven Caterpillar power modules that
are expected to be delivered in June 1999.  The seven power modules have a total
purchase  price of  $2,361,000.  The Trust  plans to rent the power  modules  to
domestic and international customers.

     During 1997,  the Trust and Fleet Bank,  N.A.  (the "Bank")  entered into a
revolving  line of credit  agreement,  whereby  the Bank  provides  a three year
committed  line of credit  facility of  $750,000.  Outstanding  borrowings  bear
interest at the Bank's prime rate or, at the Trust's choice, at LIBOR plus 2.5%.
The credit  agreement  requires  the Trust to  maintain a ratio of total debt to
tangible net worth of no more than 1 to 1 and a minimum  debt  service  coverage
ratio of 2 to 1. The credit facility was obtained in order to allow the Trust to
operate using a minimum amount of cash, maximize the amount invested in Projects
and maximize cash distributions to shareholders.  There were no borrowings under
the line of credit in 1998 or 1997.

     Other than  investments  of available  cash in power  generation  Projects,
obligations of the Trust are generally  limited to payment of the management fee
to the Managing Shareholder,  payments for certain accounting and legal services
to third persons and  distributions to shareholders of available  operating cash
flow generated by the Trust's  investments.  The Trust's policy is to distribute
as much cash as is prudent to shareholders. Accordingly, the Trust has not found
it necessary to retain a material amount of working capital.  The need to retain
working  capital is further  reduced by the  availability  of the line of credit
facility.  The Trust anticipates that its cash flow from operations during 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 the April of 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 $600.

     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.  The Managing  Shareholder's  plan called for  completion of
changes to the distribution  system and testing of that system by the end of the
first quarter of 1999 and the Managing  Shareholder believes that this effort is
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 $9,500 and is estimated to be approximately $9,000 for 1999.

     Each of the Trust's electric generating facilities is being reviewed during
the  first  quarter  of 1999 by an  outside  consultant  or by  Ridgewood  Power
Management  Corporation personnel 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  small  electric
generating  facilities that 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  systems  having  a  material  impact  on  output,  environmental
compliance,  recordkeeping  or any  other  material  impact  that have Year 2000
concerns.  To date, initial reviews at the Byron and San Joaquin facilities have
not  discovered any systems  vulnerable to Year 2000 issues.  The Providence and
On-Site Cogeneration facilities have not yet been reviewed. The Trust's share of
the estimated costs of the 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  utilities  that  purchase 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 were 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.

     The Trust's main supply contingency is the availability of natural gas from
pipelines  for  fueling  engine  sets at the  Byron,  San  Joaquin  and  On-Site
Cogeneration  facilities.  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  plants.
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 utility  customers  and material  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 manual or analog control systems if
Year 2000 problems  cannot be  remediated.  Because the plants are small and use
simple  technologies  (diesel engines and conventional  generators) that are not
dependent on computers or date-sensitive electronics, the Trust believes that it
is unlikely that any facility other than the Providence facility would be unable
to operate  because of Year 2000  problems at the facility.  The Trust  believes
that the  Providence  facility will also be capable of operation but is awaiting
the results of the systems review.

     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
Byron, San Joaquin and On-Site  Cogeneration  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 be
materially  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. The Trust believes that the Providence facility will also be capable of
operation  after January 1, 2000.  For purposes of a worst case scenario it will
assume,  until  the  survey  of  embedded  components  is  completed,  that  the
Providence  facility  would not be able to operate after January 1, 2000 because
there might be an embedded  component  that is not Year 2000  compliant  and the
component  could not be replaced in time. In 1998,  revenues from the Providence
Plant comprised about 20% of the Trust's operating  revenues.  In addition,  the
Byron,  San  Joaquin  and On-Site  Cogeneration  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,  which
would have material adverse effects on the Trust.

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
                                                 1999
                                              (U.S. $)

Bank Deposits and Certificates
  of Deposit                             $   2,414,916
  Average interest rate                          5.225%


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 Three Years
      ended December 31, 1998                                F-4
     Statement of Changes in Shareholders'
      Equity for Three Years ended December 31,
      1998                                                   F-5
     Statement of Cash Flows for Three Years
      ended December 31, 1998                                F-6

     Notes to Financial Statements                   F-7 to F-13

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

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

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


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

     Robert  E.  Swanson  has  been  the  President,   sole  director  and  sole
stockholder of Ridgewood Power Corporation since its inception in February 1991.

