28




                       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 0-24240

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

               Delaware                         22-3105824
(State or Other Jurisdiction       (I.R.S. Employer Identification No.)
of Incorporation or Organization)

1314 King Street
Wilmington, DE                                            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 $10,550,000  and the number of shares of beneficial  interest
outstanding at March 30, 2004 was 105.5.

Exhibit index is at page 30.


<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 I (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 are changes in political and economic conditions,  federal or
state  regulatory  structures,   government  taxation,  spending  and  budgetary
policies,  government  mandates,  demand for electricity and thermal energy, the
ability of customers to pay for energy  received,  supplies 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 May 9, 1994. It was
organized to acquire all of the assets and to carry on the business of Ridgewood
Energy Electric Power, L.P. (the "Partnership").  The Partnership was a Delaware
limited  partnership,  which was organized in March 1991 to  participate  in the
development,   construction  and  operation  of  independent   power  generating
facilities  ("Projects").  The  Partnership  raised  $10.5  million  in a single
private  offering  conducted in late 1991 and early 1992.  Substantially  all of
those  funds were  applied  prior to 1995 to the  purchase of  interests  in the
Projects  described  below,  to the  funding  of  business  ventures  that  were
unsuccessful and to paying the fees and expenses of the  Partnership's  offering
and the  Partnership.  On June 15, 1994, with the approval of the partners,  the
Partnership was combined into the Trust, which acquired all of the Partnership's
assets and which  became  liable for all of the  Partnership's  obligations.  In
exchange  for  their  interests  in  the  Partnership,   the  investors  in  the
Partnership  received an equivalent number of Investor Shares (as defined below)
in the Trust. The Partnership was dissolved.

     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 May 26, 1994 the Trust  notified the  Securities  and Exchange  Commission of
that election and  registered  its shares of beneficial  interest (the "Investor
Shares") under the Securities Exchange Act of 1934, as amended (the "1934 Act").
On July 15, 1994 the election and registration  became effective.  Subsequently,
on November  5, 2001,  the Trust  issued to the owners of  Investor  Shares (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")  required  due to  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. The Managing Shareholder has
complete  control  of the  day-to-day  operation  of  the  Trust.  The  Managing
Shareholder is not regularly  elected by the Investors.  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.

     In  addition,   the  Trust  is  affiliated   with  the   following   trusts
(collectively  "Other Power Trusts"),  which have been organized by the Managing
Shareholder:

o Ridgewood Electric Power Trust II ("Power II");
o Ridgewood Electric Power Trust III ("Power III");
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 The Ridgewood Power B Fund/Providence Expansion (the "B Fund").

     The Trust also is affiliated with the following  Delaware limited liability
companies  ("Ridgewood  LLCs"),  which  have  been  organized  by  the  Managing
Shareholder:

o Ridgewood Renewable PowerBank LLC
o Ridgewood Renewable PowerBank II LLC
o Ridgewood Renewable PowerBank III LLC

With respect to the Ridgewood LLCs, the Managing Shareholder acts as the LLC's
Manager.

(b) Financial Information about Industry Segments.

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

(c) Narrative Description of Business.

     (1)  General Description.

     The Trust was formed to participate in the  development,  construction  and
operation of  independent  electric power  projects.  Many of these projects are
qualifying facilities or "QFs." Historically, producers of electric power in the
United States consisted of regulated  utilities serving end-use retail customers
and certain  industrial  users that  produced  electricity  to satisfy their own
needs. The independent power industry in the United States was created by, among
other things,  the Public  Utility  Regulatory  Policies Act of 1978, as amended
("PURPA").  Generally,  PURPA 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.
PURPA  requires  that the  price  paid by  electric  utilities  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  formula  approved by state
regulatory commissions.

     Although  one of the  benefits  of PURPA is the  requirement  imposed  upon
electric utilities to purchase QF electric power, there are nonetheless many QFs
that do not have power contracts with electric  utilities  because,  among other
reasons,  the power contract has expired or was "bought out" and current avoided
cost is too low for the QF to sustain operations, the lack of a long-term market
for the power  produced by QFs,  or the  electric  utilities'  belief that state
implementation  of PURPA no longer requires such purchase of QF power.  Southern
California  Edison  Company  ("SCE"),  to whom the Brea Project  sells  electric
energy,  has taken such a position.  SCE was being legally challenged by several
QFs but the matter was not  resolved  and has  generally  been  subsumed  in the
general electric energy procurement  proceeding currently being conducted by the
California Public Utilities Commission ("CPUC").

         (2) Projects.

     (i) Brea  Project.  The  Trust  owns and  operates  a  5-megawatt  capacity
electric  generating facility fueled by methane and other burnable gases created
by the  decomposition  of garbage  in a landfill  owned by the County of Orange,
California (the "Brea Project").  Ridgewood Power  Management,  LLC ("RPM"),  an
affiliate  of  the  Trust's  Managing  Shareholder,  operates  and  manages  the
day-to-day  activities of the Brea  Project.  RPM is reimbursed by the Trust for
its actual costs incurred and allocable  overhead  expenses but is not otherwise
compensated.

     The Brea  Project  does not include the  landfill  gas  collection  system.
Currently,  GSF Energy LLC ("GSF")  collects and sells  landfill gas to the Brea
Project  pursuant  to an Amended and  Restated  Landfill  Gas Sale and  Purchase
Agreement  ("Amended Gas  Agreement").  GSF sells and collects such landfill gas
pursuant  to a gas lease  agreement  with the County of Orange.  Pursuant to the
Amended Gas Agreement,  the Trust  contracted  with GSF for the rights to all of
the landfill gas  generated at the Orange County  landfill  until the year 2018.
Because the Amended Gas  Agreement  is between GSF and the Brea  Project and not
with Orange County, if GSF were to cease operations at the landfill or if Orange
County  were to  terminate  the gas lease  agreement  with GSF,  it is not clear
whether  Orange  County is bound to recognize  the Trusts rights to the landfill
gas. The Trust is contemplating  direct discussions with Orange County regarding
this and other matters.  Under the Amended Gas  Agreement,  the Trust pays GSF a
fixed amount of $60,000 per month and a 9.5% royalty from the revenues generated
by the Brea Project.  The $60,000 fixed payment  escalates at the Consumer Price
Index  ("CPI")  and  expires  in 2005,  at which time the Trust will pay GSF the
greater of a 19%  royalty  from the  revenues  of the Brea  Project or  $720,000
annually.  The Amended Gas  Agreement  also covered gas supplies to and revenues
from the Olinda Project.  However as further  detailed below, the Olinda Project
has been relocated by the Trust to Rhode Island.

     The Brea Project is a QF. Electricity  generated by the Brea Project,  over
and above its own  requirements,  is sold to SCE under a  long-term  power sales
contract (a "Power Contract").  The energy price under the Power Contract is the
higher of 5.8 cents per  kilowatt-hour or SCE's avoided cost, which is an amount
determined  by a contract  formula  set forth in the Power  Contract.  The Power
Contract permits either party to terminate it no earlier than the end of 2004 on
5 years' advance notice.  On March 23, 2000, SCE provided such written notice to
the Brea Project  notifying that it was electing to terminate the Power Contract
as of March 23, 2005. After such termination,  the Brea Project, if it continues
operating in light of certain environmental regulations (See Below), either will
have to enter into another long-term power contract,  if available,  or sell its
electric output in the competitive electric power market.

