1




                       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, 2003

                         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)

1314 King Street
Wilmington, Delaware                                         19801
(Address of Principal Executive Offices)                   (Zip Code)

         Registrant's Telephone Number, including Area Code:  (302) 888-7444

         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

     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 ]

     Indicate  by check mark  whether  registrant  is an  accelerated  filer (as
defined in Rule 12b-2 of the Act). Yes ___ No X

     There is no market for the Shares. The aggregate capital contributions made
for the Registrant's  voting Shares held by  non-affiliates of the Registrant at
March 30,  2004 was  $39,034,440  000 and the  number  of  owners of  beneficial
interest outstanding at March 30, 2004 was 780.

Exhibit Index is located on page 31.


<PAGE>



PART I

Item 1.  Business.

Forward-looking statement advisory

     This  Annual  Report on Form 10-K,  as with some other  statements  made by
Ridgewood  Electric  Power Trust III (the "Trust")  from time to time,  includes
forward-looking  statements.  These statements discuss business trends and other
matters  relating to the Trust's future  results and business.  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 offering materials discuss many (but not all) of
the risks and uncertainties that might affect these forward-looking statements.

     Some of these include 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 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.

     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.

     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  or related  projects or facilities  ("Independent  Power
Projects" or "Projects").

     The Trust sold whole and  fractional  shares of beneficial  interest in the
Trust  ("Investor  Shares")  pursuant  to  a  private  placement  offering  (the
"Offering"), which terminated on May 31, 1995. 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 Projects.  The
Trust has 833 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 the Projects.

     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.  On November 5, 2001,  the Trust
issued to the  Investors a "Notice of  Solicitation  of  Consents," in which the
Trust sought the consent of the Investors to withdraw its election to be treated
as a  "business  development  company"  under  the 1940 Act and to make  certain
amendments to the Trust's  Declaration of Trust  ("Declaration")  necessary as a
result of such withdrawal,  including,  but not limited to, deleting the section
of the Declaration requiring  Independent  Trustees.  Consents were tabulated at
the close of business on December 18, 2001. Based on such tabulation, a majority
of Investor Shares  consented to such withdrawal and amendments.  On January 10,
2002, the Trust filed with the Securities and Exchange Commission a notification
to withdraw its election to be treated as a "business development company." As a
result of such withdrawal,  the Trust now utilizes generally accepted accounting
principles for operating companies.

     The  Trust is  organized  similarly  to a  limited  partnership.  Ridgewood
Renewable Power LLC (the "Managing  Shareholder"),  a Delaware limited liability
company,  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. The Investor does not
regularly elect the Managing Shareholder. As a result, the Trust does not have a
"board of directors"  that oversees the day-to-day  activities of the Trust and,
accordingly,  the  Trust  does  not  have an  audit  committee  or a  nominating
committee and therefore, the Trust's Chief Executive Officer and Chief Financial
Officer  effectively  perform  the  functions  that  an  audit  committee  would
otherwise perform.

     Christiana  Bank &  Trust  Company,  a  ("Christiana"),  a  Delaware  trust
company,  is the Corporate  Trustee of the Trust. The Corporate  Trustee acts on
the  instructions  of the Managing  Shareholder  and is not  authorized  to take
independent  discretionary action on behalf of the Trust. See Item 10. Directors
and Executive Officers of the Registrant below for a further  description of the
management of the Trust.

     The Trust is affiliated with the following trusts organized by the Managing
Shareholder ("Other Power Trusts"):

o Ridgewood Electric Power Trust I ("Power I");
o Ridgewood Electric Power Trust II ("Power II");
o Ridgewood Electric Power Trust IV ("Power IV");
o Ridgewood Electric Power Trust V ("Power V");
o The Ridgewood Power Growth Fund (the "Growth Fund");
o Ridgewood/Egypt Fund ("Egypt Fund"); and
o Ridgewood Power B Fund/Providence Expansion ("B Fund").

     In  addition,  the  Trust  is  affiliated  with  certain  Delaware  limited
liability companies form by the Managing Shareholder  ("Ridgewood LLCs") and for
which the Managing Shareholder acts as Manager:

o Ridgewood Renewable PowerBank, LLC;
o Ridgewood Renewable PowerBank II, LLC;
o Ridgewood Renewable PowerBank III, LLC

(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 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 4 small cogeneration facilities located in
         California, New York and Massachusetts 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 operated 5
         small cogeneration projects in New York, which was sold in 2003;
         (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 four 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., San Diego, California (the "Mobile Power
         Units").

(2) The Trust's Investments.

(i) San Joaquin Project and Byron Project.

     On January 17, 1995, the Trust and a wholly-owned  subsidiary acquired 100%
of the  existing  partnership  interests of JRW  Associates,  L.P., 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 "San Joaquin  Project").  The aggregate cash purchase price paid
by the Trust for 100% of the partnership interests was $4,900,000.

     The San Joaquin  Project 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").  Thermal  energy  from the San  Joaquin  Project  is used to
provide steam to an adjacent food processing  company under a long-term contract
that also terminates in 2020.

         Also in January 1995, the Trust formed Byron Power Partners, L.P., a
California limited partnership (the "Byron Partnership"). On January 17, 1995,
the Byron Partnership acquired through a merger all of the assets and business
of Altamont Cogeneration Corporation, including an approximately 5.7-megawatt
electric cogeneration facility located near the city of Byron, Alameda County,
California (the "Byron Project"). The aggregate cash purchase price paid by the
Trust for 100% of the partnership interests was $2,509,000.

     The Byron Project,  like the San Joaquin Project,  is fueled by natural gas
and  sells its  electric  output to PG&E  under a Power  Contract  substantially
similar to that of the San Joaquin Project (collectively the "Power Contracts").
The Power  Contract  for the  Byron  Project  also  expires  in 2020.  The Byron
Project's  heat output is used to evaporate  brine from oil and gas wells,  with
payments by the Byron Project for the site lease  offsetting  the thermal host's
payments for heat.

     Both the San Joaquin and Byron Projects  (collectively  "NorCal  Projects")
are Qualifying  Facilities  ("QFs")  pursuant to the Public  Utility  Regulatory
Policies Act of 1978, as amended ("PURPA"). Historically,  producers of electric
power in the United  States  consisted of regulated  utilities  serving  end-use
retail  customers.  PURPA,  among other things,  requires  utilities to purchase
electric power from QFs,  including  "cogeneration  facilities" and "small power
producers,"  and also  exempts  these QFs from most  federal  and state  utility
regulatory requirements. In addition, the price paid by electric utilities under
PURPA for electricity produced by QFs is 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).
Pursuant to PURPA, and state  implementation of PURPA,  many electric  utilities
have entered into long-term power contracts with rates set by contract  formulae
approved by state regulatory commissions.  The NorCal Projects entered into such
contracts  with PG&E. The capacity and energy price paid by PG&E pursuant to the
Power Contracts were determined  pursuant to a contract  formula approved by the
California  Public  Utilities   Commission  ("CPUC")  with  the  energy  payment
originally based upon a benchmark energy price adjusted for changes over time in
a gas  index;  the so called  "Short  Run  Avoided  Cost  Methodology"  or SRAC.
However,  as  described  further  below,  both the NorCal  Projects  executed an
Amendment to their Power  Contract with PG&E,  which  provides that the Projects
will receive a fixed energy payment (as well as the required  capacity  payment)
for a term of five (5) years.

     As a result of the California  energy crises in 2000 and 2001,  PG&E, among
other things,  experienced severe cash shortages and losses due primarily to the
fact that it was required under the law to purchase electric energy at wholesale
prices  significantly  above the regulated  rates it could legally charge retail
customers. As a result, PG&E filed for protection under the U.S. Bankruptcy Code
in April of 2001.  At the time of PG&E's  bankruptcy  filing,  the Byron and San
Joaquin  Projects had not been paid by PG&E for the electric energy and capacity
it had delivered in the last several  months of 2000 and the first few months of
2001 and were ultimately forced to cease operations.

     Subsequent to its bankruptcy  filing,  in an effort to get as many QFs back
online as  possible,  PG&E sought and received  approval  from the CPUC to offer
each QF an agreement,  and corresponding amendment to their Power Contracts, for
a term of five (5) years, which would effectively replace, for such 5 year term,
the variable SRAC formula for  determining  the energy price with a fixed energy
price.  Such amendment would allow the QF to operate at a price that appeared to
be reasonable in light of the circumstances at that time. In addition, a QF that
executed  the  amendment  agreed that it would not  institute,  or proceed  with
outstanding,  litigation against PG&E. Finally, in order to execute an amendment
with a fixed energy price,  it was  necessary to procure  natural gas at a fixed
price.  The Byron and San  Joaquin  Projects  were able to procure  such  fixed,
five-year  supply of natural gas from Coral Energy Services,  Inc.,  ("Coral") a
subsidiary of Shell Oil. Therefore,  until approximately  August 2006, the Byron
and San  Joaquin  Projects  will be  operating  under  the  Amendment,  which is
expected to result in positive cash flow to the Byron and San Joaquin  Projects.
In addition to the gas supply agreement  mentioned,  Coral and the Byron and San
Joaquin Projects have a master re-sale  agreement,  which also expires in August
2006.  Such agreement  enables the NorCal Projects not to take delivery and sell
back  certain of the  natural gas to Coral once  predetermined  prices have been
established. Certain re-sale pricing for 2004 has already been determined, which
is in excess of the underlying cost.

 (ii)  On-site Cogeneration Projects

     In September  1995,  the Trust  purchased  the  ownership  interests in the
On-site  Cogeneration  Projects,  a portfolio of 35 small 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).

     Returns from the On-site Cogeneration  Projects  deteriorated and beginning
in the third quarter of 1997 the Trust has closed most of the Projects.  Because
of closures and contract expirations, the Trust has recorded writedowns of $10.8
million relating to On-site Cogeneration Projects since their purchase.

     The  Massachusetts  projects  included  the Globe  Project,  a 3.5 Megawatt
turbine with backup  diesel  engines,  located at a Fall River,  Massachusetts's
facility  owned by Globe  Manufacturing  Corp.  ("Globe").  On January 13, 2001,
Globe filed a voluntary  petition for bankruptcy in the United States Bankruptcy
Court for the Northern  District of Alabama,  where Globe is  headquartered.  As
part of the bankruptcy  proceeding,  Globe sold substantially all of its assets,
including the Fall River facility.  The Bankruptcy  Court approved the sale. The
Power  Contract  that the Trust has with Globe has been rejected by Globe in the
Bankruptcy Court proceedings. Effectively the Power Contract has been terminated
and the Trust has  "rejection"  damages claims against Globe,  but given Globe's
financial  condition it is not likely that significant  amounts of money will be
available  to pay such  rejection  damages.  In 2002,  the Trust  sold the Globe
Project equipment,  but not the claim for rejection damages,  for $250,000.  The
purchaser is responsible  for, and has assumed all of the risk of, the equipment
removal and  transportation.  The Trust has received  full payment for the Globe
Equipment.

     Two of the  projects  are still in  operation.  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  Marriott  Project is located in Coronado,
California with a rated capacity of .6 Megawatts.

     RPM has management  responsibility for the On-site  Cogeneration  Projects.
See Item 10 -- Directors and Executive Officers of the Registrant.

(iii) 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. In September 2003,
the food preparation  facility ceased  operations and the power contract expired
thus,  the Trust ceased the project's  operations  and is now attempting to sell
the project's equipment.

 (iv) Ridgewood/AES Power Partners, LLC.

     The Trust engaged  AES-NJ  Cogen,  Inc., a small  operator of  cogeneration
plants  ("AES") that is not  affiliated  with the Trust,  to operate five of the
smallest  On-Site  Cogeneration  Projects.  In September  1997 the Trust and AES
created a joint venture, Ridgewood/AES Power Partners, L.P. ("Ridgewood AES") to
develop  additional  small  cogeneration  projects in the New York  metropolitan
area.  The Trust  supplies  capital and AES supplies  development  services.  At
December 31, 2002 Ridgewood AES owned five  cogeneration  projects at hotels and
hospitals in New York and New Jersey.

     In 2003, the Trust sold 100% of its ownership  interest in Ridgewood AES to
AES-NJ  for  $100,000  cash,  a  $150,000   interest  bearing   promissory  note
("promissory note") and a $74,394 interest free note ("interest free note"}. The
promissory  note bears  interest at a rate of 10% per annum,  and will be repaid
monthly  over a four-year  term.  The  interest  free note will be repaid over a
six-month  term. For the year 2002, the Trust recorded a writedown of $67,000 to
reflect the  project's  fair market value as determined by the terms of the sale
agreement.

(v)  Providence Project

     The Trust and Power IV acquired in April 1996 all of the equity interest in
an landfill gas-fired electric generating facility,  located on land adjacent to
the Central  Landfill,  near Providence,  Rhode Island.  The Trust invested $7.1
million in the Providence Project and Power IV supplied the remainder of the $20
million  investment  in the  Project.  The Trust  owns  35.7% of the  Providence
Project  and  Power  IV owns  the  remaining  64.3%.  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  Providence  Project was  encumbered  by $5.4
million of debt that has been paid in full as of February 2004.