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

     A number of other  companies are  affiliates  of Mr.  Swanson and Ridgewood
Power.  Each of these also was organized as a corporation  that was wholly-owned
by Mr. Swanson.  

     The Managing  Shareholder is an affiliate of Ridgewood  Energy  Corporation
("Ridgewood  Energy"),  which has 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 is  controlled  by Robert E.  Swanson,  who is their sole  director or
manager.


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

     Thomas R. Brown,  age 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 is also Senior Vice  President of Ridgewood  Capital and of 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 is also the
Chief Financial  Officer of Ridgewood  Capital and of Ridgewood  Capital Venture
Partners, LLC and Ridgewood Institutional Venture Partners, LLC.

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


(c)  Management Agreement.

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

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

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


     The Board of the Trust (including both initial  Independent  Trustees) have
approved  the initial  Management  Agreement  and its  renewals.  Each  Investor
consented to the terms and  conditions  of the initial  Management  Agreement by
subscribing to acquire  Investor Shares in the Trust.  The Management  Agreement
will remain in effect until January 4, 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.  RPMCo The officers have the
duties and powers usually  applicable to similar officers of a Delaware business
corporation in carrying out Trust  business.  Officers act under the supervision
and control of the Managing Shareholder, which is entitled to remove any officer
at any  time.  Unless  otherwise  specified  by the  Managing  Shareholder,  the
President  of the  Trust  has full  power to act on  behalf  of the  Trust.  The
Managing  Shareholder  expects that most actions  taken in the name of the Trust
will be  taken  by Mr.  Swanson  and  the  other  principal  officers  in  their
capacities  as  officers  of the  Trust  under  the  direction  of the  Managing
Shareholder rather than as officers of the Managing Shareholder.


(e)  The Trustees.

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

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


     Ralph O. Hellmold,  age 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.I.A.  from  Columbia  University.  He is a
Chartered  Financial  Analyst  and a member of the New York  Society of Security
Analysts.  Mr.  Hellmold  is the holder of one-half  share in each of  Ridgewood
Power I and Ridgewood  Power III, a shareholder  of one-half  Share in the Trust
and a limited  partner or shareholder  in numerous  limited  partnerships  and a
business  trust  sponsored  by  Ridgewood  Energy  to  invest  in  oil  and  gas
development and related businesses. Mr. Hellmold is a director of Core Materials
Corporation,  Columbus, Ohio 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 II, Ridgewood Power IV and Ridgewood Power
V and of an oil and gas business  trust  sponsored  by  Ridgewood  Energy and is
expected to be a trustee of other similar  entities that may be organized by the
Managing Shareholder and Ridgewood Energy. The President, sole director and sole
stockholder  of  Ridgewood  Holding is Robert E.  Swanson;  its other  executive
officers are  identical to those of the  Managing  Shareholder.  See -- Managing
Shareholder.  The principal office of Ridgewood  Holding is at 1105 North Market
Street, Suite 1300, Wilmington, Delaware 19899.

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

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

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

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


(g)  RPMCo.

     As  discussed  above  at  Item  1  -  Business,  RPMCo  assumed  day-to-day
management  responsibility for the San Joaquin, Byron, On- site Cogeneration and
Providence Projects in 1996. 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 does 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,  togetherwith  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 50, joined RPMCo in June 1996 as Vice President
of  Operations.  He has  over  27  years  of  experience  in the  operation  and
maintenance of power plants.  From 1992 until joining 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.  Since 1996 the Managing Shareholder has
compensated these persons without  additional  payments by the Trust and will be
reimbursed by Ridgewood Energy for costs related to Ridgewood Energy's business.
The Trust will  reimburse  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  1998  the  Trust  paid  each
Independent Trustee $5,000 for his services.  The Board of the Trust is entitled
to review the  compensation  payable to the  Independent  Trustees  annually and
increase or decrease it as the Board sees reasonable.  The Trust is not entitled
to pay the Independent Trustees compensation for consulting services rendered to
the Trust  outside the scope of their  duties to the Trust  without  prior Board
approval.

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

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

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

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

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

Item 13.  Certain Relationships and Related Transactions.