     In addition to the difficulties associated with procuring a long-term power
contract,  the Brea  Project  is  faced  with the  possible  termination  of its
operations  as of January 1, 2005 as a result of its  inability  to comply  with
certain  environmental  regulations.   The  Brea  Project  operates  within  the
jurisdiction of the South Coast Air Quality Management District ("South Coast"),
the air pollution  control  agency for Orange  County and major  portions of Los
Angeles, San Bernardino and Riverside counties in Southern California. The South
Coast   promulgated  Rule  1110-2  regarding  air  emissions  from  gaseous  and
liquid-fueled  stationary engines which generally imposes very low air emissions
levels on such engines, which include the generating engines used by and located
at the Brea Project (the  "Rule").  According to the Rule,  existing,  and to be
installed,  electric  generating  engines  must be in  compliance  with  the new
emissions  levels by  January  1,  2005 or cease  operations  or, if  operations
continue,  risk severe  penalties  from South  Coast.  The  electric  generating
engines used by the Brea Project cannot, in their current configuration,  comply
with the Rule.  RPM, on behalf of the Brea Project,  informally  requested  from
South Coast a temporary exemption of the Rule's application to Brea. South Coast
rejected  that request.  Brea is  considering  formally  seeking a variance from
South Coast of the Rule's applicability.  However, notwithstanding such efforts,
the Brea  Project  essentially  has three  options  with respect to the Rule (i)
cease  operations as of January 1, 2005, (ii) upgrade and/or repair the existing
engines,  if  possible,  to comply with the Rule's  emissions  levels,  or (iii)
repower  the Brea  Project  with  new  engines  capable  of  complying  with the
emissions  levels.  The Trust is seeking a workable  alternative  to ceasing its
operations  at the Brea  Project  and,  as a result,  RPM, on behalf of the Brea
Project, has been investigating  whether the existing engines can be upgraded or
repaired to comply with the Rule's air emissions  levels.  To date,  RPM has not
been able to find any such  solution that is or can be  demonstrated  to be both
successful and economically feasible.

     In addition,  RPM has been  investigating the feasibility of repowering the
Brea Project with new engines and related equipment.  A conservative estimate of
the capital costs needed to complete such  repowering are between  $3,000,000 to
$4,000,000. The problem, however, is that such capital will be difficult, if not
impossible,  to acquire without the Brea Project first securing an appropriately
priced (in light of operating costs, debt service and profit margins)  long-term
electric  power  contract to replace the SCE Power  Contract.  The  prospects of
securing  such  a  long-term  power  contract  at  reasonable   prices  are  not
encouraging. The primary reason is that the electric energy market in California
is  generally  in a state of flux in that the  CPUC  has not yet  completed  its
procurement  proceeding or has  determined how such  procurement  relates to the
procurement of renewable energy.

     Although  California  has  passed  and is  currently  adopting  rules for a
renewable  portfolio standard ("RPS"),  RPM does not believe that the California
RPS will create any significant  market for renewable energy credits ("RECs") or
provide  additional  revenues  from  RECs to  supplement  renewable  generator's
revenues.  Nevertheless, RPM, on behalf of the Brea Project, is participating in
the RPS  proceeding in  California  in an attempt to influence  policy makers in
California  to revise  the RPS.  In  addition  to the RPS  efforts,  RPM is also
attempting  to  influence  legislation  in  California  that will  increase  the
tipping-fee paid by waste haulers that dump waste at California  landfills.  The
intent is to use the tipping  fee  increase  to  subsidize  the cost of electric
generation  from  landfill  gas.  The basic  premise  behind  RPM's  efforts  in
California is to obtain through  legislation  (e.g.,  tipping fee) or regulation
(e.g.,  RPS) subsidies or  supplemental  revenue such that the long-term  all-in
revenue from electric sales,  subsidies (if any) and REC sales  cumulatively are
sufficient  to procure  and  service  the  capital  required to repower the Brea
Project,  as well as cover all operating costs and provide a reasonable  return.
See Section 4, Market Trends for more information on the California RPS.

     Given the current  prices for long-term  electric  power,  the Brea Project
must not only procure an acceptable  long-term  power  contract but also receive
either the tipping fee subsidy or the RPS benefit in order to either upgrade the
engines or repower the Brea  Project.  As of the date  hereof,  the Trust cannot
guarantee or predict  whether an  acceptable  long-term  power  contract will be
procured,  or whether the tipping fee legislation  will be enacted as described,
or whether the California RPS will be successful.  As a result,  the possibility
exists that the Trust will have to  terminate  operations  at the Brea  Project.
Such  termination  will likely lead to, among other  things,  the loss of Brea's
rights to the landfill gas generated at the Orange County landfill.

     (ii)  Olinda  Project.  In early  2001,  the Trust  decided  to expand  its
operations  at the  Orange  County  Landfill  by  developing  and  installing  a
2.5-megawatt  electric  generating  facility  fueled by methane gas (the "Olinda
Project").  The total cost of the Olinda Project was  approximately  $3,000,000,
half of which has been  financed.  The Olinda  Project was designed and built by
Stewart & Stevenson ("S&S"), an engineering and construction firm, for a cost of
approximately $2,500,000.  The Olinda Project was originally intended to receive
its landfill gas from GSF pursuant to the Amended Gas Agreement.

     The Olinda Project was completed  substantially  behind the schedule agreed
to by S&S and  Ridgewood  Olinda,  LLC,  the  owner of the  Olinda  Project.  In
addition,  within  several months of commercial  operation,  one of the electric
generating  machines  installed  by  S&S  experienced  a  catastrophic  failure.
Although S&S provided a temporary  replacement  engine to Ridgewood Olinda,  the
Olinda  Project  was  subsequently  shut-down  in  October of 2002 by the Orange
County  electrical  inspector due to S&S's failure to install proper  electrical
switchgear  or obtain a permit for the  switchgear  it did  install.  The engine
failure and switchgear  problems  highlighted  significant other failures of S&S
including,  but not limited to, S&S's failure to obtain final building  permits,
failure to deliver  operating  manuals or provide  training,  and numerous other
problems or issues that have  developed.  The parties have settled  these claims
without  litigation  and as part of such  settlement,  S&S  agreed to repair the
damaged engine and provide other services with respect to the relocation of both
Olinda engines to Rhode Island. (See below)

     The Olinda Project began commercial operation on or about March of 2002 and
sold its electric output in California to the California Power Authority ("CPA")
pursuant to a short-term  (ninety-day)  power sales  contract.  Such  short-term
contract was extended by the CPA through  December 31, 2002,  along with several
other contracts with renewable (biomass) generators.  Prior to the expiration of
such  extension  the CPA  offered  additional  six-month  extensions  to several
biomass  generators but did not offer a similar extension to the Olinda Project.
Despite  significant  efforts,  the Olinda Project began the year 2003 without a
long-term  power  contract  and the prospect for  obtaining  such an  acceptable
contract  were remote  given the  electric  energy  market in  California.  See,
Section 4, Market Trends.

     As a result of the poor long-term  possibilities in California in 2003, the
Trust  relocated the electric  generating  equipment of the Olinda  Project from
California  to Rhode  Island,  to the site of a new landfill  gas project  being
developed  by the  Trust's  affiliate,  the B Fund.  Olinda  and the B Fund have
entered into a lease agreement in which Olinda will receive from the B Fund as a
lease payment  approximately 15% of the net operating cash flow generated at the
B Fund's landfill gas-fired facility.