     The Project burns methane gas generated by the decomposition of garbage and
other  waste 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  ("NEP") that expires
in 2020.

     The Project leases the right to use the landfill site from the Rhode Island
Resource Recovery Corporation, a state agency ("RIRRC"), for a royalty of 15% of
net Project revenues , until the year 2006, thereafter 15% to 18% depending upon
production.  The Project in turn  subleases  those rights to Central Gas Limited
Partnership  ("Gasco").  Gasco,  which is not  affiliated  with the  Trust,  had
operated and  maintained  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.

     Throughout  the  Trusts'  ownership  of  the  Providence  Project,  certain
situations  have  occurred  at the  landfill  regarding  Gasco's  operation  and
maintenance of the gas collection system, which convinced the Trust and Power IV
that the gas collection system could be operated and maintained more efficiently
and  economically and could provide higher quality,  and greater  quantities of,
landfill  gas.  The  resulting  savings in costs and  increase in  quantity  and
quality of methane gas would benefit the Providence Project. In addition,  RIRRC
anticipated that the Central Landfill would be capable of providing landfill gas
from new phases that could fuel an  additional  12 MW.  Therefore,  on August 1,
2003,  the Trust and Power IV concluded a transaction in which the operation and
maintenance  of the gas  collection  systems was  transferred  to Ridgewood  Gas
Services,  LLC,  ("RGS")  which is owned by the  Trust  and Power IV in the same
proportion  to  their  ownership  in  the  Providence  Project.  RGS  is a  cost
reimbursement  company whose  operations are funded both by Gasco and the RIRRC.
Pursuant  to a  Landfill  Services  Agreement  with RGS,  Gasco pays RGS for its
operation  of the gas  collection  system that is owned by Gasco.  In  addition,
pursuant to a Landfill services Agreement with RIRRC, RGS operates and maintains
the gas  collection  system owned by RIRRC and RIRRC funds the remainder of RGS'
operations  not  funded  by  Gasco's  payments.  In  addition,  as  part  of the
transaction,  Ridgewood  Rhode  Island  Generation,  LLC,  owned by the  Trust's
affiliate,  the B Fund, has obtain rights to landfill gas from RIRRC and develop
an additional 7.5 MW landfill gas-fired electric generation facility,  which the
B Fund estimates will be completed on or about June 1, 2004.

     On January 17,  2003,  the  Providence  Project  received a  "Statement  of
Qualification"  from the  Massachusetts  Division of Energy  Resources  ("DOER")
pursuant to the renewable  portfolio standards ("RPS") adopted by Massachusetts.
In 1997,  Massachusetts  enacted  the  Electric  Restructuring  Act of 1997 (the
"Restructuring  Act").  Among other things,  the Restructuring Act requires that
all retail electricity suppliers in Massachusetts (i.e. those entities supplying
electric energy to retail end-use customers in Massachusetts) purchase a minimum
percentage of their electricity supplies from qualified new renewable generation
units  powered  by one of several  renewable  fuels,  such as solar,  biomass or
landfill.  Beginning in 2003, each such retail supplier must obtain at least one
(1%) percent of its supply from qualified new renewable  generation  units. Each
year  thereafter,  the requirement  increases  one-half of one percentage  point
until  2009,  when the  requirement  equals  four (4%)  percent  of each  retail
supplier's  sales  in  that  year.  Subsequent  to  2009,  the  increase  in the
percentage requirement will be determined and set by the DOER.

     Now that the Providence Project has been qualified in Massachusetts, it may
sell to  retail  electric  suppliers  the RPS  Attributes  associated  with  its
electrical  energy.  Retail  electric  suppliers need to purchase RPS Attributes
associated with renewable  energy and not  necessarily the energy itself.  Thus,
electrical energy and RPS Attributes are separable products and need not be sold
or purchased as a bundled  product.  Retail electric  suppliers in Massachusetts
will then use the purchase of such RPS Attributes to demonstrate compliance with
the Restructuring Act and RPS Regulations. The Trust, along with Power IV, V and
the B Fund,  completed  a  transaction  with a major  power  marketer  that does
business in  Massachusetts  for the sale of the RPS Attributes  generated by the
Providence Project, as well as the RPS Attributes generated by Projects owned by
Power IV, V and the B Fund. The  transaction,  which is  confidential,  provides
such power marketer with six separate  annual options to purchase such output in
each year from 2004 through 2009. If the power  marketer  elects to not purchase
the RPS Attributes in any year, the Providence  Project is free to sell to other
parties.  Under the terms of the  transaction,  the prices to be received by the
Providence  Project  for the RPS  Attributes,  if the power  marketer  elects to
purchase, are very favorable.

     However,  only a portion of the Providence  Project's  output qualifies for
RPS Attributes in Massachusetts. Because the Providence Project was in operation
during the period 1995 through  1997,  the average  annual  generation  produced
during those years does not qualify. Under the Massachusetts regulations,  it is
defined  as  the  Providence   Project's   "Vintage   Generation",   amounts  to
approximately 86,000 MWhs per year, and the RPS Attributes  associated with such
annual amounts of generation do not qualify in  Massachusetts.  However,  during
2004,  the  Providence  Project  became  qualified  to sell  RPS  Attributes  in
Connecticut.  The  Connecticut  RPS program is different than the  Massachusetts
program in that it does not have a "Vintage"  prohibition.  Thus, the Providence
Project can sell the 86,000 MWhs that are ineligible in  Massachusetts  into the
Connecticut  market.  In fact, the  Providence  Project has entered into several
short-term  agreements  with various power  marketers to sell the RPS Attributes
associated with such "Vintage Generation".  The prices for the RPS Attributes in
those  agreements,  although  lower than current  market,  are beneficial to the
Providence Project.

(vi) Mobile Power Units

     In August 1999 the Trust purchased five  Caterpillar  unified power modules
(the "Mobile  Power  Units") for  $1,696,000.  The Units  combine a large diesel
engine with a fuel tank, emission  equipment,  an electric generator and control
equipment  on a single  skid and  therefore  can be moved to  remote  areas as a
self-contained  power plant.  The owner of the Units is  Ridgewood  Mobile Power
III, LLC, a  wholly-owned  subsidiary  of the Trust.  The Trust bought the Units
from Hawthorne Power Systems,  Inc.  ("Hawthorne")  of San Diego,  California (a
Caterpillar  distributor).  Hawthorne added the Units to its own rental fleet of
similar  equipment and rents them to  contractors,  engineering  firms and other
industrial or commercial  customers who need emergency,  temporary or peak power
supplies.  The Trust receives 80% of the net rental  revenues and is responsible
for major  maintenance;  Hawthorne  receives  20% of the net rental  revenues to
compensate  it for  marketing  and managing the rentals.  Due to the increase in
competition and production of newer efficient  models,  the Trust  experienced a
decrease in rental revenue for the second  consecutive  year. As a result of the
change in these market conditions,  the forecasted revenues for the mobile power
modules are not expected to be enough to recover the units' book value.  In 2003
and 2002, the Trust recorded  writedowns of $87,465 and $460,697,  respectively,
to reflect the units fair market value.  In the third quarter of 2003, the Trust
decided to make its mobile power units available for sale.  Shortly after making
the  mobile  power  units  available  for sale,  the Trust  sold one  module for
$171,000.

(3) Project Operation.

     Revenue from the San Joaquin, Byron and Providence Projects primarily comes
from Power  Contracts  with the local  electric  utilities.  In  addition,  with
respect to the Providence Project, additional revenues are obtained through sale
of the  RPS  Attributes.  With  respect  to the  Power  Contracts,  the  pricing
provisions 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. Pricing for the sale of
RPS Attributes is generally  based upon the market prices for such attributes at
the time of the negotiation of the sale.

     The Mobile Power Units are managed by Hawthorne  and rented at fixed rates.
Their major costs are capital  recovery  and  maintenance;  operating  costs are
borne by the  customer.  Electricity  generated  from the Mobile  Power Units is
generally  used by the renter  on-site.  If there were a  shortage  of  electric
generation  capacity,  the Units could be rented as additional  peak  generation
capacity  by a utility or  electricity  seller,  subject to local  environmental
limitations. The Mobile Power Units are rented at fixed prices per month and are
operated by the renter. Rental periods typically range from one to six weeks.

     The Managing Shareholder  organized RPM to provide operating management for
the Projects.  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  with  RPM and  for  the  cost
reimbursements received by RPM.

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

     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 QF 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.

     Customers that accounted for more than 10% of  consolidated  revenue to the
Trust in each of the last three fiscal years are:

                                           Calendar year
                                   2003          2002       2001
Pacific Gas & Electric Co.
 (San Joaquin & Byron Projects)    72.3%         76.5%      53.1%
Coca Cola Bottling Plant of New
  York (Coca Cola Project)         18.1%         12.5%      17.4%

     Note  that the  financial  statements  of the  Providence  Project  are not
consolidated  with those of the Trust and,  accordingly,  its  revenues  are not
considered to be operating revenues.

     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.
See Item 1(c)(6) -- Business -- Narrative  Description of Business -- Regulatory
Matters.

     (4)  Market Trends

     The Trust's Byron and San Joaquin plants are located in California.  In the
years 2000 and 2001,  California  experienced severe energy crises. As a result,
both the  state  legislature  and the CPUC  have  taken  significant  action  by
enacting  legislation  and  implementing  regulations,   respectively,  intended
primarily to avoid a repeat of the crises by creating a more  stable,  efficient
and economic energy market.  For example,  the legislature  enacted  legislation
designed to enhance,  promote and encourage renewable generation in the state by
implementing  a renewable  portfolio  standard  ("RPS"),  which will require all
California  investor  owned  utilities  ("IOUs"),  as  well as  retail  electric
suppliers  to have in their  energy  supply  portfolio a certain  percentage  of
renewable  generation.  This percentage increases overtime until the requirement
equals 20%. In addition to the RPS,  California  enacted  legislation  that will
streamline  the time  required  for and the costs of new  electric  power  plant
permitting and  construction.  Finally,  legislation  has been enacted that will
fundamentally change the manner in which California IOUs procure electric energy
for their customers.  The CPUC is currently  engaged in the rule-making  process
that  will  implement  these and many  other  requirements  of the  legislation.
However,  because  the Byron and San  Joaquin  projects  are  currently  under a
long-term  fixed  price  contract  with PG&E,  which  although  having  declared
bankruptcy is emerging a much stronger company, many of the trends in California
will have little impact upon these projects.

     In the year 2003 many states  implemented  or enacted  renewable  portfolio
standards (RPS).  For example,  RPS legislation and regulations have been passed
and are effective  in, among other states,  Massachusetts,  Nevada,  Texas,  New
Jersey, and Connecticut.  Many other states are considering RPS legislation. The
intent  behind  virtually  all  RPS  programs  is  to  provide  added  financial
incentives to developers of renewable  generation by requiring  retail  electric
suppliers to purchase a certain percentage of renewable power or, alternatively,
purchase the required number the renewable  energy credits"  ("REC"),  which are
created  as a  result  of such  renewable  generation.  As a  result  of the RPS
programs, developers of renewable generation can effectively receive two sources
of  revenue:  one from the sale of the actual  electric  energy and one from the
sale of RECs. Most RPS programs effectively separate the purchase of energy from
the purchase of the "REC" and basically  require  electric  energy  suppliers to
have the required number of RECs at the end of the compliance period, regardless
of its energy  supply  portfolio.  Combined,  these two streams of income may be
sufficient to attract and increase the development of new renewable  generation.
As indicated  earlier,  the Providence  Project is currently selling RECs in the
Massachusetts and Connecticut market. As more and more states in the New England
region and surrounding  areas of the Country adopt these RPS regulations,  RECs,
such as those  generated by the Providence  Project,  may be in short supply and
will be more valuable until new renewable generation comes on line to supply the
market.

(5)  Competition

     The San Joaquin, Byron and Providence Projects, as described above, are not
currently  subject to  competition  because  those  Projects  have  entered into
long-term  agreements to sell their output at specified prices.  However, if the
Power Contracts were terminated for any reason,  these Projects could be subject
to future  competition  to market its  electricity  output.  However,  the Trust
believes  that in the near  term,  until  additional  generation  resources  are
completed  and  brought  on-line,  these  Projects  could sell  their  output at
reasonable prices,  although for a variety of factors,  including the volatility
of natural  gas  prices,  unexpected  legislation  and  litigation,  there is no
guarantee that they may be able to do so.

     There are a large number of participants in the independent power industry.
Several  large  corporations  specialize in  developing,  building and operating
Projects.   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 invested
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 QF 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.

     The Units compete against  numerous other fleets of mobile power generation
equipment  on a  regional  and  international  level.  To some  extent  local or
governmental   electricity   utilities   also  compete  to  provide   short-term
electricity in less remote areas.  Hawthorne owns many units in its rental fleet
but has agreed to market the Trust's  Units on a basis at least as  favorable at
it does for its own equipment.  Demand for the Units is heavily dependent on the
level of construction and civil engineering work in the Southern California area
and on the availability of equipment from vendors, other area rental fleets and,
to a limited extent, from outside-of-area  fleets.  Demand can be very volatile.
Further, after one year, Hawthorne can cancel the marketing agreement on 5 days'
notice.