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

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

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

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


<TABLE>
<CAPTION>

Fee                 Paid to       1998              1997            1996         1995                  1994

<S>              <C>           <C>            <C>           <C>               <C>           <C>  
Management         Managing          $673,933    $ 766,866        $794,026      $482,000                  $0
 fee              Shareholder

Cost
 reimbursements*    RPMCo          15,617,631   14,308,444      11,566,400             0                   0

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

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

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


</TABLE>


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


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


     The management fee,  payable monthly under the Management  Agreement at the
annual rate of 2.5% of the Trust's net asset value,  began on the date the first
Project was  acquired  and  compensates  the  Managing  Shareholder  for certain
management,  administrative  and advisory services for the Trust. In addition to
the  foregoing,  the  Trust  reimbursed  the  Managing  Shareholder  at cost for
expenses and fees of unaffiliated  persons  engaged by the Managing  Shareholder
for Trust  business  and in 1995 for payroll and other costs of operation of the
Trust's Projects.  Beginning in 1996, these  reimbursements  were paid to RPMCo.
The reimbursements to RPMCo, which do not exceed its actual costs, 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 of Registrant's  Registration  Statement filed with the Commission on
February 15, 1994.

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

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

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

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

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

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

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

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

     24.   Powers of Attorney                         Page 69

     27.   Financial Data Schedule                    Page 72



<PAGE>


<PAGE>


SIGNATURES

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

Signature                      Title                        Date

RIDGEWOOD ELECTRIC POWER TRUST III (Registrant)


By:/s/ Robert E. Swanson    President and Chief    April 14, 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 and
       Martin V. Quinn   Chief Financial Officer   April 14, 1999

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


*  As attorney-in-fact for the Independent Trustee


                       Ridgewood Electric Power Trust III

                              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 III

     In our opinion,  the accompanying balance sheets and the related statements
     of operations,  changes in  shareholders'  equity and of cash flows present
     fairly,  in all  material  respects,  the  financial  position of Ridgewood
     Electric  Power Trust III (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 $21,714,050 and $24,613,978 (91% of  shareholders'  equity) 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 III
Balance Sheet
--------------------------------------------------------------------------------

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

Assets:

Investments in power generation projects .   $ 21,714,050    $ 24,613,978
Cash and cash equivalents ................      2,414,916       2,687,626
Due from affiliates ......................         30,071          20,458
Other assets .............................         98,359          14,162
                                             ------------    ------------

         Total assets ....................   $ 24,257,396    $ 27,336,224
                                             ------------    ------------




Liabilities and Shareholders' Equity:

Liabilities:
Accounts payable and accrued expenses ....   $    185,209    $     38,537
Due to affiliates ........................        289,153         340,373
                                             ------------    ------------

         Total liabilities ...............        474,362         378,910

Commitments and contingencies

Shareholders' equity:
Shareholders' equity (391.8444
  shares issued and outstanding) .........     23,876,239      27,018,776
Managing shareholder's accumulated deficit        (93,205)        (61,462)
                                             ------------    ------------

         Total shareholders' equity ......     23,783,034      26,957,314
                                             ------------    ------------

         Total liabilities and
           shareholders' equity ..........   $ 24,257,396    $ 27,336,224
                                             ------------    ------------
















                 See accompanying notes to financial statements.

                                      -F3-
<PAGE>



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

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

   Income from power generation
     projects .....................   $ 2,727,968    $ 4,075,390    $ 3,525,613
   Interest income ................        83,807
                                                                        247,762
   Income from arbitration award ..     1,265,122           --             --
                                      -----------    -----------    -----------
         Total revenue ............     4,076,897      4,227,395      3,773,375

Expenses:
     Project due diligence costs ..          --            3,692
                                                                        258,378
     Management fee ...............       673,933        766,866
                                                                        794,026
     Accounting and legal fees ....        94,734         46,869
                                                                         48,231
     Miscellaneous ................        51,431         22,203
                                                                         18,012
     Writedown of investments
       in power generation projects     4,055,214      4,743,631        113,042
                                      -----------    -----------    -----------
         Total expenses ...........     4,875,312      5,583,261      1,231,689
                                      -----------    -----------    -----------

         Net (loss) income ........   $  (798,415)   $(1,355,866)   $ 2,541,686
                                      -----------    -----------    -----------





























                 See accompanying notes to financial statements.