     (iii)  Stillwater  Project.  In October  1991,  the Trust  acquired a 32.5%
equity interest with respect to a 3.5 megawatt (nominal capacity)  hydroelectric
facility which was then under construction on the Hudson River in the village of
Stillwater, New York (approximately 30 miles northeast of Albany) at the site of
a pre-existing  800 foot wide masonry dam structure (the  "Stillwater  Project")
for a purchase price of $750,000.  The Stillwater  Project commenced  commercial
operation in May 1993.

     The Trust and  affiliates of the general  contractor  and affiliates of the
equipment  supplier formed  Stillwater Hydro Partners,  L.P. ("SHP") to continue
development  of  the  Stillwater  Project.  The  Trust's  total  investment  was
$1,162,000. Debt financing for the Project was provided by the CIT Group/Capital
Equipment Financing Inc. ("CIT"). The CIT financing is a fixed rate 15-year term
loan in the principal amount of approximately $8,995,000, with the final payment
due in 2008. In addition to the fixed interest payments, CIT is also entitled to
receive,  as  additional  interest,  22.5%  of the  available  cash  flow of the
Stillwater Project. The term loan is payable only by SHP, and is non-recourse to
the Trust.

     The Trust now owns a fixed preferred  partnership  interest entitling it to
aggregate  distributions  of $1 million,  plus a compound  annual  return of 12%
thereon until paid in full. Over the nine-year schedule of annual payments,  the
Trust  was  to  receive  total  payments,   including  the  annual  return,   of
approximately  $1,720,000.  SHP is required to apply  substantially all of SHP's
available  cash flow after funding of debt service (up to a maximum  amount each
year) to satisfy the payment  obligation to the Trust, with any shortfalls to be
carried forward with interest into subsequent years.

     The  Stillwater  Project's  revenues are dependent upon water levels in the
Hudson River, which have fluctuated significantly during the last several years.
During low flow  periods,  generation  is  curtailed.  For a variety of reasons,
power  output  during high flow  periods has not reached  projected  levels.  In
addition,  even if water  flow  levels  are  optimal,  the  Project is unable to
generate the full projected output of 3.5 megawatts of electricity  because of a
design defect. As a result, the Trust has only received a single partial payment
of $126,000 in 1994 and does not expect to receive any  additional  payments for
several  years.  Electricity  generated  by the  Stillwater  Project  is sold to
Niagara Mohawk Power Corporation under a long-term Power Contract, which expires
in 2028.

     (iv) Mobile Power Units.  Effective  August 1999,  the Trust  purchased two
mobile electric generating units manufactured by Caterpillar Inc. (the "Units").
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 I, 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 manages the Units, which are
rented at fixed  rates.  Hawthorne  receives  20% of the net rental  revenues to
compensate  it for  marketing  and  managing  the Units.  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 $44,143 and $209,251,  respectively,
to reflect the units fair market value.  In the third quarter of 2003, the Trust
decided to make its mobile power modules available for sale.

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

         (3) Project Management and Operation

     The Managing  Shareholder has organized RPM to provide operating management
for the Projects, and has assigned day-to-day management of the Brea Project and
Olinda Project to RPM. These services are charged to the Projects at RPM's cost.
See Item 10 - Directors and Executive  Officers of the  Registrant and Item 13 -
Certain Relationships and Related Transactions for further information regarding
the Operation Agreement and RPM and for the cost reimbursements received by RPM.
The Stillwater  Project is managed by its remaining equity  partners.  Hawthorne
manages the Mobile Power Units.

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

                                  Calendar Year
                                    2003      2002      2001
Southern California Edison          99.8%     97.3%     94.6%


         (4) Market Trends.

     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 of "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.

     The California RPS generally  requires that retail electric  sellers in the
state increase the renewable  generation in their electric  supply  portfolio by
one (1%) percent per year,  provided certain conditions are met, over a baseline
level  of  renewable  generation  to be  determined  by  the  California  Public
Utilities  Commission  ("CPUC").  According  to  California's  RPS,  the  annual
incremental  renewable  generation   procurement   requirement  continues  until
renewable  generation  comprises twenty (20%) percent of the aggregate  electric
supply to retail  users in the state.  Such 20% target must be achieved no later
than December 31, 2017.

     However,  California  adopted and is  implementing an RPS that is different
than most other state RPS programs. According to the California RPS legislation,
electric  utility  purchases  of  renewable  energy  (or  RECs)  is  part of the
utilities annual procurement proceedings. Basically, the REC was not "separated"
from the purchase of the renewable  energy and, as a result,  the procurement of
renewable energy has been  incorporated  into the electric  utilities  long-term
power procurement  proceedings.  In addition,  the RPS legislation in California
requires  the  utilities  to pay no more for  renewable  energy  than a  "market
referent price"  determined by the CPUC and which is supposed to approximate the
cost of energy from a new combined cycle natural  gas-fired  electric  facility.
Any "above  market  costs" of the  renewable  energy  are to be funded  from the
"public goods charge",  which is a limited fund  administered  by the California
Energy  Commission  ("CEC").  As  a  result  of  this  general  framework,   the
implementation  of the RPS in California is extremely  complicated  and involves
many divisive issues that are not part of any other state RPS program including,
without limitation, determining renewable generation market price referents, the
utilities  least cost,  best fit strategy with respect to renewable  generation,
establishing initial renewable generation baselines, and reviewing and approving
the investor-owned utilities ("IOU's") renewable procurement plans.

     According  to the  RPS  legislation,  the  CPUC  and  the  CEC  are to work
collaboratively to make necessary  findings,  determine  appropriate  procedures
and,  ultimately,   determine  the  methodology  for  renewable  procurement  by
California's IOU's. The RPS legislation  required that such collaborative effort
be  completed  and  implemented  by the end of  2003.  Both the CPUC and CEC are
significantly  behind  schedule and it is  questionable  whether the RPS will be
implemented in 2004.

     RPM, as agent for the Brea Project,  is participating in these proceedings.
However, as a result of such  participation,  RPM has concluded that in the near
term  (next  two  years)  the  RPS  program  in  California  probably  will  not
substantially assist renewable projects obtain profitable power contracts nor is
it  likely  to  facilitate  the sale of any  RECs  generated  by such  renewable
facilities. The reasons for such conclusion include, as mentioned, the fact that
(i) California  IOUs pay no more for renewable  power than they would  otherwise
pay for non-renewable  power, (ii) any excess above a fossil-fueled  "benchmark"
price be obtained  from the CEC through the "public goods  charge",  (iii) there
may not be sufficient  "public  goods charge" funds  available for the predicted
renewable supply, and (iv) the RPS legislation does not necessarily facilitate a
RPS trading program such that a renewable generator could sell its energy to one
customer and  renewable  attributes  to another.  As a result of these and other
problems in California,  the Trust, as mentioned  earlier,  relocated the Olinda
Project's electric generating equipment to Providence,  Rhode Island, to be part
of a project  being  developed  by its  affiliate,  the B Fund.  The  market for
renewable  power  in  New  England  is  significantly  more  favorable  than  in
California.

     In addition  to  developments  in  California,  the  general  trends in the
electric  power  industry  have  continued to reflect an attitude of caution and
restraint.  Throughout  the United  States,  memories of the  California  energy
crises,  Enron  Corp.'s  bankruptcy,   proceedings  before  the  Federal  Energy
Regulatory Commission ("FERC") regarding certain questionable practices of other
energy  producers and  marketers,  as well as the generally  poor U.S. and world
economy,  have led many to call for a more  regulated  electric  industry,  with
strict reporting  requirements  and cost of service  regulation.  However,  many
legislators, regulators and market participants have not disavowed deregulation.