(iv) Potential Legislation and Regulation.

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

(6) Regulatory Matters.

     Projects are subject to energy and  environmental  laws and  regulations at
the federal,  state and local levels in connection with development,  ownership,
operation, geographical location, zoning and land use of a Project and emissions
and other substances produced by a Project.  These energy and environmental laws
and  regulations  generally  require  that a wide  variety of permits  and other
approvals be obtained before the commencement of construction or operation of an
energy-producing  facility and that the facility then operate in compliance with
such permits and approvals.

(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.  QFs
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,  from state laws regarding rate or financial regulation. In order
to be a QF, a cogeneration  facility must (a) produce not only  electricity  but
also a certain  quantity  of heat  energy  (such as  steam)  which is used for a
purpose  other  than  power  generation,  (b)  meet  certain  energy  efficiency
standards  when  natural  gas or oil is  used  as a fuel  source  and (c) not be
controlled  or more than 50% owned by an electric  utility or  electric  utility
holding  company.  Other types of Independent  Power  Projects,  known as "small
power production  facilities,"  can be QFs if they meet  regulations  respecting
maximum size (in certain cases), primary energy source and utility ownership.

     The exemptions  from  extensive  federal and state  regulation  afforded by
PURPA to QFs are important to the Trust and its competitors.  The Trust believes
that each of its Projects is a QF. If a Project loses its QF 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 or the Project's
Power Contract can be terminated by the electric utility.

     (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 1992 Energy 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 QFs under PURPA are exempt from the  rate-making and certain
other  provisions  of the  FPA,  non-QFs  are  subject  to the  FPA  and to FERC
rate-making jurisdiction.

     (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 QFs under
PURPA, and which are considered  public  utilities in many states.  In addition,
states may assert  jurisdiction over the siting and construction of non-QFs and,
among other things, issuance of securities,  related party transactions and sale
and transfer of assets.  The actual scope of jurisdiction  over non-QFs by state
public utility regulatory commissions varies from state to state.

     (F) Mobile Power Units.  The Units, as temporary  on-site units operated by
the electricity  consumer,  are not subject to economic regulation in California
or most other jurisdictions.  If a Unit were rented by a regulated utility, that
utility might be subject to economic  regulation but the rental fee for the Unit
would probably not be directly regulated.  There might be an indirect regulatory
effect to the extent that the utility was  regulated  as to the rental  price it
would be authorized  to pay.  Under current  conditions in  California,  this is
unlikely.

(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  modifications  to
existing Projects.

     The Providence Project operates  filtration and condensation  equipment for
the  purpose  of  removing  contaminants  from  the  landfill  gas  supply.  The
condensate is further  treated and then  discharged to a local  treatment  plant
under an  NPDES  permit.  The  contaminants  removed  from  the  condensate  are
incinerated at an approved  facility.  The Trust believes that these  discharges
and  contaminants  are being  disposed  of in  compliance  with  NPDES and other
requirements.

     The  Managing   Shareholder   expects  that   environmental  and  land  use
regulations  may become more stringent.  The Trust and the Managing  Shareholder
have  developed  a certain  expertise  and  experience  in  obtaining  necessary
licenses,  permits  and  approvals,  but will  nonetheless  rely upon  qualified
environmental  consultants and environmental counsel retained by it to assist in
evaluating the status of Projects regarding such matters.

     The Mobile Power Units, which do not have a fixed location,  are subject to
differing air quality standards that depend in part on the locations of use, the
amount of time and time periods of use and the quantity of  pollutants  emitted.
The Trust  believes  that the Units as used comply with  applicable  air quality
rules.

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

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

(e) Employees.

     The  Projects  are  operated  by  RPM  and  accordingly  the  Trust  has no
employees.  The persons  described  below at Item 10 - Directors  and  executive
officers of the Managing  Shareholder and RPM 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

Providence   Providence,  Leased    2020         4      10,000      Landfill
           Rhode Island                                             gas-fired
                                                                    generation
                                                                    facility

Item 3.  Legal Proceedings.

         None.



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

         None.

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.  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.

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

(b)  Holders

     As of the date of this Form 10-K,  there are 833 record holders of Investor
Shares.

(c)  Dividends

     The Trust made  distributions  as follows for the years ended  December 31,
2003 and 2002:

                             Year ended            Year ended
                         December 31, 2003      December 31, 2002
Total distributions
 to Investors               $1,175,538              $ --
Distributions per
 Investor Share             $    3,000              $ --
Distributions to
 Managing Shareholder       $   11,874              $ --

     The Trust's decision whether to make future  distributions to Investors and
their timing will depend on, among other things,  the net cash flow of the Trust
and  retention of  reasonable  reserves as  determined by the Trust to cover its
anticipated expenses. See Item 7 Management's Discussion and Analysis.

     Occasionally,  distributions  may include funds derived from the release of
cash from operating or restricted  cash.  Further,  the  Declaration  authorizes
distributions  to be made from  cash  flows  rather  than  income,  or from cash
reserves in some  instances.  For  purposes  of  generally  accepted  accounting
principles,  amounts  of  distributions  in excess of  accounting  income may be
considered to be capital in nature.  Investors should be aware that the trust is
organized to return net cash flow rather that 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.  As described in such
financial  statements,  financial  information  for the years 1999 and 2000 have
been  restated to reflect the  application  of new  accounting  principles  as a
result of the Trust's election to terminate its status as a business development
company.


Selected Financial Data
                        As of and for the year ended December 31,
                     2003       2002      2001       2000        1999

Total Fund Information:

Revenues         $7,257,996 $7,848,594 $6,383,067 $9,590,113  $9,735,514
Net income(loss)  1,622,699 (1,356,396)(1,482,487)(2,521,130)  1,091,759
                      (A)        (B)                  (C)          (D)
Net assets
(shareholders'
  equity)        14,708,565 14,273,278 15,629,674 17,112,161  21,414,406
Investments in
 Plant and
 Equipment(net
 of deprec.)      5,016,351  6,632,404  7,863,053  8,468,270  11,904,223
Investment
 in Power
 Contract(net
 of amort.)       1,147,840  1,219,580  1,291,320  1,363,060   1,434,800
Tot. Assets      15,199,350 15,589,236 17,480,795 18,919,336  21,255,421
Long-term
obligations              --         --    250,000         --          --
Per Share:
Revenues             18,523     20,030     16,290     24,474      24,845
Net income(loss)      4,141     (3,462)    (3,783)    (6,434)      2,786
                        (A)        (B)                  (C)          (D)
Net asset value      37,537     36,426     39,887     43,671      54,650
Distributions
 to Investors         3,000         --         --      4,500       6,006


(A) Includes writedowns of investments of $143,179 ($365 per Investor Share).
(B) Includes writedowns of investments of $579,550 ($1,479 per Investor Share).
(C) Includes writedowns of investments of $2,780,083 ($7,095 per Investor
    Share).
(D) Includes $1,581,308 of income from arbitration award ($4,036 per
    Investor Share)



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

Introduction

     The following  discussion and analysis  should be read in conjunction  with
the Trust's financial  statements and the notes thereto presented below.  Dollar
amounts in this discussion are generally rounded to the nearest $1,000.

Outlook

     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. 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.

Significant Accounting Policies

     The Trust's plant and equipment is recorded at cost and is depreciated over
its estimated  useful life.  The estimate  useful lives of the Trust's plant and
equipment  range from 10 to 20 years.  A  significant  decrease in the estimated
useful life of a material  amount of plant and  equipment  could have a material
adverse  impact on the  Trust's  operating  results  in the  period in which the
estimate is revised and subsequent  periods.  The Trust evaluates the impairment
of its long-lived  assets (including power sales contracts) based on projections
of undiscounted cash flows whenever events or changes in circumstances  indicate
that the carrying  amounts of such assets may not be  recoverable.  Estimates of
future cash flows used to test the recoverability of specific  long-lived assets
are based on expected  cash flows from the use and eventual  disposition  of the
assets.  A significant  reduction in actual cash flows and estimated  cash flows
may  have a  material  adverse  impact  on the  Trust's  operating  results  and
financial condition.

Results of Operations

The year ended December 31, 2003 compared to the year ended December 31, 2002.

     Power generation revenue decreased  $514,000,  or 7%, to $7,225,000 in 2003
compared to $7,739,000  in 2002.  The decrease is primarily due to the Byron and
San Joaquin projects operating on a shorter production schedule during the first
half of 2003. As a result of high natural gas prices,  the Byron and San Joaquin
projects had elected to produce the minimum amount of contracted energy, thereby
enabling the projects to sell their  residual  volume of natural gas under fixed
priced purchase contracts at current market prices,  resulting in slight profits
and reduced wear and tear on the  generation  equipment.  As a partial offset to
the  decrease   previously   discussed,   revenues  from  the  Trust's   on-site
cogeneration  projects  increased  $158,000  due to the  increase in natural gas
prices.

     Rental revenue from the Trust's  mobile power modules  decreased by $76,000
to $33,000 in 2003.  The  decrease  in rental  revenue  is due the  increase  in
competition and production of newer efficient models.

     Gross profit,  which  represents  total revenues  reduced by cost of sales,
increased  by  $740,000  to a profit of  $259,000  in 2003 from a gross  loss of
$481,000 in 2002. The increase is a result of the lower fuel expenses due to the
shorter production  schedule in 2003, offset by the decrease in power generation
revenues.

     General and administrative expenses increased $4,000, or 2%, to $197,000 in
2003 from $193,000 in 2002.

     In 2002, the Trust recovered  $107,000 relating to PG&E revenues from prior
years,  which  had been  treated  as  uncollectible  due to  PG&E's  filing  for
bankruptcy  protection.  In the current year the Trust  incurred  $38,000 of bad
debt expense.

     In 2003,  the Trust  recorded  a write down to the  Mobile  Power  Units of
$143,000.  In 2002, the Trust recorded a write down to its  investments in power
generation projects of $580,000.  The projects comprising the write down are the
Mobile  Power  Units,   $461,000,   Ridgewood  AES,  $67,000,  and  the  On-site
Cogeneration Projects, $52,000.

     The management fee paid to the Managing  Shareholder  decreased by $34,000,
or 9%, to $357,000 in 2003 from $391,000  reflecting the lower net assets of the
Trust.

     Loss  from  operations  decreased  $1,062,000,  to  $475,000  in 2003  from
$1,537,000  in 2002,  primarily  due to the  increase  in gross  profit  and the
decrease in write down in power generation projects in the current year.

     Other  income,  net,  increased by  $1,917,000,  to $2,098,000 in 2003 from
$181,000 in 2002.  The increase is  comprised  of $240,000 of proceeds  received
from the sale of the equipment of one of the idle cogeneration facilities, which
had been  written off in 2000.  The Trust also  recorded an  unrealized  gain of
$1,254,000,  in the current year,for the increase in the market price of natural
gas. In addition,  the Trust's equity income in the Providence Project increased
$390,000  in 2003  compared  to 2002.  The  increase  in equity  income from the
Providence project can be attributed to the lower revenues recorded in 2002 as a
result of the failure of one of the facility's engines. In addition, the project
recorded  the  revenue of  $772,000  for the  transfer  of  renewable  portfolio
standard attributes in 2003 compared to zero in 2002.

     The Trust's net income increased  $2,979,000,  from a loss of $1,356,000 in
2002 to income of $1,623,000 in 2003.  The increase is primarily due to decrease
in loss from  operations  in addition to the increase in equity  income from the
Providence project,  the proceeds received from the sale of the equipment of one
of the idle  cogeneration  facilities  and the  unrealized  gain on gas purchase
contracts.

The year ended December 31, 2002 compared to the year ended December 31, 2001.

     Power generation  revenue  increased  $1,761,000,  or 29%, to $7,739,000 in
2002 compared to $5,978,000 in 2001.  The increase is primarily due to the Byron
and San Joaquin projects  operating on their normal schedule in 2002 as compared
to 2001 when the plants were idle from February to August due to PG&E's  failure
to pay the projects for power delivered  since December 1, 2000.  Rental revenue
from the Trust's mobile power modules  decreased by $295,000 or 73%, to $109,000
in 2002.  The  decrease  in rental  revenue is due to the higher  rental  volume
experienced in 2001, as a result of the California energy crisis.

     Gross profit,  which  represents  total revenues  reduced by cost of sales,
decreased  by  $319,000 to a gross loss of $481,000 in 2002 from a gross loss of
$162,000 in 2001. The increase in gross loss is primarily due to the San Joaquin
and Byron projects  experiencing greater repair and maintenance costs as well as
a  higher  fuel  costs as a  result  of the  plants  operating  on their  normal
schedule, as compared to 2001 when the plants were mostly idle.

     General and administrative expenses decreased $413,000, or 68%, to $193,000
in 2002 from $606,000 in 2001. The decrease  primarily  reflects the legal costs
associated with the project's dispute with PG&E in 2001.

     The $229,000 of bad debt expense in 2001 is associated with the sale of the
San Joaquin and Byron  project's PG&E  receivables to AMROC.  In 2002, the Trust
recovered $107,000 relating to prior year PG&E revenues.