                                      -F4-
<PAGE>





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

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

Shareholders' equity,
  January 1, 1996 .....   $ 32,584,476    $     (5,250)   $ 32,579,226

Cash distributions ....     (3,694,661)        (37,312)     (3,731,973)

Net income for the year      2,516,269          25,417       2,541,686
                          ------------    ------------    ------------

Shareholders' equity,
  December 31, 1996 ...     31,406,084         (17,145)     31,388,939

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

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

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

Cash distributions ....     (2,352,106)        (23,759)     (2,375,865)

Net loss for the year .       (790,431)         (7,984)       (798,415)
                          ------------    ------------    ------------

Shareholders' equity,
  December 31, 1998 ...   $ 23,876,239    $    (93,205)   $ 23,783,034
                          ------------    ------------    ------------
























                 See accompanying notes to financial statements.

                                      -F5-
<PAGE>





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

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

Cash flows from operating
  activities:
Net (loss) income ............   $   (798,415)   $ (1,355,866)   $  2,541,686
                                 ------------    ------------    ------------
Adjustment to  reconcile  net
  (loss)  income to net cash
  flows  from  operating
  activities:
Writedown of power generation
   project investments
                                    4,055,214       4,743,631         113,042
Investments in power
  generation projects ........     (1,155,286)     (2,098,774)     (7,279,299)
Proceeds from sale or transfer
  of investment ..............           --           900,000         353,619
Changes in assets and
  liabilities:
 (Increase) decrease in due
   to/from affiliates, net ...        (60,833)        320,915        (109,085)
 Decrease in deferred due
   diligence costs ...........           --            30,000         273,213
 (Increase) decrease in other
   assets ....................        (84,197)        266,838         (88,808)
 Increase (decrease) in
   accounts payable and
   accrued expenses ..........        146,672          (2,599)        (85,731)
                                 ------------    ------------    ------------
   Total adjustments .........      2,901,570       4,160,011      (6,823,049)
                                 ------------    ------------    ------------
   Net cash provided by (used
     in)operating activities .      2,103,155       2,804,145      (4,281,363)
                                 ------------    ------------    ------------

Cash flows from financing
  activities:
  Cash distributions to
    shareholders .............     (2,375,865)     (3,075,759)     (3,731,973)
                                 ------------    ------------    ------------

  Net cash used in financing
    activities ...............     (2,375,865)     (3,075,759)     (3,731,973)
                                 ------------    ------------    ------------

  Net decrease in cash and
    cash equivalents .........       (272,710)       (271,614)     (8,013,336)

Cash and cash equivalents,
  beginning of year ..........      2,687,626       2,959,240      10,972,576
                                 ------------    ------------    ------------

Cash and cash equivalents,
  end of year ................   $  2,414,916    $  2,687,626    $  2,959,240
                                 ------------    ------------    ------------












                 See accompanying notes to financial statements.
-F6-
<PAGE>



Ridgewood Electric Power Trust III
Notes to Financial Statements
--------------------------------------------------------------------------------


1.       Organization and Purpose

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

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

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

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 original  maturities of
three months or less when purchased to be cash and cash equivalents.

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

Income taxes
No provision is made for income taxes in the accompanying  financial  statements
as the income or losses of the Trust are passed  through and included in the tax
returns of the individual shareholders of the Trust.
                                      -F7-


<PAGE>


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

3.       Investments in Power Generation Projects

The Trust had the following investments in power generation projects:

                                                 Fair Values as of December 31,
                                                         1998          1997
                                                     -----------   -----------

JRW Associates, L.P. .............................   $ 6,087,039   $ 5,481,186
Byron Power Partners, L.P. .......................     2,999,031     2,734,331
Ridgewood Providence Power Partners, L.P. ........     7,310,458     7,504,792
Ridgewood AES Power Partners, LLC ................       472,496       141,065
Ridgewood El Segundo LLC .........................       691,619          --
On-site Cogeneration Projects:
   Ridgewood/Mass PPLP ...........................     2,394,851     3,731,067
   Ridgewood/Elmsford PPLP .......................       990,082     1,756,416
   Other On-site Cogeneration Project Partnerships       768,474     3,265,121
                                                     -----------   -----------

                                                     $21,714,050   $24,613,978
                                                     -----------   -----------