         (5)  Competition

     The Brea and Stillwater  Projects,  as described  above,  are not currently
subject to competition  because those Projects have entered into long-term Power
Contracts  to sell their  output at  specified  prices,  although the Brea Power
Contract expires as of March 23, 2005, assuming that the Brea Project can comply
with the South Coast's Rule. The Brea and Stillwater Projects, likewise, will be
subject to competition to market its electricity  output once the Power Contract
expires or is  terminated.  However,  as further  detailed in Item 1(c)(4),  the
California  RPS  Standard,  if  implemented  in a manner that is  beneficial  to
renewable  generation,  may very well  permit  the Brea  Project  to  repower to
satisfy the Rule and market and sell its  renewable  power at  favorable  rates,
although  such  outcome  can not be assured due to certain  other  uncertainties
including, but not limited to, the South Coast Rule. The process of deregulation
in New York, where the Stillwater Project is located,  is still uncertain and it
is difficult to estimate the level of market  competition  that it would face in
any such event.  The Olinda Project is receiving  lease payment from the B Fund.
Although the B Fund has not yet  procured a long-term  contract for its electric
power and is selling  currently to the New England ISO and  receiving  the "spot
price" for its power, the price for such power is approximately $.04/kwh and the
sale of the REC is New England is also approximately $.04/kwh. These two revenue
stream  combine  for a  $.08/kwh,  which is an  economically  attractive  price,
although  there is no  guarantee  that these  prices can be sustained or that an
acceptable long-term power contract can be procured.

     The Units compete against  numerous other fleets of mobile power generation
equipment  on a  regional  and  international  level.  Due  to the  increase  in
competition  and  production  of  newer  efficient  mobile  models,   the  Trust
experienced  a  decrease  in rental  revenue  for the  current  year,  thus,  as
described above and in the Notes, prompted a writedown of the Trust's investment
in the Units.

         6. Regulatory Matters.

     The 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.  PURPA,  and the  adoption of  regulations  thereunder  by FERC,
provided incentives for the development of QFs meeting certain criteria. QFs are
generally  exempt from the provisions of the Public Utility  Holding Company Act
of 1935,  as amended,  the Federal  Power Act, as  amended,  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 QF  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 Energy Act has resulted
and may continue to result in increased competition in the sale of electricity.

     (C) The  Federal  Power Act.  The FPA  grants  FERC  exclusive  rate-making
jurisdiction over wholesale sales of electricity in interstate commerce.  Again,
this will not affect the Trust's  Projects  unless they were to attempt sales to
other customers.

     (D) State  Regulation.  The  Trust's  Projects  are not subject to material
state economic  regulation except for requirements in California and New York to
supply the purchasing  utility with  information to confirm  compliance  with QF
fuel use and  efficiency  requirements  and to make the Projects  available  for
audit and  inspection  to confirm QF  compliance.  The Trust  believes  that its
Projects  meet QF  standards.  States also have  authority  to regulate  certain
environmental, health and siting aspects of QFs.

     (E) Mobile Power Units. The Mobile Power Units, as temporary  on-site units
operated by the electricity consumer,  are not subject to economic regulation in
California or most other jurisdictions.

         (ii) Environmental Regulation.

     The  operation  of  Independent  Power  Projects  is subject  to  extensive
federal,  state  and  local  environmental  laws and  regulations.  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 also include  wetlands  preservation,  fisheries  protection (at the
Stillwater  Project) and noise  regulation.  These laws and  regulations in many
cases require a lengthy and complex  process of renewing or obtaining  licenses,
permits  and  approvals  from  federal,  state  and  local  agencies.  Obtaining
necessary  approvals can be time-consuming and difficult.  Each Project requires
technology   and   facilities   that  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 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 all applicable air quality rules.

     The  Managing   Shareholder   expects  that   environmental  and  land  use
regulations  may become more stringent or, at a minimum,  remain  constant.  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 co-owners of the Stillwater Project and as to all Projects
on qualified environmental  consultants and environmental counsel retained by it
to assist in evaluating the status of Projects regarding such matters.

         (iii) Potential Legislation and Regulation.

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

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

  The Trust has no foreign operations.

         (e)     Employees.

     The  employees of the Brea  Project and the Olinda  Project are employed by
RPM, the Trust is administered  by the Managing  Shareholder and accordingly the
Trust has no employees.  The persons described below at Item 10 -- Directors and
Executive  Officers of the Registrant  serve as executive  officers of the Trust
and have the duties and  powers  usually  applicable  to similar  officers  of a
Delaware corporation in carrying out the Trust business.

Item 2.  Properties.

     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.  All of the Projects  are  described in further  detail at Item
1(c)(2).

                                   Est.Amount    Approximate
                                    of Land        Square
Project       Location      Land    (acreage)      Footage

Brea          Brea, CA     Leased       2           6,000

Still       Stillwater,    Leased      .75           N/A
 Water          NY           and
                          Licensed


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 has 105.5  Investor  Shares.  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  they are held by  persons  in a control
relationship  with the Trust.  Investors  wishing to  transfer  Investor  Shares
should also consider the  applicability  of state  securities laws. The Investor
Shares have not been  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 234  holders  of  record 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,    December 31,
                                         2003            2002
Total distributions to Investors      $1,690,497     $1,052,499
Distributions per Investor Share          16,024          9,976
Total distributions to
 Managing Shareholder                     17,076         10,631

     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  debt  services  reserves.  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 than accounting income to Investors.

Item 6.  Selected Financial Data (all amounts in $).

     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        $3,211,055 $3,352,189 $4,379,154 $3,259,562 $3,114,503
Net income(loss)(1,409,416)   101,827  1,454,876  1,487,998    799,717
                    (A)                                            (B)
Net assets
(shareholders'
  equity)        3,694,937  6,811,926  7,773,229  6,318,353  6,323,075
Investments in
 Plant and
 Equipment (net
 of depreciation)1,513,422  4,671,615  4,922,297  2,688,320  2,920,044
Investment
 in Power
 Contract(net
 of amortization)  157,694    473,091   788,489  1,103,887  1,419,284
Total assets     4,937,723  8,291,849 9,386,999  6,507,720  6,543,322
Long-term
 obligations       652,607    952,607 1,227,674        --         --
Per Share:
Revenues            30,436     31,774    41,509     30,896     29,521
Net income(loss)   (13,359)       965    13,790     14,104      7,580
                      (A)                                         (B)
Net asset value     35,023     64,568    73,679     59,890     59,934
Distributions
 to Investors       16,024      9,976       --      14,008     12,300

(A) Includes writedown of investment of $1,722,380 ($16,326 per Investor Share).
(B) Includes writedown of investment of $422,019 ($4,000 per Investor Share).

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

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 Brea and  Stillwater  Projects are QFs under PURPA and  currently  sell
their electric output to utilities  under long-term Power Contracts  expiring in
2005 and  2028,  respectively.  During  the  term of the  Power  Contracts,  the
utilities may or may not attempt to buy out the contracts  prior to  expiration.
At the end of the Power 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
Trust's Projects to operate profitably.

     All available cash flow from the  Stillwater  Project is being used to meet
debt  service  requirements.  Distributions  to  the  Trust  will  resume  after
repayment of the bonds. Assuming normal water flows and no operational failures,
the bonds are expected to be repaid in 2008.

     Additional  trends affecting the independent  power industry  generally are
described at Item 1(c)(4).