     Write  downs to the Trust's  investments  in power  generation  projects of
$143,000 and $580,000  were recorded in 2003 and 2002,  respectively.  The write
downs were comprised of Mobile Power Units $87,000  (2003) and $461,000  (2002),
the  On-Site  Cogeneration  Projects  $56,000  (2003) and  $52,000  (2002),  and
Ridgewood AES $67,000 (2002).

     The management fee paid to the Managing Shareholder  decreased by $101,000,
or 21%, to $391,000 in 2002 from $493,000 reflecting the lower net assets of the
Trust.

The loss from operations in 2002 remained comparable to 2001.

     Other income,  net, increased by $128,000,  to $136,000 in 2002 from $8,000
in 2001.  The increase is primarily due to costs incurred in issuing the "Notice
of  Solicitation of Consents" to investors in 2001. The Trust's equity income in
the Providence  Project  increased  slightly in 2002 compared to 2001 due to the
decrease in interest  expense as a result of the lower  outstanding debt balance
on the Providence Project.

     The Trust's net loss in 2002 decreased $126,000,  or 9%, from $1,482,000 in
2001 to $1,356,000 in 2002. The decrease is primarily due to decrease in general
and  administrative  expenses,  offset  by  the  write  down  of  certain  power
generation investments.

Liquidity and Capital Resources

     In 2003, the Trust's operating activities used $168,000 of cash compared to
$18,000 in 2002.

     Cash generated  from  investing  activities in 2003 and 2002 was $1,022,000
and $10,000.  The increase is reflective of the distributions  received from the
Providence  Project  in 2003  and  proceeds  of  $266,000  from  the sale of the
Ridgewood AES Project and one of the mobile power units.

     Cash  used  by  financing  activities  of  $1,187,000  in  2003  represents
distributions to shareholders.

     On June 26, 2003,  the Managing  Shareholder  of the Trust,  entered into a
$5,000,0000 Revolving Credit and Security Agreement with Wachovia Bank, National
Association.  The agreement allows the Managing  Shareholder to obtain loans and
letters of credit for the benefit of the trusts and funds that it  manages.  The
agreement  expires  on June  30,  2004.  On  February  20,  2004,  the  Managing
Shareholder  and Wachovia  Bank amended the agreement  increasing  the amount to
$6,000,000  and extending the date of expiration to June 30, 2005.As part of the
agreement,  the Trust agreed to limitations on its ability to incur indebtedness
and liens and make guarantees.

     In October 2003, the Trust issued  through its bank two standby  letters of
credit,  in the amounts of $504,000 and $792,000 to secure the gas purchases for
the Byron and San Joaquin  projects,  respectively.  The Trust used the Managing
Shareholder's credit facility to collateralize the letters of credit.

     Obligations  of the Trust are generally  limited to payment of a management
fee to  the  Managing  Shareholder  and  payments  for  certain  administrative,
accounting and legal services to third persons.  Accordingly,  the Trust has not
found it necessary to retain a material amount of working capital.

     The Providence  Project has secured long-term debt, without recourse to the
Trust, with scheduled principal payments as follows:

                  2004          $867,223

     On February 13, 2004 the  Providence  Project made a payment of $813,257 to
pay off its remaining debt. The final payment consisted of cash and the transfer
of the balance in the  Providence  Projects'  debt  reserve fund at February 13,
2004.

     The Byron and San  Joaquin  Projects  have  certain  long-term  obligations
relating to their Power  Contracts with PG&E and their Gas Agreements with Coral
(See Note 6 of the Consolidated  Financial  Statements).  The Providence Project
has certain long-term  obligations  relating to its Power Contract with NEP, its
property  lease  and  its  arrangements  with  its  gas  supplier.  The  On-site
Cogeneration Projects also have certain long-term obligations with the companies
owning the facilities where they are sited. None of these long-term  obligations
are  guaranteed by the Trust.  The Trust and its  subsidiaries  anticipate  that
during 2004 their cash flow from  operations  will be  sufficient  to meet their
obligations.

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 to 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, 2003
                       Expected Maturity Date
                              2004
                            (U.S. $)

Bank Deposits and Certificates of Deposit      $ 46,000
Average interest rate                              1.04%


Item 8.  Financial Statements and Supplementary Data.

A. Index to Consolidated Financial Statements

Report of Independent Accountants                      F-2
Report of Independent Accountants                      F-3
Consolidated Balance Sheet at December 31,
  2003 and 2002                                        F-4
Consolidated Statement of Operations for the
  three years ended December 31, 2003                  F-5
Consolidated Statement of Changes in Shareholders'
 Equity for the three years ended December 31, 2003    F-6
Consolidated Statement of Cash Flows for the three
  years ended December 31, 2003                        F-7
Notes to Consolidated Financial Statements             F-8 to F-19

Financial Statements for Ridgewood Providence Power Partners, L.P.


                       Ridgewood Electric Power Trust III

                        Consolidated Financial Statements

                        December 31, 2003, 2002 and 2001


<PAGE>


                        Report of Independent Accountants

Managing Shareholder and Shareholders'
Ridgewood Electric Power Trust III



We have  audited  the  accompanying  consolidated  balance  sheet  of  Ridgewood
Electric Power Trust III and subsidiaries  (the "Trust") as of December 31, 2003
and the related consolidated  statement of operations,  changes in shareholders'
equity  and cash flows for the year then  ended.  These  consolidated  financial
statements are the responsibility of the Trust's management.  Our responsibility
is to express an opinion on these consolidated financial statements based on our
audit.

We conducted our audit in accordance with auditing standards  generally accepted
in the  United  States of  America.  Those  standards  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.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audit  provides  a
reasonable basis for our opinion.

In our opinion, the consolidated  financial statements referred to above present
fairly, in all material  respects,  the financial position of Ridgewood Electric
Power Trust III and  subsidiaries  as of December 31,  2003,  and the results of
their  operations  and their cash flows for the year ended  December 31, 2003 in
conformity with accounting principles generally accepted in the United States of
America.







/s/ Perelson Weiner, LLP

New York, NY
March 26, 2004








<PAGE>


                        Report of Independent Accountants


To the Shareholders of
Ridgewood Electric Power Trust III:

In our opinion,  the  accompanying  consolidated  balance sheets and the related
consolidated statements of operations,  changes in shareholders' equity and cash
flows  present  fairly,  in all material  respects,  the  financial  position of
Ridgewood  Electric  Power  Trust  III and its  subsidiaries  (the  "Trust")  at
December 31, 2002, and the results of their  operations and their cash flows for
each of the two years in the period ended December 31, 2002, in conformity  with
accounting principles generally accepted in the United States of America.  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
auditing  standards  generally  accepted in the United States of America,  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 our opinion.



/s/ PricewaterhouseCoopers LLP
Florham Park, NJ
April 3, 2003



<PAGE>


Ridgewood Electric Power Trust III
Consolidated Balance Sheets
--------------------------------------------------------------------------------

                                                          December 31,
                                                 ------------------------------
                                                     2003              2002
                                                 ------------      ------------
Assets:
Cash and cash equivalents ..................     $     46,173      $    379,894
Restricted cash ............................             --             100,000
Trade receivables, net .....................          456,666           554,722
Current portion of note receivable
   from sale of investment .................           59,963              --
Assets held for sale .......................          483,994              --
Current portion unrealized gain
   on gas purchase contract ................          559,499              --
Due from affiliates ........................          860,587           277,083
Other current assets .......................          103,987           138,369
                                                 ------------      ------------
       Total current assets ................        2,570,869         1,450,068

Investment in Ridgewood
   Providence Power Partners, L.P. .........        5,669,648         5,717,184

Plant and equipment ........................        9,326,726        11,086,565
Accumulated depreciation ...................       (4,310,375)       (4,454,161)
                                                 ------------      ------------
                                                    5,016,351         6,632,404
                                                 ------------      ------------

Electric power sales contracts .............        1,793,500         1,793,500
Accumulated amortization ...................         (645,660)         (573,920)
                                                 ------------      ------------
                                                    1,147,840         1,219,580
                                                 ------------      ------------

Note receivable from sale of
    investment, less current portion .......           85,536              --
Unrealized gain on gas purchase
    contract, net of current portion .......          695,106              --
Other assets ...............................           14,000           570,000
                                                 ------------      ------------
                                                      794,642           570,000
                                                 ------------      ------------
        Total assets .......................     $ 15,199,350      $ 15,589,236
                                                 ------------      ------------

Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ......     $    127,188      $    691,714
Accrued fuel expense .......................          200,247           299,627
Due to affiliates ..........................          163,350           324,617
                                                 ------------      ------------
         Total current liabilities .........          490,785         1,315,958

Commitments and contingencies ..............             --                --

Shareholders' Equity:
Shareholders' equity (391.8444
   investor shares issued
    and outstanding) .......................       14,892,513        14,461,579
Managing shareholder's accumulated
   deficit (1 management share
   issued and outstanding) .................         (183,948)         (188,301)
                                                 ------------      ------------
         Total shareholders' equity ........       14,708,565        14,273,278
                                                 ------------      ------------
         Total liabilities and
           shareholders' equity ............     $ 15,199,350      $ 15,589,236
                                                 ------------      ------------

        See accompanying notes to the consolidated financial statements.


<PAGE>



Ridgewood Electric Power Trust III
Consolidated Statements of Operations
-------------------------------------------------------------------------------
                                                Year Ended December 31,
                                      -----------------------------------------
                                          2003           2002           2001
                                      -----------    -----------    -----------

 Power generation revenue .........   $ 7,224,948    $ 7,739,234    $ 5,978,365
 Rental revenue ...................        33,048        109,360        404,702
                                      -----------    -----------    -----------
    Total revenue .................     7,257,996      7,848,594      6,383,067

Cost of sales, including
   depreciation and
   amortization of $644,328,
   $712,386 and $710,204 in
    2003, 2002 and 2001 ...........     6,999,253      8,329,348      6,545,145
                                      -----------    -----------    -----------
Gross profit (loss) ...............       258,743       (480,754)      (162,078)
                                      -----------    -----------    -----------
General and administrative
    expenses ......................       196,627        192,936        605,967
Provision for bad debt
    (recoveries) expense ..........        37,595       (107,045)       229,443
Write down of investments
   in power generation
   projects .......................       143,179        579,550           --
Management fee paid to
  managing shareholder ............       356,742        390,743        492,430
                                      -----------    -----------    -----------
     Total other
      operating expenses ..........       734,143      1,056,184      1,327,840
                                      -----------    -----------    -----------
Loss from operations ..............      (475,400)    (1,536,938)    (1,489,918)
                                      -----------    -----------    -----------
Other income (expense):
   Interest income ................        12,934         25,306         32,337
   Interest expense ...............       (10,835)       (59,844)          --
   Unrealized gain on gas purchase
    contracts ....................      1,254,605            --            --
   Equity income from
     Ridgewood Providence
      Power Partners, L.P. ........       628,822        239,290        168,919
    Other income ..................       240,000           --             --
    Other expense .................       (27,427)       (24,210)      (193,825)
                                      -----------    -----------    -----------
     Total other income
        (expense), net ............     2,098,099        180,542          7,431
                                      -----------    -----------    -----------
Net income (loss) .................   $ 1,622,699    $(1,356,396)   $(1,482,487)
                                      -----------    -----------    -----------








        See accompanying notes to the consolidated financial statements.


<PAGE>


Ridgewood Electric Power Trust III
Consolidated Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 2003, 2002 and 2001
--------------------------------------------------------------------------------

                                        Managing
                       Shareholders    Shareholder      Total
                       -------------   -----------   -------------
Shareholders' equity
  (deficit),
January 1, 2001 .....  $ 17,272,073    $ (159,912)    $ 17,112,161

Net loss for
   the year .........    (1,467,662)      (14,825)     (1,482,487)
                       -------------   -----------   -------------
Shareholders' equity
  (deficit),
December 31, 2001 ...    15,804,411      (174,737)      15,629,674

Net loss for
   the year .........    (1,342,832)      (13,564)      (1,356,396)
                       -------------   -----------    -------------
Shareholders' equity
  (deficit),
December 31, 2002 ...    14,461,579      (188,301)       14,273,278

Cash
   distributions ....    (1,175,538)      (11,874)       (1,187,412)

Net income for
  the year ..........     1,606,472        16,227          1,622,699
                       -------------   -----------     -------------
Shareholders' equity
  (deficit),
December 31, 2003 ...  $ 14,892,513    $ (183,948)      $ 14,708,565
                       -------------   -----------     -------------







        See accompanying notes to the consolidated financial statements.