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

                                               For the Year Ended December 31,
                                            ------------------------------------
                                               1998         1997          1996
                                            ----------   ----------   ----------
JRW Associates, L.P. ....................   $1,051,375   $1,152,013   $  779,409
Byron Power Partners, L.P. ..............      464,530      571,576      428,540
Ridgewood Providence Power Partners, L.P.      546,690      922,941      562,427
Ridgewood AES Power Partners, LLC .......       33,807        4,249         --
On-site Cogeneration Projects:
  Ridgewood/Rhode Island PPLP ...........         --        282,943      572,970
  Ridgewood/Mass PPLP ...................      323,694      745,005      660,201
  Ridgewood/Elmsford PPLP ...............      242,881      292,543      160,940
  Other On-site Cogeneration
    Project Partnerships ................       64,991      104,120      361,126
                                            ----------   ----------   ----------
                                            $2,727,968   $4,075,390   $3,525,613
                                            ----------   ----------   ----------

   JRW Associates, L.P. (known as San Joaquin Power Company)
   On January 17, 1995,  the Trust  acquired  100% of the  existing  partnership
   interests of JRW  Associates,  L.P.,  which owns and operates an 8.5 megawatt
   electric cogeneration facility, located in Atwater, California. The aggregate
   cost of the investment was $6,087,039 and $5,481,186 at December 31, 1998 and
   1997,  respectively.  The increase in investment was primarily  caused by the
   cost of a new boiler  installed at the facility in 1998.  The Trust  received
   distributions  of  $1,051,375,  $1,152,013  and $779,409  from the project in
   1998, 1997 and 1996, respectively.

   Byron Power Partners, L.P. (known as Byron Power Company)
   In January 1995, the Trust caused the formation of Byron Power Partners, L.P.
   in which  the Trust  owns  100% of the  existing  partnership  interests.  On
   January 17, 1995, Byron Power Partners, L.P. acquired a 5.7 megawatt electric
   cogeneration facility,  located in Byron, California. As of December 31, 1998
   and 1997, the aggregate cost of the Trust's investment in the partnership was
   $2,999,031 and $2,734,331,  respectively. The Trust received distributions of
   $464,530,  $571,576  and  $428,540  from the project in 1998,  1997 and 1996,
   respectively.
                                      -F8-
<PAGE>

   Ridgewood Providence Power Partners, L.P. (known as the Providence Project)
   In 1996, Ridgewood  Providence Power Partners,  L.P. was formed as a Delaware
   limited  partnership  ("Providence  Power").  The Trust owns a 35.7%  limited
   partnership  interest in Providence Power. In addition,  Ridgewood Providence
   Power Corporation was formed as a Delaware  corporation  ("RPPCorp.") and the
   Trust owns 35.7% of the  outstanding  common stock of RPPCorp.,  which is the
   sole general partner of Providence  Power. At December 31, 1998 and 1997, the
   total  cost  of  the  Trust's   investment  was  $7,310,458  and  $7,504,792,
   respectively.

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

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

   Through  ownership in RPPCorp.  and Providence Power, the Trust owns 35.7% of
   the Providence  Project.  The remaining 64.3% is owned by Ridgewood  Electric
   Power Trust IV ("Trust  IV").  Ridgewood  Power  Corporation  is the managing
   partner of the Trust and Trust IV. In 1998, 1997 and 1996, the Trust received
   distributions  of $546,690,  $922,941 and  $562,427,  respectively,  from the
   Providence Project.

   Ridgewood AES Power Partners, LLC (known as  Ridgewood AES)
   In September 1997, the Trust formed Ridgewood AES Power Partners, LLC entered
   into an agreement with AES-NJ Cogen, Inc. (AES-NJ) to invest in co-generation
   facilities operated by AES-NJ. In 1997,  Ridgewood AES owned three facilities
   and added two  additional  facilities in 1998. The facilities are all located
   in New York.  The aggregate  cost of the investment was $472,496 and $141,065
   at December 31, 1998 and 1997, respectively. The Trust received distributions
   of $33,807 and $4,249 from the  projects in 1998 and 1997,  respectively.  In
   January 1999, the Trust  transferred  five of its Other On-site  Cogeneration
   Projects with a fair value of $283,966 to Ridgewood AES.

   Ridgewood El Segundo, LLC (known as the Dobbs House project)
   In April 1998, the Trust purchased an on-site  cogeneration  facility located
   near one of its  existing  on-site  cogeneration  facilities  in Los Angeles,
   California.  The total purchase price was approximately  $590,733,  including
   the payment of liabilities that encumbered the project. The aggregate cost of
   the investment was $691,619 at December 31, 1998.