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 5 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  2%  to  $3,203,000  in  2003  from
$3,263,000 in 2002,  primarily due to the decrease in power  generation  revenue
from  the  Olinda  Project.  The  Olinda  project  provided  $372,000  in  power
generation  revenue  in 2002,  but did not  operate  in 2003  due to  mechanical
problems and the lack of a power  contract.  Power  generation  revenue from the
Brea project  increased by $312,000 in the current year. The increase in revenue
from the Brea project is attributable to the project operating more consistently
in 2003 as compared to 2002, when the project  experienced a temporary shut down
due to mechanical  problems.  Rental revenue from the Trust's Caterpillar rental
modules  decreased by $82,000 or 92%, to $8,000 in 2003.  The decrease in rental
revenue is due to the increase in competition  and production of newer efficient
models.

     Gross profit,  which  represents  total revenues  reduced by cost of sales,
increased  from $780,000 in 2002, to $944,000 in 2003. The increase is primarily
the result of the Brea project experiencing greater repair and maintenance costs
in 2002.

     General and administrative expenses increased $181,000, or 72%, to $433,000
in 2003 from  $252,000 in 2002.  The  increase is due to the  professional  fees
incurred  by the  Trust on behalf of the Brea  project.  The Trust had  retained
professional  firms  to  assist  it in the  researching  and  monitoring  of the
California  legislation on renewable energy, with the intent of the Brea project
qualifying as a renewable energy  generation  facility and becoming  eligible to
receive additional revenue for the sale of renewable energy attributes.

     During 2002, the Trust  recorded  $72,000 of project  development  expenses
relating to projects in California that it ultimately decided not to develop.

     In 2003  the  Trust  recorded  a  write  down in its  investment  in  power
generation projects of $1,772,000, of which, $1,728,000 is the write down of the
Olinda project,  which removed its engines and transferred them to the Ridgewood
Providence expansion. The remaining $44,000 is related to the Caterpillar rental
modules, for which in 2002, the Trust recorded a write down of $209,000.

     The management fee paid to the Managing  Shareholder  decreased $10,000, or
13%, to $68,000 in 2003 from $78,000 in 2002,  which  reflects the Trust's lower
net asset balance.

     Income (loss) from operations  decreased $1,499,000 to a loss of $1,330,000
in 2003 from income of $169,000 in 2002. The decrease in income is primarily the
result of the  increase  in the write down in  investments  in power  generation
projects in 2003,  partially  offset by the  decrease in repair and  maintenance
costs.

     Other income (expense),  net, increased $13,000, or 19%, to $80,000 in 2003
from $67,000 in 2002. Interest income decreased $24,000 in 2003 due to the lower
cash balances and lower interest rates.  Interest expense decreased $23,000 as a
result of the lower  principal  balance  on the  Olinda  project  financing.  In
addition,  the Trust recorded equity income from its investment in Stillwater of
$37,000 in both 2003 and 2002.

     Net income  (loss)  decreased  $1,511,000,  to a loss of $1,409,000 in 2003
from income of $102,000 in 2002.  The  decrease in net income is a result of the
write down in investment in power generation  projects,  partially offset by the
decrease in repair and maintenance costs.

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

     Power  generation   revenue  decreased  21%  to  $3,263,000  in  2002  from
$4,141,000 in 2001,  primarily due to the decrease in power  generation  revenue
from the Brea Project.  Power generation revenue from the Brea Project decreased
by  $1,250,000,  while the Olinda  Project  provided  an increase of $372,000 in
2002.  The  decrease in revenue  from the Brea  project is  attributable  to the
higher  energy prices  charged  during the first half of 2001 as a result of the
California  energy crisis.  Rental revenue from the Trust's  Caterpillar  rental
modules decreased by $150,000 or 63%, to $89,000 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 from $2,450,000 in 2001, to $780,000 in 2002. The decrease is a result
of the higher energy prices charged during the California energy crisis in 2001,
as well as the Brea project experiencing greater repair and maintenance costs in
2002.

     General and administrative  expenses decreased $20,000,  or 7%, to $252,000
in 2002 from $272,000 in 2001. The decrease  primarily  reflects the legal costs
associated with the Brea Project's dispute with SCE in 2001.

     The $480,000 of bad debt expense in 2001 is associated with the sale of the
Brea Project's SCE receivables to AMROC.

     During 2002, the Trust  recorded  $72,000 of project  development  expenses
relating to projects in California  that it  ultimately  decided not to develop.
Also during 2002,  the Trust  recorded a write down of $209,000  relating to the
Caterpillar rental modules.

     The management fee paid to the Managing  Shareholder  decreased  $9,000, or
10%, to $78,000 in 2002 from $87,000 in 2001,  which  reflects the Trust's lower
net asset balance.

     Income from operations  decreased  $1,441,000,  or 90%, to $169,000 in 2002
from $1,610,000 in 2001 as a result of the decrease in revenues and the increase
in repair and maintenance costs.

     Other income (expense),  net, decreased $88,000, or 57%, to $67,000 in 2002
from $155,000 in 2001.  The decrease in expense is a result of costs incurred in
issuing the "Notice of Solicitation of Consents" in 2001, offset by the increase
in interest expense paid in 2002 on the Olinda Project long-term  financing.  In
addition, the Trust recorded an equity loss from its investment in Stillwater of
$29,000 in 2001 compared to income of $37,000 in 2002 reflecting higher revenues
due to the increase in river flows.  Interest income  decreased  $46,000 in 2002
due to the lower cash balances and lower interest rates.

     Net  income  decreased  $1,353,000,  or  93%,  to  $102,000  in  2002  from
$1,455,000  in 2001 as a result of the  decrease in revenues and the increase in
repair and maintenance costs.

Liquidity and Capital Resources

     In 2003 and 2002, the Trust's operating activities generated $1,021,000 and
$714,000  of cash,  respectively.  The  increase  in cash  flow  from  operating
activities  is  primarily  due to the increase in gross profit and the timing of
receipt/payment of assets and liabilities.

     Cash  used in  investing  activities  in 2003  and 2002  was  $192,000  and
$257,000,  respectively.  Cash used in investing activities in 2003 and 2002 was
for capital expenditures relating to the Olinda Project.

     Cash  used  in  financing  activities  in 2003  of  $1,983,000  represented
distributions  to  shareholders of $1,708,000 and payments of $275,000 to reduce
long-term debt on the Olinda Project.  Cash used in financing activities in 2002
of $1,315,000  represented  distributions  to  shareholders  of  $1,063,000  and
payments of $252,000 to reduce long-term debt on the Olinda Project.

     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 Trust's
significant  long-term  obligation  is limited to  $953,000  of  long-term  debt
related to the  Olinda  Project,  which is  guaranteed  by the Trust.  Scheduled
principal payments of the long-term debt are as follows:

2004            $300,000
2005             327,000
2006             326,000


     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,
liens and provide guarantees.

     The Brea  Project has  certain  long-term  obligations  relating to its Gas
Agreement with GSF (See Note 5 of the Consolidated Financial Statements) and its
Power Contract with SCE. These  obligations are not 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  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     $ 836,000
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 Sheets at December 31,
  2003 and 2002                                        F-4
Consolidated Statements of Operations for the
  three years ended December 31, 2003                  F-5
Consolidated Statements of Changes in
 Shareholders' Equity for the three years
 ended December 31, 2003                               F-6
Consolidated Statements of Cash Flows for the three
  years ended December 31, 2003                        F-7
Notes to Consolidated Financial Statements             F-8 to F-16

Financial Statements for Stillwater Hydro Partners, L.P.