<PAGE>


Ridgewood Electric Power Trust III
Consolidated Statements of Cash Flows
--------------------------------------------------------------------------------

                                               Year Ended December 31,
                                    -----------------------------------------
                                        2003           2002           2001
                                    -----------    -----------    -----------
Cash flows from
      operating activities:
     Net income (loss) ..........   $ 1,622,699    $(1,356,396)   $(1,482,487)
                                    -----------    -----------    -----------
     Adjustments to reconcile
       net loss to net cash
       flows from operating
         activities:
     Depreciation and
        amortization ............       644,328        712,386        710,204
     Provision for
      doubtful accounts .........        37,595           --             --
     Writedown of investments in
        power generation projects       143,179        579,550           --
     Equity in earnings
       from unconsolidated
        Ridgewood  Providence
        Power Partners L.P. .....      (628,822)      (239,290)      (168,919)
     Unrealized gain on gas
      purchase contract..........    (1,254,605)          --              --
     Changes in assets
         and liabilities:
        Decrease (increase)
         restricted cash ........       100,000        197,430       (297,430)
       Increase (decrease)
       in trade receivables .....       (13,933)       207,672      1,217,945
       Decrease (increase)
        in other current assets .        34,382        (60,866)       121,897
       Decrease (increase)
            in other assets .....       556,000        (14,000)      (556,000)
       (Decrease) increase
    in accounts payable
      and accrued
         expenses ...............      (564,526)      (213,812)        88,100
       Decrease in accrued
        fuel expense ............       (99,380)      (154,873)      (305,092)
       Increase (decrease)
        in due to affiliates, net      (744,771)       573,968       (550,342)
       (Decrease) increase
         in other liabilities ...          --         (250,000)       250,000
                                    -----------    -----------    -----------
         Total adjustments ......    (1,790,553)     1,338,165      1,120,547
                                    -----------    -----------    -----------
         Net cash used in
         operating activities ...      (167,854)       (18,231)      (361,940)
                                    -----------    -----------    -----------
Cash flows from
  investing activities:
     Cash distribution
       from Ridgewood Providence
       Power Partners L.P. ......       676,357           --          356,732
     Proceeds from sale
       of investment, net .......       266,292           --             --
     Proceeds from
         note receivable ........        78,895           --             --
     Reimbursement (payment)
      of capital expenditures ...          --           10,453        (33,247)
                                    -----------    -----------    -----------
         Net cash provided
         by investing activities      1,021,545         10,453        323,485
                                    -----------    -----------    -----------
Cash flows from
    financing activities:
     Cash distributions
        to shareholders .........    (1,187,412)          --             --
                                    -----------    -----------    -----------
         Net cash used in
           financing activities .    (1,187,412)          --             --
                                    -----------    -----------    -----------
Net decrease in cash
   and cash equivalents .........      (333,721)        (7,778)       (38,455)
Cash and cash equivalents,
    beginning of year ...........       379,894        387,672        426,127
                                    -----------    -----------    -----------
Cash and cash equivalents,
    end of year .................   $    46,173    $   379,894    $   387,672
                                    -----------    -----------    -----------






        See accompanying notes to the consolidated financial statements.


<PAGE>


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

1. Organization and Purpose

Nature of Business
Ridgewood  Electric  Power  Trust III (the  "Trust")  was  formed as a  Delaware
business  trust on December 6, 1993.  The managing  shareholder  of the Trust is
Ridgewood Renewable Power LLC (formerly 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.

Christiana  Bank & Trust Company,  a Delaware  trust  company,  is the Corporate
Trustee of the Trust.  The  Corporate  Trustee acts on the  instructions  of the
Managing  Shareholder  and is not authorized to take  independent  discretionary
action on behalf of the Trust.

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

In November 2001,  through a proxy  solicitation  the Trust  requested  investor
consent to end the BDC status. On December 18, 2001, the consents were tabulated
and more than 50% of the investor shares consented to the elimination of the BDC
status. Accordingly, the Trust is no longer an investment company under the 1940
Act.

2. Summary of Significant Accounting Policies

Principles of consolidation
The consolidated  financial statements include the accounts of the Trust and its
controlled  subsidiaries.  All  material  intercompany  transactions  have  been
eliminated.

The Trust uses the equity method of accounting for its investments in affiliates
which are 50% or less owned if the Trust has the ability to exercise significant
influence  over the operating and financial  policies of the affiliates but does
not control the  affiliate.  The Trust's share of the  operating  results of the
affiliates is included in the Consolidated Statements of Operations.

Use of estimates
The  preparation  of  consolidated   financial  statements  in  accordance  with
accounting  principles  generally  accepted  in the  United  States of  America,
requires  the Trust to make  estimates  and  judgments  that affect the reported
amounts of assets,  liabilities,  sales and expenses,  and related disclosure of
contingent assets and liabilities. On an on-going basis, the Trust evaluates its
estimates,  including  provision for bad debts,  carrying value of  investments,
amortization/depreciation  of plant and equipment  and  intangible  assets,  and
recordable  liabilities for litigation and other contingencies.  The Trust bases
its  estimates on historical  experience,  current and expected  conditions  and
various  other  assumptions  that  are  believed  to  be  reasonable  under  the
circumstances,  the results of which form the basis for making  judgments  about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates.

New Accounting Standards and Disclosures

SFAS 143
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143,
Accounting for Asset Retirement  Obligations,  on the accounting for obligations
associated  with the  retirement  of  long-lived  assets.  SFAS 143  requires  a
liability  to  be  recognized  in  the  consolidated  financial  statements  for
retirement  obligations  meeting specific  criteria.  Measurement of the initial
obligation is to approximate fair value,  with an equivalent  amount recorded as
an increase in the value of the capitalized asset. The asset will be depreciated
in  accordance  with  normal  depreciation  policy  and  the  liability  will be
increased  for the time value of money,  with a charge to the income  statement,
until  the  obligation  is  settled.  SFAS 143 is  effective  for  fiscal  years
beginning  after June 15, 2002. The Trust adopted SFAS 143 effective  January 1,
2003, with no material impact on the consolidated financial statements.

SFAS 145
In April 2002, the FASB issued SFAS No. 145,  Rescission of FASB  Statements No.
4, 44, and 64,  Amendment of FASB  Statement No. 13, and  Technical  Correction.
SFAS No. 145 eliminates extraordinary accounting treatment for reporting gain or
loss  on  debt   extinguishment,   and  amends  other   existing   authoritative
pronouncements  to make various  technical  corrections,  clarify  meanings,  or
describe their applicability  under changed  conditions.  The Trust adopted SFAS
145  effective  January 1, 2003,  with no  material  impact on the  consolidated
financial statements.

SFAS 146
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal  Activities.  SFAS No. 146 requires  recording costs associated
with exit or disposal  activities at their fair values when a liability has been
incurred. The Trust adopted SFAS 146 effective January 1, 2003, with no material
impact on the consolidated financial statements.

FIN 45
In  November  2002,  the FASB  issued  FASB  Interpretation  No. 45 ("FIN  45"),
"Guarantor's  Accounting and Disclosure  Requirements for Guarantees,  Including
Indirect  Guarantees  and  Indebtedness  of Others."  FIN 45  elaborates  on the
disclosures  to be made by the  guarantor  in its interim  and annual  financial
statements about its obligations under certain guarantees that it has issued. It
also requires  that a guarantor  recognize,  at the inception of a guarantee,  a
liability  for the fair  value  of the  obligation  undertaken  in  issuing  the
guarantee.   The  initial   recognition  and  measurement   provisions  of  this
interpretation  are  applicable on a prospective  basis to guarantees  issued or
modified  after  December  31,  2002;  while the  provisions  of the  disclosure
requirements are effective for financial statements of interim or annual reports
ending after December 15, 2002. The Trust adopted FIN 45 with no material impact
to the consolidated financial statements.

FIN 46
In December 2003, the FASB issued FASB  Interpretation No. 46, (Revised December
2003) "Consolidation of Variable Interest Entities" ("FIN 46") which changes the
criteria  by which one  company  includes  another  entity  in its  consolidated
financial  statements.  FIN  46  requires  a  variable  interest  entity  to  be
consolidated  by a company if that  company is subject to a majority of the risk
of loss from the variable interest entity's  activities or entitled to receive a
majority  of  the  entity's   residual   returns  or  both.  The   consolidation
requirements of FIN 46 apply  immediately to variable  interest entities created
after December 31, 2003, and apply in the first fiscal period ending after March
15, 2004, for variable  interest  entities created prior to January 1, 2004. The
Trust adopted the disclosure  provisions of FIN 46 effective  December 31, 2002,
with no material impact to the consolidated financial statements. The Trust will
implement the full  provisions of FIN 46 effective  January 1, 2004 and does not
anticipate a material impact to the consolidated financial statements.

SFAS 149
In April 2003,  the FASB issued SFAS No. 149,  "Amendment  of  Statement  133 on
Derivative  Instruments  and  Hedging  Activities."  SFAS  No.  149  amends  and
clarifies  the  accounting  for  derivative   instruments,   including   certain
derivative  instruments embedded in other contracts,  and for hedging activities
under  SFAS  No.  133,  "Accounting  for  Derivative   Instruments  and  Hedging
Activities."  SFAS No. 149 is generally  effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003.  The Trust adopted SFAS 149 effective  July 1, 2003,  resulting in the
Trust  recording an asset at fair value and an unrealized  gain of $1,254,605 on
its gas purchase and re-sale agreements.

SFAS 150
In May 2003,  the FASB  issued SFAS No. 150,  Accounting  for Certain  Financial
Instruments with  Characteristics  of both Liabilities and Equity.  SFAS No. 150
establishes   standards  for   classifying  and  measuring   certain   financial
instruments  with  characteristics  of both  liabilities  and equity.  The Trust
adopted  SFAS  150  effective  July 1,  2003,  with no  material  impact  on the
consolidated financial statements.

Significant Accounting Policies

Cash and cash equivalents
The Trust considers all highly liquid investments with maturities when purchased
of  three  months  or  less,  to be cash  and  cash  equivalents.  Cash and cash
equivalents consist of commercial paper and funds deposited in bank accounts.

Trade receivables
Trade  receivables  are recorded at invoice price and do not bear  interest.  An
allowance  for bad debt  expense of $37,595 and $0 in at  December  31, 2003 and
2002,  respectively,  was provided based upon historical  write-off  experience,
evaluation of customer credit  condition and the general  economic status of the
customer.

Impairment of Long-Lived Assets and Intangibles
In accordance with the provisions of SFAS No. 144, Accounting for the Impairment
of Long-Lived Assets to be Disposed Of, the Trust evaluates  long-lived  assets,
such as fixed assets and specifically identifiable  intangibles,  when events or
changes in circumstances indicate that the carrying value of such assets may not
be recoverable.  The determination of whether an impairment has occurred is made
by comparing the carrying value of an asset to the estimated  undiscounted  cash
flows attributable to that asset. If an impairment has occurred,  the impairment
loss recognized is the amount by which the carrying value exceeds the discounted
cash flows attributable to the asset or the estimated fair value of the asset.

Plant and equipment
Plant and equipment,  consisting principally of electrical generating equipment,
is stated at cost. Major renewals and betterments that increase the useful lives
of the assets are capitalized. Repair and maintenance expenditures that increase
the  efficiency of the assets are expensed as incurred.  The Trust  periodically
assesses the recoverability of plant and equipment,  and other long-term assets,
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable.

Depreciation is recorded using the straight-line method over the useful lives of
the  assets,  which are 10 to 20 years  with a  weighted  average of 18 years at
December  31, 2003 and 2002.  During  2003,  2002 and 2001,  the Trust  recorded
depreciation expense of $572,588, $640,646 and $638,464, respectively.

Electrical Power Sales Contracts
A portion of the  purchase  price of the JRW  Associates  L.P.  and Byron  Power
Partners,  L.P.  were assigned to electric  power sales  contracts and are being
amortized over the lives of the contracts (25 years) on a  straight-line  basis.
The electric power sales  contracts are reviewed for impairment  whenever events
or changes in circumstances  indicate that the carrying amount of the assets may
not be recoverable.  During 2003, 2002 and 2001, the Trust recorded amortization
expense of $71,740 each year.

Revenue recognition
Power  generation  revenue is  recorded in the month of  delivery,  based on the
estimated  volumes  sold to  customers  at rates  stipulated  in the power sales
contracts.  Adjustments  are made to reflect actual  volumes  delivered when the
actual information  subsequently  becomes  available.  Billings to customers for
power  generation  generally occurs during the month following  delivery.  Final
billings do not vary significantly  from estimates.  Rental revenue and interest
income are recorded when earned and dividend income is recorded when declared.

Significant Customers and Supplier
During  2003,  2002 and 2001,  the  Trust's  largest  customer,  Pacific Gas and
Electric Company ("PG&E"), accounted for 72%, 75% and 53%, respectively of total
revenues.  During  2003,  2002 and 2001,  the Trust's  second  largest  customer
accounted for 18%, 12% and 17%,  respectively of total revenues.  In early 2001,
PG&E  experienced  severe  financial  difficulty,  see  Note  8  for  additional
discussion.  During 2003,  2002 and 2001,  the Trust  purchased  100% of the San
Joaquin and Byron Projects gas supply from one supplier.

Income taxes
No provision is made for income taxes in the accompanying consolidated 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. At December 31,
2003 and  2002,  the  Trust's  net  assets  had a tax basis of  $20,170,582  and
$21,374,328, respectively.

Supplemental cash flow information
Total interest paid during the years ended December 31, 2003,  2002 and 2001 was
$10,835, $59,844 and $0, respectively.