   On-site Cogeneration Projects
   In 1995,  the Trust  acquired a portfolio of 35 projects  from  affiliates of
   Eastern  Utilities  Associates  ("EUA"),  which sell  electricity and thermal
   energy to industrial and commercial customers. The projects are held in eight
   limited  partnerships  of which the Trust is the sole limited  partner and is
   the  sole  owner  of each of the  general  partners.  In the  aggregate,  the
   projects  had 13.7  megawatts  of base load and 5.7  megawatts  of backup and
   standby capacity.  The Trust paid a total of $11,300,000 for the projects and
   invested  additional  amounts for capital  repairs and  improvements  and for
   working capital. EUA operated the projects under a transition agreement until
   January  1,  1996,  at which  time  Ridgewood  Power  Management  Corporation
   ("RPMC"),  an  affiliate  of  the  Trust,  assumed  operational  control.  No
   distributions  were  made by these  projects  in  1995.  The  Trust  received
   distributions  of $631,566,  $1,424,611 and $1,755,237 from these projects in
   1998, 1997 and 1996,  respectively.  See Note 6 - Arbitration and Litigation,
   for information relating to arbitration proceedings against EUA.
                                      -F9-
<PAGE>

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

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

   Ridgewood/Massachusetts Power Partners L.P.
   Ridgewood/Massachusetts  Power  Partners  L.P. (the  "Partnership")  owns two
   projects.  The first is a 3.5 megawatt base load,  single  cycle,  dual-fuel,
   combustion  turbine  powered plant with a heat recovery steam generator which
   sells electric power and steam to a manufacturing  facility on whose site the
   plant is located.  The project includes two 1.6 megawatt  Caterpillar  diesel
   engine generator sets to provide backup power. The project sells electric and
   thermal energy to the manufacturing facility at the project's production cost
   (as defined in the Energy Service Agreement) plus a share of the savings (the
   difference  between what the electric and thermal  energy would have cost the
   company absent the cogeneration  plant). The Energy Service Agreement expires
   at the end of 2005.  During 1998, the Trust completed an intensive  review of
   the project and determined  that a write-down of the fair value of $1,236,002
   was required. As of December 31, 1998 and 1997, the total cost of the Trust's
   investment in the partnership was $2,394,851 and $3,731,067 respectively. The
   Trust  received  distributions  of $323,694,  $745,005 and $660,201  from the
   project in 1998, 1997 and 1996,  respectively.  The  Partnership  also owns a
   smaller  group of four  cogeneration  generator  sets  totaling  255 kilowatt
   serving  a  residential  complex  in  Worcester,  Massachusetts.  The  energy
   services  agreement  ("ESA") provides that the partnership  receives from the
   customer  the cost to  purchase  electricity  and  natural gas from the local
   utility,  less a guaranteed savings based on the utility's current rates. The
   ESA expires in 2004.

   Ridgewood/Elmsford Power Partners, L.P.
   Ridgewood/Elmsford   Power  Partners,   L.P.  (the  "Partnership")  owns  one
   cogeneration  project  consisting of two 665 kilowatt  (1,330 kilowatt total)
   dual-fuel  Cooper  Superior  engine  generator  sets with heat recovery and a
   Caterpillar  600 kilowatt  standby diesel  generator set. The Energy Services
   Agreement ("ESA") expires in 2005 and provides that the Partnership  receives
   its  production  costs (as  defined in the ESA) plus a share of the excess of
   the customer's  avoided cost over  production  costs.  During 1998, the Trust
   completed an intensive review of the project and determined that a write-down
   of the fair value of $505,390 was required. As of December 31, 1998 and 1997,
   the total cost of the Trust's  investment in the partnership was $990,082 and
   $1,756,416,  respectively.  The Trust  received  distributions  of  $242,881,
   $292,543 and $160,940 from the project in 1998, 1997 and 1996, respectively.