                        Ridgewood Electric Power Trust I

                        Consolidated Financial Statements

                        December 31, 2003, 2002 and 2001


<PAGE>



                        Report of Independent Accountants

Managing Shareholder and Shareholders'
Ridgewood Electric Power Trust I



We have  audited  the  accompanying  consolidated  balance  sheet  of  Ridgewood
Electric  Power Trust I 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 I 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 I:

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 I 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 I
Consolidated Balance Sheets
--------------------------------------------------------------------------------
                                                             December 31,
                                                     ---------------------------
                                                         2003           2002
                                                     -----------    ------------
Assets:
Cash and cash equivalents ........................   $   835,739    $ 1,988,812
Trade receivables ................................       447,156        440,199
Due from affiliates ..............................        45,354         48,354
Assets held for sale .............................       243,349           --
Other current assets .............................        36,863         45,911
                                                     -----------    -----------

       Total current assets ......................     1,608,461      2,523,276

Investment in Stillwater Hydro Partners, L.P. ....       635,576        598,867

Equipment held by Ridgewood
  Rhode Island Generation LLC ....................     1,000,000           --

Plant and equipment ..............................     2,710,725      5,917,134
Accumulated depreciation .........................    (1,197,303)    (1,245,519)
                                                     -----------    -----------
                                                       1,513,422      4,671,615
                                                     -----------    -----------

Electric power sales contract ....................     2,207,778      2,207,778
Accumulated amortization .........................    (2,050,084)    (1,734,687)
                                                     -----------    -----------
                                                         157,694        473,091
                                                     -----------    -----------

Other non-current assets .........................        22,570         25,000
                                                     -----------    -----------
        Total assets .............................   $ 4,937,723    $ 8,291,849
                                                     -----------    -----------

Liabilities and Shareholders' Equity:
Liabilities:
Current maturities of long-term debt .............   $   299,921    $   275,067
Accrued professional fees ........................        92,208         61,281
Accrued fuel expense .............................       191,616        189,158
Accounts payable and accrued expense .............         4,545           --
Due to affiliates ................................         1,810          1,810
                                                     -----------    -----------
         Total current liabilities ...............       590,100        527,316

Long-term debt, less current portion .............       652,686        952,607

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

Shareholders' Equity:
Shareholders' equity (105.5 investor
     shares issued and outstanding) ..............     3,748,147      6,833,966
Managing shareholder's accumulated deficit
   (1 management shares issued and outstanding) ..       (53,210)       (22,040)
                                                     -----------    -----------
         Total shareholders' equity ..............     3,694,937      6,811,926
                                                     -----------    -----------

         Total liabilities and shareholders'
              equity .............................   $ 4,937,723    $ 8,291,849
                                                     -----------    -----------




        See accompanying notes to the consolidated financial statements.



<PAGE>




Ridgewood Electric Power Trust I
Consolidated Statements of Operations
--------------------------------------------------------------------------------

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

 Power generation revenue ..........  $ 3,203,435    $ 3,262,789    $ 4,140,580
 Rental revenue ....................        7,620         89,400        238,574
                                      -----------    -----------    -----------
    Total revenue ..................    3,211,055      3,352,189      4,379,154

Cost of sales, including
   depreciation and
   amortization of $649,768,
   $614,196 and $552,722 in
   2003, 2002 and 2001 .............    2,267,435      2,572,063      1,929,321
                                      -----------    -----------    -----------

Gross profit .......................      943,620        780,126      2,449,833
                                      -----------    -----------    -----------

General and administrative
  expenses .........................      432,763        252,466        272,337
Provision for bad debt expense .....         --             --          480,252
Project development costs ..........         --           71,601           --
Write down of investments in
  power generation projects ........    1,772,380        209,251           --
Management fee paid to
        managing shareholder .......       68,118         77,734         87,406
                                      -----------    -----------    -----------
     Total other operating
       expenses ....................    2,273,261        611,052        839,995
                                      -----------    -----------    -----------

Income (loss) from operations ......   (1,329,641)       169,074      1,609,838
                                      -----------    -----------    -----------

Other income (expense):
   Interest income .................        9,153         33,200         78,584
   Interest expense ................      (95,811)      (118,606)       (10,852)
   Other expense ...................      (29,826)       (18,389)      (193,379)
   Equity income (loss) from
     Stillwater Hydro Partners, L.P.       36,709         36,548        (29,315)
                                      -----------    -----------    -----------
     Other expense, net ............      (79,775)       (67,247)      (154,962)
                                      -----------    -----------    -----------

Net (loss) income ..................  $(1,409,416)   $   101,827    $ 1,454,876
                                      -----------    -----------    -----------






        See accompanying notes to the consolidated financial statements.


<PAGE>


Ridgewood Electric Power Trust I
Consolidated Statements 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 .............   $ 6,345,329    $   (26,976)   $ 6,318,353

Net income for the year .......     1,440,327         14,549      1,454,876
                                  -----------    -----------    -----------

Shareholders' equity (deficit),
  December 31, 2001 ...........     7,785,656        (12,427)     7,773,229

Cash distributions ............    (1,052,499)       (10,631)    (1,063,130)

Net income for the year .......       100,809          1,018        101,827
                                  -----------    -----------    -----------

Shareholders' equity (deficit),
  December 31, 2002 ...........     6,833,966        (22,040)     6,811,926

Cash distributions ............    (1,690,497)       (17,076)    (1,707,573)

Net loss for the year .........    (1,395,322)       (14,094)    (1,409,416)
                                  -----------    -----------    -----------

Shareholders' equity (deficit),
  December 31, 2003 ...........   $ 3,748,147    $   (53,210)   $ 3,694,937
                                  -----------    -----------    -----------










        See accompanying notes to the consolidated financial statements.


<PAGE>



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

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

Cash flows from
  operating activities:
     Net income (loss) .............  $(1,409,416)   $   101,827    $ 1,454,876
                                       -----------    -----------    -----------

     Adjustments to reconcile
      net income (loss) to net
      cash flows from operating
         activities:
     Depreciation and
       amortization ................      649,768        614,196        552,722
     Writedown of investments
       in power generation
         project ...................    1,772,380        209,251           --
     Equity in (earnings)/loss
      from unconsolidated Stillwater
         Hydro Partners, L.P. ......      (36,709)       (36,548)        29,315
     Changes in assets and
       liabilities:
       (Increase) decrease in
          trade receivables ........       (6,957)      (211,241)       168,804
       Decrease (increase) in
        other current assets .......        9,048        (28,714)        (3,825)
       Decrease (increase) in
         other non-current assets ..        2,430        (25,000)          --
       Decrease (increase) in
        accounts payable and
         accrued expenses ..........        4,545           --          (34,693)
       Increase (decrease) in
         accrued professional fees .       30,927         (3,426)          --
       Increase in accrued
         fuel expense ..............        2,458        139,158           --
       Decrease (increase) in due
           to/from
            affiliates, net ........        3,000        (45,963)       (40,548)
                                       -----------    -----------    -----------
         Total adjustments .........    2,430,890        611,713        671,775
                                       -----------    -----------    -----------
         Net cash provided by
          operating activities .....    1,021,474        713,540      2,126,651
                                       -----------    -----------    -----------

Cash flows from
     investing activities:
     Capital expenditures ..........     (191,907)      (257,367)    (2,471,301)
                                       -----------    -----------    -----------
         Net cash used in
           investing
            activities .............     (191,907)      (257,367)    (2,471,301)
                                       -----------    -----------    -----------

Cash flows from
   financing activities:
     Proceeds from
      long-term debt ...............         --             --        1,500,000
     Payments to reduce
       long-term debt ..............     (275,067)      (252,272)       (20,054)
     Cash distributions
        to shareholders ............   (1,707,573)    (1,063,130)          --
                                       -----------    -----------    -----------
         Net cash (used in) provided
           by financing activities .   (1,982,640)    (1,315,402)     1,479,946
                                       -----------    -----------    -----------

Net (decrease) increase in
     cash and cash equivalents .....   (1,153,073)      (859,229)     1,135,296
Cash and cash equivalents,
   beginning of year ...............    1,988,812      2,848,041      1,712,745
                                       -----------    -----------    -----------
Cash and cash equivalents,
   end of year .....................   $  835,739    $ 1,988,812    $ 2,848,041
                                       -----------    -----------    -----------






        See accompanying notes to the consolidated financial statements.