In conjunction with the sale of Ridgewood AES in March 2003, accounts receivable
of $74,344 was converted to a note  receivable.  In the fourth  quarter of 2003,
the Trust  recorded  $483,994  in Assets held for sale.  Accordingly,  the Trust
reduced Plant and equipment $483,994.

Reclassification
Certain items in previously issued consolidated  financial  statements have been
reclassified for comparative purposes. This had no effect on income or loss.

3. Projects

JRW Associates, L.P. (known as the San Joaquin Project)
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
purchase price was $4,898,987 including transaction costs.

The  acquisition of the San Joaquin  Project was accounted for as a purchase and
the results of operations  of the San Joaquin  Project have been included in the
Trust's  consolidated  financial  statements  since the  acquisition  date.  The
purchase  price  was  allocated  to the net  assets  acquired,  based  on  their
respective fair values.  Of the purchase price,  $1,374,000 was allocated to the
Electric  Power  Sales  Contract  and is  being  amortized  over the life of the
contract  (25 years).  See Note 8 - Pacific Gas and Electric  Company  Financial
Crisis, for developments affecting the Byron and San Joaquin Projects.

Byron Power Partners, L.P. (known as the Byron Project)
In January 1995, the Trust caused the formation of Byron Power Partners, L.P. in
which the Trust owns 100% of the  partnership  interests.  On January 17,  1995,
Byron  Power  Partners,  L.P.  acquired  a 5.7  megawatt  electric  cogeneration
facility,  located  in  Byron,  California.  The  aggregate  purchase  price was
$2,508,847 including transaction costs.

The  acquisition  of the Byron  Project was  accounted for as a purchase and the
results of  operations  of the Byron  Project have been  included in the Trust's
consolidated financial statements since the acquisition date. The purchase price
was allocated to the net assets acquired, based on their respective fair values.
Of the  purchase  price,  $419,500 was  allocated  to the  Electric  Power Sales
Contract and is being  amortized  over the life of the contract (25 years).  See
Note 8 - Pacific Gas and Electric  Company  Financial  Crisis,  for developments
affecting the Byron and San Joaquin Projects.

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") which acquired 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  megawatts.  The Trust  invested  $7,132,860  in return for a 35.7% limited
partnership interest in Providence Power and its general partner.

The Providence  Project is 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 remaining 64.3% of Ridgewood Power is owned by
Ridgewood  Electric Power Trust IV ("Trust IV"),  whose managing partner is also
Ridgewood Renewable Power LLC.

The Trust's  investment  in the  Providence  Project is accounted  for under the
equity  method  of  accounting.  The  Trust's  equity  in  the  earnings  of the
Providence  Project has been included in the consolidated  financial  statements
since acquisition.

Summarized financial  information for Ridgewood Providence Power Partners,  L.P.
is as follows:

  Balance Sheet
                                   As of December 31,
                                   2003          2002
                               -----------   -----------

Current assets .............   $ 2,683,947   $ 1,827,155
Other non-current assets ...    15,084,289    17,088,980
                               -----------   -----------
Total assets ...............   $17,768,236   $18,916,135
                               -----------   -----------

Current liabilities ........   $ 1,886,867   $ 2,034,392
Long-term debt .............          --         867,223
                               -----------   -----------
Total liabilities and equity   $17,768,236   $18,916,135
                               -----------   -----------
Trust share ................   $ 5,669,648   $ 5,717,184
                               -----------   -----------


<PAGE>

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

  Statements of Operations


                        For the Year Ended December 31,
                     ------------------------------------
                        2003         2002         2001
                     ----------   ----------   ----------

Revenue ..........   $8,552,957   $7,344,120   $7,472,308
                     ----------   ----------   ----------
Cost of sales ....    6,023,645    5,885,503    5,840,911
Other expenses,
    net ..........      767,905      788,338    1,221,061
                     ----------   ----------   ----------
Total expenses ...    6,791,550    6,673,841    7,061,972
                     ----------   ----------   ----------
Net income .......   $1,761,407   $  670,279   $  410,336
                     ----------   ----------   ----------

Trust share ......   $  628,822   $  239,290   $  168,919
                     ----------   ----------   ----------


Ridgewood Mobile Power III, LLC (a wholly owned subsidiary)
Effective August 1999, the Trust acquired five Caterpillar  mobile power modules
with a total capacity of 4.2 megawatts for $1,695,558.  These modules are rented
to domestic and  international  customers.  As per an agreement  with  Hawthorne
Power Systems ("Hawthorne"), the Trust pays Hawthorne, a California company that
maintains a large fleet of similar rental modules,  a fee of 20% of gross rental
revenues to arrange and  administer  the rental of the units.  The revenue  from
these modules is included as rental revenue and  Hawthorne's  fee is included in
cost of sales in the Consolidated Statement of Operations.

Due to the increase in competition and production of newer efficient models, the
Trust experienced a decrease in rental revenue for the second  consecutive year.
As a result of the change in these market  conditions,  the forecasted  revenues
for the mobile power modules are not expected to be enough to recover the units'
book  value.  In 2003 and 2002,  the Trust  recorded  writedowns  of $87,465 and
$460,697,  respectively,  to reflect the units fair market value. The writedowns
have been  presented as a separate line item under other  operating  expenses in
the Consolidated Statements of Operations.

In the third quarter of 2003, the Trust decided to make its mobile power modules
available for sale.  Shortly after making the mobile power modules available for
sale,  the Trust sold one module for  $171,000.  The remaining net book value of
$483,994,  as of December 31, 2003,  is reflected as Assets held for sale on the
accompanying Consolidated Balance Sheet.

Ridgewood AES Power Partners, LLC (known as Ridgewood AES)
In 1997, the Trust formed Ridgewood AES Power Partners,  LLC and entered into an
agreement  with AES-NJ  Cogen,  Inc.  (AES-NJ)  to invest in five  co-generation
facilities operated by AES-NJ. The facilities are all located in New York.

In March 2003, the Trust,  sold 100% of its ownership  interest in Ridgewood AES
to  AES-NJ.  The  acquisition  agreement  provides  for the  sale of 100% of the
Trust's  ownership  in  Ridgewood  AES in return for  $100,000  cash, a $150,000
interest bearing promissory note ("promissory note") and a $74,394 interest free
note ("interest free note"). The promissory note bears interest at a rate of 10%
per annum,  and will be repaid  monthly over a four year term. The interest free
note will be repaid over a six month term. Both notes are guaranteed by AES-NJ.

In 2002,  the Trust recorded a writedown of $66,783 to reflect the projects fair
market value as determined by the terms of the sale agreement. The writedown has
been  presented as a separate  line item under other  operating  expenses in the
Consolidated  Statements of  Operations.  The sale of Ridgewood AES has not been
disclosed as a discontinued  operation due to the immateriality of the project's
operating results.

Ridgewood El Segundo, LLC (known as the El Segundo 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.  During 2000, the Trust analyzed the
carrying value of the El Segundo Project assets using an estimated  undiscounted
cash flow analysis.  Using this analysis, an impairment loss was recorded during
2000 in the amount of $524,054,  bringing the book value of the project to zero.
In the third quarter of 2003, the project's power generation  agreement with its
host expired.

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 were 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.  All the
projects  were   gas-fired   cogeneration   projects,   located  in  California,
Connecticut,  Massachusetts,  Rhode  Island or New York.  Their  energy  service
agreements had terms expiring  between  September 1996 and 2011. The acquisition
of the projects was accounted for as a purchase and the results of operations of
the projects have been included in the Trust's consolidated financial statements
since the acquisition date.

The Trust has shut down the majority of the  projects  and as a result  recorded
writedowns  of  $52,070 in 2002,  and  $10,764,642  in the years  prior to 2001.
During 2003, the Trust recorded an additional writedown of $55,714 to adjust the
carrying  value of the projects to reflect their current fair market value.  The
writedown  has been  presented  as a separate  line item under  other  operating
expenses in the Consolidated  Statements of Operations.  Two of the projects are
still operated by the Trust with a total base load of 2 megawatts.

4. Transactions With Managing Shareholder And Affiliates

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 prior year's net asset
value of the Trust payable  monthly.  During 2003, 2002 and 2001, the Trust paid
management fees to the managing shareholder of $356,742,  $390,743 and $492,430,
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  a  cumulative  amount  equal  to 14%  per  annum  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, 2003.

The managing  shareholder  owns one  investor  share of the Trust with a cost of
$84,000.  The Trust granted the managing  shareholder a single  Management Share
representing  the  managing  shareholder's   management  rights  and  rights  to
distributions of cash flow.

Effective  from January 1, 1996,  under an operating  agreement  with the Trust,
Ridgewood Power  Management LLC ("Ridgewood  Management"),  an entity related to
the  managing   shareholder  through  common  ownership,   provides  management,
purchasing,  engineering,  planning  and  administrative  services  to the power
generation  projects  operated by the Trust.  Ridgewood  Management  charges the
projects at its cost for these services and for the allocable  amount of certain
overhead  items.  Allocations of costs are on the basis of  identifiable  direct
costs,  time records or in proportion to amounts invested in projects managed by
Ridgewood  Management.  During the year ended December 31, 2003,  2002 and 2001,
Ridgewood   Management   charged  the   following  to  the  projects   based  on
proportionate amounts invested:


                                   For the Year Ended December 31,
                                   -------------------------------
                                      2003       2002       2001
                                   ---------  ---------  ---------
JRW Associates, L.P. ............   $120,180   $132,732   $152,098
Byron Power Partners, L.P. ......     71,174     78,510     89,966
Ridgewood Providence
       Power Partners, L.P. .....    451,626    570,159    538,262
Ridgewood El Segundo LLC ........     14,015     15,029     17,223
On-site Cogeneration Projects:
  Ridgewood/Mass PPLP ...........      3,609      4,367      6,658
  Ridgewood/Elmsford PPLP .......     32,215     35,579     40,771
  Other On-site Cogeneration
      Project Partnerships ......     28,241     33,693     55,354



From time to time, the Trust records  short-term  payables and receivables  from
other  affiliates in the ordinary  course of business.  The amounts  payable and
receivable with the other affiliates do not bear interest.  At December 31, 2003
and 2002, the Trust had outstanding payables and receivables, with the following
affiliates:

                                           As of December 31,
                                      Due To              Due From
                               -----------------------------------------
                                  2003      2002       2003       2002
                               -------------------   -------------------
Ridgewood Management .......   $   --     $   --     $290,184   $226,753
Ridgewood Providence
  Power Partners, L.P. .....       --      266,285    570,073       --
Ridgewood Renewable Power ..    107,680       --         --       50,000
Other affiliates ...........     55,670     58,332        330        330
                               --------   --------   --------   --------
Total ......................   $163,350   $324,620   $860,587   $277,083
                               ========   ========   ========   ========


5. Line of Credit Facility and Letters of Credit

On June 26, 2003, Ridgewood Renewable Power LLC, the Managing Shareholder of the
Trust,  entered into a $5,000,0000  Revolving Credit and Security Agreement with
Wachovia  Bank,  National   Association.   The  agreement  allows  the  Managing
Shareholder  to obtain loans and letters of credit for the benefit of the trusts
and funds that it manages.  The agreement  expires on June 30, 2004. On February
20, 2004,  the Managing  Shareholder  and  Wachovia  Bank amended the  agreement
increasing the amount to $6,000,000 and extending the date of expiration to June
30,  2005.  As part of the  agreement,  the Trust agreed to  limitations  on its
ability to incur indebtedness, liens and provide guarantees.

In October  2003,  the Trust  issued  through  its bank two  standby  letters of
credit,  in the amounts of $504,000 and $792,000 to secure the gas purchases for
the Byron and San  Joaquin  projects,  respectively.  The Trust  used  Ridgewood
Renewable Power's credit facility to collateralize the letters of credit.

6. Commitments and Contingencies

The Trust,  through  certain of its  subsidiaries,  has two long-term  operating
ground leases.

 Future minimum lease payments as of December 31, 2003 are as follows:

                                   Year Ended
                                   December 31,            Repayment
                                   ------------            ---------
                                   2004                     $173,256
                                   2005                      173,256
                                   2006                      173,256
                                   2007                      173,256
                                   2008                      173,256
                                   Thereafter              2,136,962
                                                           ---------
                                   Total                  $3,003,242
                                                          ----------

Rent expense for the years ended December 31, 2003,  2002 and 2001 was $173,256,
$172,932 and $172,332, respectively.

The San  Joaquin  and Byron  projects  have a  long-term  agreement  to purchase
natural gas from its supplier at a fixed price  throughout the term, which as of
December 31, 2003, is below market prices. The agreement expires in August 2006.