   The "Other On-site Cogeneration Project Partnerships"
   The  "other  on-site   cogeneration   project   partnerships"   include  five
   partnerships,  which  owned  31 of  the 35  projects  acquired  from  Eastern
   Utilities Associates.  These 31 projects represented  approximately one-third
   of the Trust's original investment in the on-site cogeneration  projects. All
   thirty-one  were  gas-fired  cogeneration  projects,  located in  California,
   Connecticut or New York.  Their energy service 
                                     -F10-
<PAGE>

     agreements had terms expiring between September 1996 and 2011. The projects
represented 5.5 MW of base load capacity.  The largest project was 660 kilowatts
or 12% of the  capacity.  The  projects  ranged in size from 30 kilowatts to 660
kilowatts.  In 1996,  the Trust  wrote-off  four  small  projects  amounting  to
$113,042.  In 1997, the Trust wrote-off an additional  fifteen projects with 2.1
megawatts of base load capacity amounting to $1,991,463.  During 1998, the Trust
completed an intensive  review of the projects and determined  that a write-down
of the fair value of $2,313,822 was required.  The Trust received  distributions
of $64,991,  $104,120  and $361,126  from the  projects in 1998,  1997 and 1996,
respectively.  As of December  31, 1998 and 1997,  the total cost of the Trust's
investment in the "other  on-site  cogeneration  partnerships"  was $768,474 and
$3,265,121,  respectively.  In January 1999, the Trust  transferred  five of its
Other On-site  Cogeneration  Projects with a fair value of $283,966 to Ridgewood
AES.

   4.    Transactions With Managing Shareholder And Affiliates

   The Trust pays to the managing shareholder a distribution and offering fee up
   to 5% of each capital  contribution made to the Trust. The fee is intended to
   cover legal, accounting,  consulting, filing, printing, distribution, selling
   and closing costs for the offering of the Trust.  These fees were recorded as
   a reduction in shareholders' capital contributions.

   The Trust pays to the managing shareholder an investment fee up to 2% of each
   capital  contribution  made to the Trust.  The fee is payable to the managing
   shareholder  for its  services in  investigating  and  evaluating  investment
   opportunities  and  effecting  transactions  for investing the capital of the
   Trust.

   The Trust entered into a management agreement with the managing  shareholder,
   under   which  the   managing   shareholder   renders   certain   management,
   administrative  and advisory  services  and  provides  office space and other
   facilities to the Trust.  As compensation  to the managing  shareholder,  the
   Trust pays the managing shareholder an annual management fee equal to 2.5% of
   the net asset  value of the Trust  payable  monthly  upon the  closing of the
   Trust.  For the years ended December 31, 1998,  1997 and 1996, the Trust paid
   management  fees  to the  managing  shareholder  of  $673,933,  $766,866  and
   $794,026, respectively.

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

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

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

   Effective from January 1, 1996, under an operating  agreement with the Trust,
   Ridgewood Power Management Corporation  ("Ridgewood  Management"),  an entity
   related  to the  managing  shareholder  through  common  ownership,  provides
   management, purchasing,  engineering, planning and administrative services to
   the power generation  projects  operated by the Trust.  Ridgewood  
-F11-
<PAGE>

     Management  harges the projects at its cost for these  services and for the
allocable  amount of certain  overhead  items.  Allocations  of costs are on the
basis of  identifiable  direct  costs,  time records or in proportion to amounts
invested  in projects  managed by  Ridgewood  Management.  During the year ended
December 31, 1998, 1997 and 1996,  Ridgewood Management charged the following to
the projects based on proportionate amounts invested:


                                           For the Year Ended December 31,
                                            ------------------------------
                                              1998       1997       1996
                                            --------   --------   --------
JRW Associates, L.P. ....................   $119,960   $ 94,460   $ 91,962
Byron Power Partners, L.P. ..............     70,956     55,740     49,972
Ridgewood Providence Power Partners, L.P.    401,290    467,881    316,228
Ridgewood El Segundo LLC ................      9,120       --         --
On-site Cogeneration Projects:
  Ridgewood/Mass PPLP ...................    106,685     91,081     79,408
  Ridgewood/Elmsford PPLP ...............     47,385     42,590     35,129
  Other On-site Cogeneration
    Project Partnerships ................    100,005    122,871     31,264



   5.    Line of Credit Facility

   During the fourth quarter of 1997,  the Trust and the Trust's  principal bank
   executed a revolving line of credit agreement,  whereby the bank will provide
   a three year  committed  line of credit  facility  of  $757,000.  Outstanding
   borrowings  bear interest at the bank's prime rate or, at the Trust's choice,
   at LIBOR plus 2.5%. The credit agreement 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. At December 31, 1998 and 1997,
   there were no borrowings outstanding under the credit facility.