<PAGE>


Ridgewood Electric Power Trust I
Notes to the Consolidated Financial Statements
--------------------------------------------------------------------------------


1. Organization and Purpose

Nature of Business
Ridgewood  Energy  Electric  Power,  L.P.  (the  "Partnership")  was formed as a
Delaware limited  partnership on March 6, 1991 by Ridgewood  Renewable Power LLC
(formerly Ridgewood Power  Corporation),  acting as the general partner. On June
15, 1994, with the approval of the partners,  the Partnership  merged all of its
assets and  liabilities  into a newly formed trust,  called  Ridgewood  Electric
Power Trust I (the  "Trust").  Effective  July 25, 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 Act
of 1934. In connection with this  transaction,  the Trust issued 105.5 shares in
exchange for outstanding Partnership units. Ridgewood Renewable Power LLC is the
sole managing shareholder ("Managing Shareholder").

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.

The Trust invests in  independent  power  generation  facilities and other power
generation assets.  These independent power generation  facilities include small
power  production  facilities  which produce  electricity  from landfill gas and
water.

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.

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,  with no material
impact on the consolidated financial statements.

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 of three
months or less when purchased,  to be cash and cash  equivalents.  Cash and cash
equivalents  consist of commercial  paper and funds  deposited in bank accounts.
Cash  balances  with banks as of December 31,  2003,  exceed  insured  limits by
approximately $820,000.

Trade receivables
Trade  receivables  are recorded at invoice price and do not bear  interest.  No
allowance  for bad debt expense 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 5 to 20 years with a weighted  average of 14 and 16 years
at December 31, 2003 and 2002,  respectively.  During 2003,  2002 and 2001,  the
Trust  recorded  depreciation  expense  of  $334,370,  $298,798,  and  $237,324,
respectively.

Electric Power Sales Contract
A portion of the purchase price of the Brea Project was assigned to the electric
power sales  contract  and is being  amortized  over the life of the contract (7
years) on a straight-line  basis.  The electric power sales contract is reviewed
for impairment  whenever  events or changes in  circumstances  indicate that the
carrying amount of the asset may not be recoverable. During 2003, 2002 and 2001,
the Trust recorded amortization expense of $315,398 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
contract.  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.  Interest income is recorded
when earned.

Supplemental cash flow information
Total interest paid during the years ended December 31, 2003,  2002 and 2001 was
$95,811, $118,606 and $10,852, respectively.

In the fourth quarter of 2003,  the Trust recorded  $1,000,000 in Equipment held
by Ridgewood  Rhode Island  Generation LLC and $243,349 in Assets held for sale.
Accordingly, the Trust reduced Plant and equipment $1,243,349.

Significant Customer and Supplier
During 2003, 2002 and 2001, the Trust's largest  customer,  Southern  California
Edison  ("SCE"),  accounted  for  100%,  97%  and,  95%,  respectively  of total
revenues. In early 2001, SCE experienced severe financial difficulty, see Note 8
for additional discussion.  During 2003, 2002 and 2001, the Trust purchased 100%
of its gas 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  $5,010,723  and
$7,605,812, respectively.

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

Brea Power Partners, L.P. (known as the Brea Project)
In  October  1994,   the  Trust  invested  in  a  limited   partnership   ("Brea
Partnership"),  which  acquired  a  5  megawatt  gas-fired  electric  generating
facility and related landfill gas processing  facility in Brea,  California.  On
June 1, 1997,  the Trust  purchased  the general and other  limited  partnership
interests  in Brea to increase its  ownership  in the Brea Project to 100%.  The
aggregate  purchase  price  of  the  Trust's   investments   totaled  $5,916,879
including, the assumption of liabilities and acquisition costs.

Electricity  generated by the Brea Project, over and above its own requirements,
is sold to SCE under a Power  Contract.  The Power Contract may be terminated by
either  party no earlier  than the end of 2004 on 5 years'  advance  notice.  On
March 23, 2000, SCE provided such written  notice to the Brea Project  notifying
the Brea Project it was electing to terminate the Power Contract as of March 23,
2005. After such termination,  the Brea Project will sell its electric output in
the  competitive  electric  power  market The  landfill  gas is produced  from a
landfill owned by the County of Orange,  California and is collected and sold by
GSF  Energy,  L.L.C.  ("GSF")  under a gas lease  agreement  between GSF and the
County of Orange.

In addition to procuring a long-term power  contract,  the Brea Project is faced
with the possible  termination  of its operations as of January 2005 as a result
of its  inability to comply with  certain  environmental  regulations.  The Brea
Project  operates  within  the  jurisdiction  of the  South  Coast  Air  Quality
Management District ("South Coast"), the air pollution control agency for Orange
County in Southern California.  South Coast promulgated Rule 1110-2 (the "Rule")
regarding air emissions from gaseous and liquid-fueled  stationary engines which
generally  imposes very low air emissions levels on such engines,  which include
the generating engines used by and located at the Brea Project. According to the
Rule,  existing,  or to be  installed,  electric  generating  engines must be in
compliance with the new emissions levels by January 2005 or cease operations or,
if operations  continue,  risk severe  penalties from South Coast.  The electric
generating   engines  used  by  the  Brea  Project  cannot,   in  their  current
configuration, comply with the Rule. The Brea Project requested from South Coast
an  extension  of the  Rule's  application,  but South  Coast has  rejected  the
project's request.  As a result, the Brea Project  essentially has three options
with respect to the Rule (i) cease  operations as of January 2005,  (ii) upgrade
and/or  repair the  existing  engines,  if  possible,  to comply with the Rule's
emissions  levels, or (iii) repower the Brea Project with new engines capable of
complying with the emissions levels. The Trust is seeking a workable alternative
to  ceasing  its  operations  at the Brea  Project  and,  as a result,  has been
investigating whether the existing engines can be upgraded or repaired to comply
with the Rule's air emissions levels. As of December 31, 2003, the Trust has not
currently been able to find any such solution that is or can be  demonstrated to
be both successful and  economically  feasible.  At December 31, 2003, the Trust
believes  that the  anticipated  cash flows and salvage value of the project are
sufficient  to support the carrying  value of the Brea  Project.  The Trust will
continue to research possible solutions and will record a valuation  adjustment,
if warranted, when alternatives, or lack thereof, become more determinable.

Ridgewood Mobile Power I, LLC (a wholly owned subsidiary)
Effective  August 1999, the Trust acquired two Caterpillar  mobile power modules
with a total capacity of 2.35  megawatts for $710,241.  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 Statements 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 $44,143 and
$209,251,  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.  Accordingly,
the remaining net book value of $243,349,  as of December 31, 2003, is reflected
as Assets held for sale on the accompanying Consolidated Balance Sheet.