Future  minimum  purchases  under the  agreement  as of December 31, 2003 are as
follows:

                                   Year Ended
                                   December 31,            Purchases
                                   ------------            ---------
                                   2004                   $2,296,766
                                   2005                    3,512,322
                                   2006                    2,341,548
                                                           ---------
                                   Total                  $8,150,636
                                                          ----------

In order to hedge  exposure to commodity  price risks and to maximize the impact
of the increase in natural gas prices,  the Trust entered into a master  re-sale
agreement  with  its  supplier  of  natural  gas to the San  Joaquin  and  Byron
projects.  The master re-sale  agreement,  which expires in August 2006, compels
the supplier to repurchase  from the Trust any natural gas the Trust chooses not
to take delivery of if a predetermined re-sale price has been established. As of
December 31, 2003, a re-sale price to the supplier,  in excess of the underlying
cost of the natural gas, has been  established  for 2004. In 2003, the Trust has
recorded an unrealized  gain of $1,254,605 in accordance with SFAS 149 utilizing
re-sale  prices   committed  for  and  fair  value  prices  for  re-sale  prices
uncommitted for.

7. Fair Value of Financial Instruments

At December 31, 2003 and 2002,  the carrying  value of the Trust's cash and cash
equivalents,   trade   receivables,   accounts   payable  and  accrued  expenses
approximates  their fair value. The fair value of the letters of credit does not
differ materially from its carrying value.

8. Pacific Gas and Electric Company Financial Crisis

Due to financial  difficulties,  PG&E did not pay in full for electrical  energy
and capacity  delivered by the San Joaquin and Byron  Projects in December  2000
and January 2001. Accordingly, the San Joaquin and Byron Projects were unable to
pay their natural gas supplier for the gas  delivered for those months.  In late
January of 2001, the gas supplier requested assurance of payment before it would
agree to provide natural gas during February. Due to PG&E's financial crisis and
its  inability to pay, the San Joaquin and Byron  Projects  were unable on their
own to provide an  acceptable  assurance or to pay the arrears and, as a result,
the  supplier  refused to provide  natural  gas beyond  February 6, 2001 and the
Trust shut down the San Joaquin and Byron  Projects.  Many qualified  facilities
under  contract  with  PG&E  suffered  the same  fate and  were  forced  to shut
operations  because of PG&E's failure to pay for energy and capacity  delivered.
On  April 6,  2001,  as a result  of its  financial  problems,  PG&E  filed  for
protection under the U.S. Bankruptcy laws.

In April 2001, the San Joaquin and Byron Projects entered into an agreement with
a financial  institution  whereby they sold,  irrevocably and without  recourse,
their undivided interest in all eligible trade accounts receivables for December
2000 and January 2001. Costs associated with the sale of receivables of $229,443
for 2001,  primarily  related to the discount  and loss on sale,  is included in
provision for bad debt expense in the Consolidated Statements of Operations.

In August  2001,  PG&E and the San  Joaquin  and  Byron  Projects  entered  into
amendments to the electric power sales contracts for a term of five years, which
would  effectively  replace,  for such 5 year term,  the  variable  formula  for
determining the energy price with a fixed energy price. Also in August 2001, the
San Joaquin and Byron  Projects  entered into five year fixed price  natural gas
supply agreements with Coral Energy Services,  Inc.  ("Coral"),  a subsidiary of
Shell Oil. In addition to the letters of credit  discussed in Note 5 above,  the
gas supply agreements  required the San Joaquin and Byron Projects to maintain a
deposit  of  $556,000  with  Coral  which is  reflected  as other  assets in the
December 31, 2002  Consolidated  Balance  Sheet.  In the fourth quarter of 2003,
upon the amending and  extension  of the letters of credit,  Coral  returned the
Trust's deposit.

In the second half of 2001,  the previous  natural gas supplier made demands for
payment of the arrears owed by the San Joaquin and Byron  Projects.  In December
2001, the San Joaquin and Byron Projects and the natural gas supplier executed a
settlement agreement.  Pursuant to the settlement  agreement,  the Byron and San
Joaquin  Projects  were  required  to pay the  natural  gas  supplier an upfront
payment  against the  arrearage  and the  remainder to be paid over the next two
years at 8%  interest  rate per annum.  The entire  balance  was  required to be
discharged  no later  than the end of July  2003.  The Trust has  reflected  the
$250,000  due  in  2003  as  a  current  liability  in  the  December  31,  2002
Consolidated   Balance  Sheet.  In  2003,  in  accordance  with  the  settlement
agreement, the Trust made the final scheduled payment.

9. Financial Information by Business Segment

The Trust's business  segments were determined based on similarities in economic
characteristics  and customer  base.  The Trust's  principal  business  segments
consist of wholesale and retail.

Common  services  shared by the business  segments are allocated on the basis of
identifiable  direct costs,  time records or in proportion to amount invested in
projects managed by Ridgewood Management.

The financial data for business segments are as follows:


                                          Wholesale
                          -----------------------------------------
                              2003           2002           2001
                          ------------   ------------   -----------
Revenue ...............   $ 5,245,931    $ 5,917,877    $ 3,363,789
Depreciation and
  amortization ........       426,269        428,036        426,954
Operating income (loss)       246,685       (470,425)    (1,283,347)
Total assets ..........     7,096,367      6,812,337      7,387,797
Capital expenditures ..          --          (10,453)        33,247



                                            Retail
                          -----------------------------------------
                              2003           2002           2001
                          -----------    ------------   -----------
Revenue ...............   $ 2,012,065    $ 1,930,720    $ 3,019,278
Depreciation and
  amortization ........       218,059        284,350        283,250
Operating income (loss)       (10,597)      (168,694)       512,084
Total assets ..........     1,522,975      2,291,340      3,200,827
Capital expenditures ..          --             --             --



                                           Corporate
                          -----------------------------------------
                              2003           2002           2001
                          -----------    ------------   -----------
Revenue ...............   $      --      $      --      $      --
Depreciation and
  amortization ........          --             --             --
Operating loss ........      (711,488)      (897,819)      (718,655)
Total assets ..........     6,483,254      6,485,559      6,892,171
Capital expenditures ..          --             --             --



                                            Total
                          -----------------------------------------
                              2003           2002           2001
                          -----------    ------------   -----------
Revenue ...............   $ 7,257,996    $ 7,848,597    $ 6,383,067
Depreciation and
  amortization ........       644,328        712,386        710,204
Operating loss ........      (475,400)    (1,536,938)    (1,489,918)
Total assets ..........    15,102,596     15,589,236     17,480,795
Capital expenditures ..          --          (10,453)        33,247





10. Renewable Attribute Revenue

In 1997,  Massachusetts  enacted  the  Electric  Restructuring  Act of 1997 (the
"Restructuring  Act").  Among other things,  the Restructuring Act requires that
all retail electricity suppliers in Massachusetts (i.e. those entities supplying
electric energy to retail end-use customers in Massachusetts) purchase a minimum
percentage of their electricity supplies from qualified new renewable generation
units  powered  by one of several  renewable  fuels,  such as solar,  biomass or
landfill.  Beginning in 2003, each such retail supplier must obtain at least one
(1%) percent of its supply from qualified new renewable  generation  units. Each
year  thereafter,  the requirement  increases  one-half of one percentage  point
until  2009,  when the  requirement  equals  four (4%)  percent  of each  retail
supplier's  sales  in  that  year.  Subsequent  to  2009,  the  increase  in the
percentage requirement will be determined and set by the DOER.

On  January  17,  2003,  the  Providence   Project   received  a  "Statement  of
Qualification"  from the  Massachusetts  Division of Energy  Resources  ("DOER")
pursuant to the renewable  portfolio standards ("RPS") adopted by Massachusetts.
Since the Providence Project has become qualified,  it is able to sell to retail
electric  suppliers the RPS Attributes  associated  with its electrical  energy.
Retail  electric  suppliers  need to purchase  RPS  Attributes  associated  with
renewable energy and not necessarily the energy itself. Thus,  electrical energy
and RPS Attributes are separable products and need not be sold or purchased as a
bundled product.  Retail electric  suppliers in Massachusetts  will then use the
purchase of such RPS Attributes to demonstrate compliance with the Restructuring
Act and RPS Regulations.

For the year ended December 31, 2003, the Providence  Project recorded Renewable
attribute revenue totaling $772,370.




<PAGE>

B. Supplementary Financial Information (Unaudited)

Selected Quarterly Financial Data for the years ended December 31, 2003 and
2002.


                                               2003
                         -------------------------------------------------------
                            First         Second         Third         Fourth
                           Quarter        Quarter       Quarter        Quarter
                         -----------    -----------   -----------   ------------
Revenue ..............   $ 1,647,000    $ 1,930,000   $ 2,366,000   $ 1,315,000
Income (loss) from
 operations ..........      (354,000)       256,000       329,000      (706,000)
Net income (loss) ....        93,000        334,000     1,127,000        69,000



                                             2002
                        --------------------------------------------------------
                            First        Second          Third         Fourth
                           Quarte        Quarter        Quarter        Quarter
                        -----------    -----------    -----------   ------------
Revenue .............   $ 1,659,000    $ 2,199,000    $ 2,390,000   $ 1,601,000
Income (loss) from
 operations .........      (470,000)      (315,000)       265,000    (1,017,000)
Net income (loss) ...      (495,000)      (301,000)       286,000      (846,000)


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

     The  Trust   dismissed   PricewaterhouseCoopers   LLP  as  its  independent
accountants on January 14, 2004 and appointed  Perelson Weiner LLP as successor,
as reported in the Trust's  Current  Report on Form 8-K dated  January 20, 2004,
incorporated   herein  by   reference.   There   were  no   disagreements   with
PricewaterhouseCoopers LLP for the years ended December 31, 2002 and 2001 or for
the interim period  through  January 20, 2004,  whether or not resolved,  on any
matter of accounting principles or practices, financial statement disclosure, or
auditing  scope  or  procedure,  which  disagreements  if  not  resolved  to the
satisfaction  of  PricewaterhouseCoopers  LLP  would  have  caused  them to make
reference thereto in their report on the financial statements for such years.

Item 9A.  Controls and Procedures

     Within the 90 days prior to the filing  date of this  Report,  the  Trust's
Chief Executive  Officer and Chief Financial  Officer conducted an evaluation of
the effectiveness and design of the Trust's  disclosure  controls and procedures
pursuant to Rule 13a-15 of the  Securities  Exchange Act of 1934 (the  "Exchange
Act").  Based  upon that  evaluation,  the  Chief  Executive  Officer  and Chief
Financial  Officer each concluded  that the  disclosure  controls and procedures
were effective.

     There have been no significant changes in the internal controls or in other
factors that could  significantly  affect these controls  subsequent to the date
that they completed their evaluation.

     The term "disclosure  controls and procedures" is defined in Rule 13a-15(e)
of the Exchange Act as "controls  and other  procedures  designed to ensure that
information  required  to be  disclosed  by the issuer in the  reports  files or
submits under the Exchange Act is recorded, processed,  summarized and reported,
within the time periods specified in the [Securities and Exchange]  Commission's
rules and forms." The Trust's disclosure controls and procedures are designed to
ensure that material  information  relating to the consolidated  subsidiaries is
accumulated  and  communicated  to  management,  including  the Chief  Executive
Officer and Chief Financial  Officer,  as appropriate to allow timely  decisions
regarding the required disclosures.

PART III

Item 10.  Directors and Executive Officers of the Registrant.

(a) General.

     As Managing  Shareholder of the Trust,  Ridgewood  Renewable  Power LLC has
direct and exclusive  discretion in management and control of the affairs 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.

(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.  It
organized  the Trust and acted as managing  shareholder  until April 1999. On or
about  April 21,  1999 it was  merged  into the  current  Managing  Shareholder,
Ridgewood Power LLC. In December of 2002,  Ridgewood Power, LLC changed its name
to Ridgewood  Renewable Power, LLC. Robert E. Swanson is the controlling member,
sole manager and President of the Managing Shareholder. All of the equity in the
Managing  Shareholder is owned by Mr.  Swanson or by family trusts.  Mr. Swanson
has the power on behalf of those  trusts to vote or  dispose  of the  membership
equity interests owned by them.

     The  Managing  Shareholder  has also  organized  the Other Power  Trusts as
Delaware  business  trusts  or  other  Delaware  limited  liability   companies.
Ridgewood  Renewable  Power LLC is the managing  shareholder  of the Other Power
Trusts and the manager of the Ridgewood  LLCs. The business  objectives of these
trusts and LLCs 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.  In April 1999, most of them were merged into limited  liability
companies  with  similar  names and Mr.  Swanson  became  the sole  manager  and
controlling  owner of each  limited  liability  company.  For  convenience,  the
remainder of this Memorandum will discuss each limited liability company and its
corporate predecessor as a single entity.

     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 18  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 LLC ("Ridgewood  Securities"),
an NASD member  which has been the  placement  agent for the  private  placement
offerings of the eight trusts  sponsored  by the  Managing  Shareholder  and the
funds  sponsored  by  Ridgewood  Energy;   Ridgewood   Capital   Management  LLC
("Ridgewood  Capital"),   which  assists  in  offerings  made  by  the  Managing
Shareholder  and which is the sponsor of four privately  offered venture capital
funds (the Ridgewood  Capital  Venture  Partners and Ridgewood  Capital  Venture
Partners II funds);  Ridgewood  Power VI LLC ("Power  VI"),  which is a managing
shareholder of the Growth Fund,  and RPM. 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 57, has also served as Chief  Executive  Officer of
the Trust since its inception in 1991 and as Chief Executive Officer of RPM, the
Other Power Trusts,  and the Ridgewood LLCs 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 the Ridgewood Capital Venture Partners
I,  II,  III and IV  venture  capital  funds  (collectively  "Ridgewood  Venture
Funds").  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.