   6.    Arbitration and Litigation

   In December 1996, the Trust's  subsidiaries that own the on-site cogeneration
   projects brought an arbitration proceeding against EUA, claiming that EUA had
   breached  its  representations  in the  acquisition  agreement  and had  also
   defrauded the trust through  misrepresentations,  improper billing  practices
   and  violations  of state fair trade  practice  laws.  In October  1998,  the
   arbitrators  awarded the Trust  damages of  approximately  $2,600,000  on its
   claims  and  awarded  approximately   $400,000  to  EUA  for  alleged  unpaid
   management  services  thereon.  In  November  1998,  EUA  made a  payment  of
   $2,210,184  to the Trust to  liquidate  the  claims.  After  deducting  costs
   associated with the arbitration  proceeding,  the Trust recognized  income of
   $1,265,122.

   The arbitration panel also awarded the Trust its attorneys' fees and expenses
   incurred in prosecuting the case,  which the Trust computed at  approximately
   $997,000,  and  awarded  EUA its  attorneys'  fees and  expenses  incurred in
   prosecuting  its  counterclaim.  The panel is  expected to rule by the end of
   April  1999 on  objections  raised  by each  party  to the  others'  fees and
   expenses and to make a final  award.  EUA has also refused to pay interest at
   12% per year awarded by the panel on the Trust's award from September 1995 to
   November 1998 (approximately $808,000) until a final ruling by the panel.

   The Trust has brought a motion in the United  States  District  Court for the
   District of  Massachusetts  to confirm the award,  which will await the final
   ruling of the panel on the  attorneys'  fees and  expenses.  The Trust is not
   accruing any potential  recovery on fees,  expenses and  interest,  pending a
   final ruling or payment.
                                     -F12-
<PAGE>

   In the ordinary  course of business,  in late 1996 the Trust had discovered a
   small number of overbillings at on-site cogeneration  projects purchased from
   EUA and had refunded the  overbilled  amounts to customers.  In preparing for
   the arbitration hearings against EUA in the second quarter of 1998, the Trust
   made  an  intensive   engineering   and  financial   review  of  the  on-site
   cogeneration  projects  and  discovered  what  appeared  to be a  pattern  of
   material  overbillings of customers of a number of the on-site projects.  The
   overbillings  were caused by the Trust's  reliance  on billing  formulas  and
   practices  used by EUA and EUA's  transfer of false billing  protocols to the
   Trust was an element of the Trust's claim against EUA. The Trust has informed
   affected  customers  of the  overbillings  and has  offered  or paid  refunds
   totaling over $271,000. It has also advised federal government authorities of
   overbillings to federally  supported  entities that were included in the that
   amount.  Although  the federal  government  has the right at any time to take
   action  adverse  to the  Trust  if it sees  fit,  it has not done so to date.
   Although  there can be no  assurance  that  adverse  action will not be taken
   against the Trust,  the Trust  believes that it is not probable that any such
   adverse action will occur.

   7.    Administrative Proceeding at the Providence Project

   In September 1998, the Region I office of the U.S.  Environmental  Protection
   Agency  ("EPA") filed an  administrative  proceeding  against RPPP seeking to
   recover  civil  penalties  of  up  to  $190,000  for  alleged  violations  of
   operational   recordkeeping  and  training  requirements  at  the  Providence
   Project.  RPPPP  answered  and the matter has been  referred to an  alternate
   dispute  resolution  procedure  within the EPA. In the course of  discussions
   with the EPA and through the alternate dispute resolution procedure,  the EPA
   has offered to reduce the penalty to $88,750. Further, EPA is discussing with
   RPPP a proposal  to offset a portion of the  penalty by  crediting  RPPP with
   certain  environmental  audit and  remediation  expenditures,  over and above
   those  required by law, that the Trust and other  Ridgewood  Power Trusts may
   agree to make.  RPPP expects to resolve this matter in the second  quarter of
   1999 and does  not  anticipate  that it will  have to make  further  material
   capital  expenditures to remedy the items  identified by the EPA or that this
   proceeding  will have a  material  adverse  impact on it.  The Trust does not
   anticipate  that it will be liable  for or will have to fund the costs of the
   proceeding.

8.       Subsequent Event - Purchase of Caterpillar Power Modules

   On February 19, 1999, the Trust made a $590,200 deposit for seven Caterpillar
   power modules that are expected to be delivered in June 1999. The seven power
   modules  have a  total  price  of  $2,360,803  and a  total  capacity  of 7.8
   megawatts.  The  Trust  plans to rent  the  power  modules  to  domestic  and
   international customers.
                                     -F13-

<PAGE>