     Randall  Holmes,  age 56, has served as the President  and Chief  Operating
Officer of the Managing Shareholder,  RPM, the Trust, the Other Power Trusts and
the  Ridgewood  LLCs  since  January 1,  2004.  Prior to that,  he served as the
primary outside counsel to and has represented the Managing  Shareholder and its
affiliates since 1991. Mr. Holmes has over 30 years of acquisition, development,
financing  and  operating  experience  in  the  electric  generation  and  other
industries.  Mr. Holmes  previously  was counsel to Downs Rachlin Martin PLLC in
Vermont ("DRM"), to DeForest & Duer in New York and to Chadbourne & Parke in New
York.  Mr.  Holmes was also  President of the  Pepsi-Cola  Operating  Company of
Chesapeake  and   Indianapolis  and  was  Vice  President  of  Advanced  Medical
Technologies.  He was also a Partner with the New York law firm of Barrett Smith
Schapiro  Simon & Armstrong  where he  specialized  in  financing  transactions,
acquisitions and tax planning.  DRM is one of the primary outside counsel to the
Trust,  Managing  Shareholder and their  affiliates.  Immediately prior to being
appointed President and Chief Operating Officer,  Mr. Holmes was counsel to DRM.
He has maintained a minor consulting  relationship  with DRM in which he may act
as a paid  advisor to DRM on certain  matters that are  unrelated to  Ridgewood.
Such relationship will not require a significant  amount of Mr. Holmes' time and
it is expected that such  relationship  will not adversely  affect his duties as
President and Chief Operating Officer.

     Robert L. Gold,  age 45,  has served as  Executive  Vice  President  of the
Managing Shareholder,  RPM, the Trust, the Other Power Trusts, and the Ridgewood
LLCs  since  their  respective  inceptions,   with  primary  responsibility  for
marketing and acquisitions. He has been President of Ridgewood Capital since its
organization  in 1998. As such, he is President of the Ridgewood  Venture Funds.
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.

     Daniel V.  Gulino,  age 43, has been  Senior  Vice  President  and  General
Counsel of the Managing Shareholder,  RPM, the Trust, Other Power Trusts and the
Ridgewood  LLCs. He began his legal career as an associate  for Pitney,  Hardin,
Kipp & Szuch,  a large New  Jersey  law  firm,  where  his  experience  included
corporate acquisitions and transactions.  Prior to joining Ridgewood, Mr. Gulino
was in-house counsel for several large electric utilities,  including GPU, Inc.,
Constellation  Power Source,  and PPL Resources,  Inc.,  where he specialized in
non-utility   generation   projects,   independent  power  and  power  marketing
transactions.  Mr. Gulino also has experience  with the electric and natural gas
purchasing of industrial  organizations,  having worked as in-house  counsel for
Alumax,  Inc.  (now part of Alcoa)  where he was  responsible  for,  among other
things,  Alumax's electric and natural gas purchasing  program.  Mr. Gulino is a
member of the New Jersey State Bar and Pennsylvania  State Bar. He is a graduate
of Fairleigh Dickinson University and Rutgers University School of Law - Newark.

     Christopher I. Naunton, 39, has been the Vice President and Chief Financial
Officer of the Managing Shareholder, RPM, the Trust, the Other Power Trusts, and
the  Ridgewood  LLCs since April 2000.  From February 1998 to April 2000, he was
Vice President of Finance of an affiliate of the Managing Shareholder.  Prior to
that  time,  he was a  senior  manager  at the  predecessor  accounting  firm of
PricewaterhouseCoopers  LLP. Mr. Naunton's  professional  qualifications include
his certified public accountant qualification in Pennsylvania, membership in the
American   Institute  of  Certified  Public  Accountants  and  the  Pennsylvania
Institute of Certified Public Accountants. He holds a Bachelor of Science degree
in Business Administration from Bucknell University (1986).

     Mary Lou  Olin,  age 51,  has  served  as Vice  President  of the  Managing
Shareholder,  RPM, Ridgewood Capital,  the Trust, the Other Power Trusts and the
Ridgewood LLCs 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.

     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  is subject to  termination  at any time on 60 days' prior
notice by a majority in interest of the  Investors or the Managing  Shareholder.
The  Management  Agreement  is  subject to  amendment  by the  parties  with the
approval of a majority in interest of the Investors.

(d) Executive Officers of the Trust.

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

     The  Corporate  Trustee  of the Trust is  Christiana  Bank & Trust  Company
("Christiana").  Legal title to Trust  Property is now and in the future will be
in the name of the  Trust.  Christiana  is also a  trustee  of the  Other  Power
Trusts. The principal office of Christiana Bank is 1314 King Street, Wilmington,
DE 19801.

     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) RPM.

     As discussed above at Item 1 - Business,  RPM assumed day-to-day management
responsibility for the San Joaquin,  Byron, On- site Cogeneration and Providence
Projects in 1996. Like the Managing Shareholder,  RPM 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 RPM,  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,  RPM charges
the Trust at its cost for these services and for the Trust's allocable amount of
certain  overhead  items.  RPM shares  space and  facilities  with the  Managing
Shareholder  and its  Affiliates.  To the extent  that  common  expenses  can be
reasonably  allocated to RPM, the Managing  Shareholder may, but is not required
to, charge RPM 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 RPM for
the full amount of rent,  utility supplies and office expenses allocable to RPM.
As a result,  both  initially and on an ongoing  basis the Managing  Shareholder
believes  that  RPM'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.  RPM 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 RPM; and  allocations  will be made in a manner  consistent
with generally accepted accounting principles.

     RPM 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.  RPM 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
RPM,  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 RPM;  however,  no  amendment  that
materially  increases the obligations of the Trust or that materially  decreases
the  obligations  of RPM shall  become  effective  until at least 45 days  after
notice of the amendment,  together with the text thereof,  has been given to all
Investors.

     The executive officers of RPM are the same as for the Managing  Shareholder
as set forth above.

(h). Code of Ethics.

     The  Managing  Shareholder  has  adopted a Code of Ethics in March 2004 for
itself, the Trust, Other Power Trusts,  Ridgewood LLCs and affiliates.  The Code
of Ethics is attached hereto as Exhibit 10F.

Item 11.  Executive Compensation.

     The  Managing  Shareholder  compensates  its  officers  without  additional
payments  by the  Trust.  The  Trust  will  reimburse  RPM at cost for  services
provided by RPM's employees.  Information as to the fees payable to the Managing
Shareholder   and  certain   affiliates  is  contained  at  Item  13  -  Certain
Relationships and Related Transactions.

     Christiana,  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 of $84,000 in the offering one
full  Investor  Share.  By virtue of its  purchase  of an  Investor  Share,  the
Managing  Shareholder  is entitled to the same ratable  interest in the Trust as
all other  purchasers of Investor  Shares.  No other  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),  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 a cumulative  amount equal to
14%  per  year  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  made  distributions  in 2003 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:

                 2003         2002        2001         2000         1999
Managing      $356,742     $390,743    $492,430     $592,664     $594,576
Shareholder
Cost
Reimburse-  $6,589,814   $7,893,953  $6,634,733   $7,440,297   $8,920,930
ments
RPM

     The management fee,  payable monthly under the Management  Agreement at the
annual rate of 2.5% of the Trust's prior year 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.  Payroll and other costs of  operation  of the
Trust's Projects are reimbursed to RPM. The  reimbursements to RPM, which do not
exceed its actual costs,  are described at Item 10(g) -- Directors and Executive
Officers of the Registrant -- RPM.

     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.

Item 14.  Principal Accountant Fees and Services

Audit Fees

     The  aggregate  audit fees  billed for  professional  services  rendered by
Perelson Weiner LLP for the audit of the Company's annual  financial  statements
for the year ended December 31, 2003 were approximately  $35,000.  The aggregate
audit fees billed for professional  services rendered by  PricewaterhouseCoopers
LLP for the audit of the Company's  annual  financial  statements  and financial
statements  included  in the  Company's  Quarterly  Reports on Form 10-Q for the
years ended December 31, 2003 and 2002 were  approximately  $16,000 and $41,000,
respectively.


     Tax Fees

     The aggregate fees billed for all tax services  rendered by Perelson Weiner
LLP for the year ended December 31, 2003 were approximately  $38,000. There were
no tax  services  rendered  by  PricewaterhouseCoopers  LLP for the years  ended
December 31, 2003 and 2002. Tax services principally include tax compliance, tax
advice and planning  (including  foreign tax  services,  as well as tax planning
strategies for the preservation of net operating loss carryforwards).

     Audit Related Fees

     None.


     All Other Fees

     None.

PART IV

Item 15.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

The following documents are filed as part of this report:

(a) Financial Statements.

     See the Index to Financial Statements in Item 8 hereof.

(b) Reports on Form 8-K.

     The Registrant filed a Form 8-K with the Commission on January 20, 2004
indicating that the Trust changed its Certifying Accountants by dismissing
PrcewaterhouseCoopers LLP and engaging Perselson Weiner LLP.

(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.

     10.F. Code of Ethics, adopted March 1, 2004.

     99.1. Certifications under Section 906 of the Sarbanes-Oxley Act.

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


<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.


RIDGEWOOD ELECTRIC POWER TRUST III (Registrant)

By:/s/ Robert E. Swanson    Chief Executive Officer       April 14, 2004

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    Chief Executive Officer       April 14, 2004
Robert E. Swanson

By:/s/ Christopher Naunton  Vice President and                April 14, 2004
Christopher Naunton      Chief Financial Officer

RIDGEWOOD RENEWABLE POWER LLC  Managing Shareholder         April 14, 2004
By:/s/ Robert E. Swanson    Chief Executive Officer
Robert E. Swanson


<PAGE>





                   CERTIFICATION PURSUANT TO RULE 13A-14 UNDER
                 THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Robert E. Swanson,  Chief Executive Officer of Ridgewood Electric Power Trust
III ("registrant"), certify that:

1. I have reviewed this annual report on Form 10-K of the registrant;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

           (a) Designed such disclosure controls and procedures, or caused such
           disclosure controls and procedures to be designed under our
           supervision, to ensure that material information relating to the
           Registrant, including its consolidated subsidiaries, is made known to
           us by others within those entities, particularly during the period in
           which the Annual Report is being prepared;

           (b) Evaluated the effectiveness of the Registrant's disclosure
           controls and procedures and presented in the Annual Report our
           conclusions about the effectiveness of the disclosure controls and
           procedures, as of the end of the period covered by the Annual Report
           based on such evaluation; and

           (c) Disclosed in the Annual Report any change in the Registrant's
           internal control over financial reporting that occurred during the
           Registrant's most recent fiscal quarter (the Registrant's fourth
           fiscal quarter in the case of an annual report) that has materially
           affected, or is reasonably likely to materially affect, the
           Registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation of internal control over financial reporting,
to the registrant's auditors and senior management:

           (a) All significant deficiencies and material weaknesses in the
           design or operation of internal control over financial reporting
           which are reasonably likely to adversely affect the Registrant's
           ability to record, process, summarize and report financial
           information; and

           (b) Any fraud, whether or not material, that involves management or
           other employees who have a significant role in the Registrant's
           internal control over financial reporting.



Date: April 14, 2004
/s/   Robert E. Swanson
------------------------
Robert E. Swanson
Chief Executive Officer

<PAGE>




                   CERTIFICATION PURSUANT TO RULE 13A-14 UNDER
                 THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Christopher I. Naunton,  Chief Financial Officer of Ridgewood  Electric Power
Trust III ("registrant"), certify that:

1. I have reviewed this annual report on Form 10-K of the registrant;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

           (a) Designed such disclosure controls and procedures, or caused such
           disclosure controls and procedures to be designed under our
           supervision, to ensure that material information relating to the
           Registrant, including its consolidated subsidiaries, is made known to
           us by others within those entities, particularly during the period in
           which the Annual Report is being prepared;

           (b) Evaluated the effectiveness of the Registrant's disclosure
           controls and procedures and presented in the Annual Report our
           conclusions about the effectiveness of the disclosure controls and
           procedures, as of the end of the period covered by the Annual Report
           based on such evaluation; and

           (c) Disclosed in the Annual Report any change in the Registrant's
           internal control over financial reporting that occurred during the
           Registrant's most recent fiscal quarter (the Registrant's fourth
           fiscal quarter in the case of an annual report) that has materially
           affected, or is reasonably likely to materially affect, the
           Registrant's internal control over financial reporting; and


5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and senior management:

            (a) All significant deficiencies and material weaknesses in the
            design or operation of internal control over financial reporting
            which are reasonably likely to adversely affect the Registrant's
            ability to record, process, summarize and report financial
            information; and

            (b) Any fraud, whether or not material, that involves management or
            other employees who have a significant role in the Registrant's
            internal control over financial reporting.



Date: April 14, 2004
/s/   Christopher I. Naunton
-----------------------------
Christopher I. Naunton
Chief Financial Officer