Ridgewood Olinda, LLC (known as the Olinda Project)
In April 2001, the Trust formed Ridgewood Olinda,  LLC.  Ridgewood Olinda,  LLC,
(`Ridgewood   Olinda")   contracted   with  an   unaffiliated   engineering  and
construction firm ("the firm") to construct a $3,000,000 2.5 megawatt  expansion
to the Brea Project.  The  construction of the new addition was completed in the
second quarter of 2002.

The Olinda  Project began  commercial  operation on or about May of 2002 and had
been selling its electric output in California to the California Power Authority
("CPA")  pursuant  to  a  short-term  (ninety-day)  power  sales  contract.  The
short-term  contract  was extended by the CPA through  December 31, 2002,  along
with several other contracts with renewable (biomass)  generators.  Prior to the
expiration of the extension,  the CPA offered additional  six-month extension to
several biomass  generators but did not offer a similar  extension to the Olinda
Project. In addition, the Olinda Project submitted a proposal to SCE in response
to SCE's request for proposals for  short-term  procurement.  The Olinda Project
offered to sell SCE power pursuant to a five-year  contract at prices  favorable
to Olinda,  but slightly above prices  apparently  submitted by other  renewable
generators. SCE did not accept the Olinda Project's proposal.

Within several months of commercial  operation,  one of the electric  generating
machines installed by the firm experienced a catastrophic failure.  Although the
firm provided a replacement  engine to Ridgewood Olinda,  the Olinda Project was
subsequently  shut-down  in  October  of 2002 by the  Orange  County  electrical
inspector due to the firm's failure to install a proper  electric  switchgear or
obtain a permit for the installed switchgear.  The engine failure and switchgear
problems highlighted significant other failures of the firm, including,  but not
limited to, the firm's  failure to obtain  final  building  permits,  failure to
deliver operating manuals or provide training, and numerous other issues.

In the second  quarter of 2003,  Ridgewood  Olinda and the firm  agreed that the
firm would  refurbish and  recondition  the engines to their original  state. In
return,  Ridgewood  Olinda would pay $200,000 of the remaining  $250,000 it owed
the firm under the original  agreement.  In the third quarter,  Ridgewood Olinda
made the final payment of $200,000.

As a result of the problems  experienced  at the Olinda Project site in Southern
California  including,  but not limited to, the  construction  problems with the
engineering and  construction  firm and the fact that the Olinda Project did not
have a power  contract,  the Trust  elected to relocate the electric  generating
equipment of the Olinda  Project,  to the site of a new landfill gas development
of the Trust's  affiliate,  the Ridgewood  Power B Fund/  Providence  Expansion.
Accordingly,  the Olinda  project had its engines  removed from its facility for
refurbishment  and  reconditioning  during  the  third  quarter  of  2003.  Upon
completion of the overhaul,  the engines were transferred to Rhode Island, where
they are being installed in the Ridgewood Rhode Island generation facility,  the
new landfill gas  development  site of the  Ridgewood  Power B Fund/  Providence
Expansion.

As of October 1, 2003,  Ridgewood  Olinda  entered into a lease  agreement  with
Ridgewood  Rhode Island  Generation  LLC, (a subsidiary of the Ridgewood Power B
Fund/  Providence  Expansion)  whereby  Ridgewood Olinda will receive 15% of the
available  cash flows (as  defined) of the  Ridgewood  Rhode  Island  generation
facility.  The agreement  will remain in effect as long as the  Ridgewood  Rhode
Island generation  facility is in operation.  Any payments received arising from
the  agreement  will be  treated as a  reduction  of the  carrying  value of the
segregated  asset  until  said  asset  has been  bought  down to zero,  or until
circumstances have changed  sufficiently whereby it would be appropriate for the
Trust to recognize income, if any, on the transaction.

As a result of the relocation and installation of the Olinda  project's  engines
in Rhode Island, the Trust recorded a write down of approximately  $1,728,000 in
the third quarter of 2003 with $1,000,000  representing the remaining  estimated
fair value of the project.

Stillwater Hydro Partners, L.P.
On October  31,  1991,  the Trust  acquired,  for  $1,000,000,  a 32.5%  general
partner's  interest  in  a  limited  partnership  whose  sole  business  is  the
construction,  ownership and operation of a 3.5 megawatt hydroelectric facility,
located on the Hudson River in Stillwater,  New York (the "Stillwater Project").
At the time of the investment,  the project was under construction and commenced
operations in May 1993.  Electricity generated by the Stillwater Project is sold
to the Niagara Mohawk Power  Corporation  under a long-term  Power Contract that
expires in 2028.

On May 16, 1994, the Trust, as stipulated in the limited partnership  agreement,
elected to exchange its general partner interest for a 32.5% limited partnership
interest, which includes a priority distribution of available cash flow from the
project in the aggregate amount of $1,000,000. Such distribution is payable from
available  cash  flows in nine  annual  installments  together  with  cumulative
interest at 12% per year, which were scheduled to begin in May 1995. To date, no
payments have been  received and any future  proceeds will be recorded in income
on an as received basis.

The ultimate ability of the project to meet its payment obligations to the Trust
is dependent on the actual  operating  performance  of the  Stillwater  Project,
which,  in turn,  is largely  dependent  upon water levels in the Hudson  River.
Since 1995,  water levels in the Hudson River basin have  frequently  been below
normal.  Due to the low water levels,  the operating results of the project were
insufficient to meet its debt payments,  and accordingly,  no distributions were
made to the Trust  since 1994.  As a result,  all  available  cash flow from the
Stillwater Project is being applied to meet its debt service requirements. Until
the current debt service  requirements are paid, it appears likely that most, if
not  all,  of the  payments  due to the  Trust  will  be  carried  forward  into
subsequent years.

The Trust accounts for its investment in the Stillwater Project under the equity
method of accounting.  The Trust's  equity in the  income/loss of the Stillwater
Project  has  been  included  in the  consolidated  financial  statements  since
acquisition, subject to certain adjustments.

Summarized financial information for the Stillwater Project is as follows:

Balance Sheet Information

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

Current assets ..............   $  270,014   $  225,380
Non-current assets ..........    8,187,390    8,549,483
                                ----------   ----------
Total assets ................   $8,457,404   $8,774,863
                                ----------   ----------

Current liabilities .........   $  871,637   $  783,911
Long-term debt ..............    3,871,054    4,404,898
Other non-current liabilities    2,751,000    2,615,292
Equity ......................      963,713      970,762
                                ----------   ----------
Total liabilities and equity    $8,457,404   $8,774,863
                                ----------   ----------

Adjusted Trust share ........   $  635,576   $  598,867
                                ----------   ----------

Statement of Operations Information

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

Revenue ............   $ 1,310,630    $ 1,384,041    $ 1,262,217
                       -----------    -----------    -----------
Operating expenses .       696,732        709,994        723,886
Other expense ......       620,947        681,643        748,532
                       -----------    -----------    -----------
Total expenses .....     1,317,679      1,391,637      1,472,418
                       -----------    -----------    -----------
Net loss ...........   $    (7,049)   $    (7,546)   $  (210,201)
                       -----------    -----------    -----------

Adjusted Trust Share   $    36,709    $    36,548    $   (29,315)
                       -----------    -----------    -----------

4. Long-Term Debt

In August  2001,  Ridgewood  Olinda,  LLC entered into an  agreement,  effective
December  2001,  to borrow  $1,500,000.  The proceeds from the loan were used to
finance the 2.5 megawatt  expansion of the Olinda facility.  The  collateralized
non-recourse  notes  are  due in  monthly  installments  of  $30,906,  including
interest  at 8.68%.  Final  payment is due on  November  30,  2006.  The loan is
collateralized  by the  equipment  that was  originally  installed at the Olinda
facility, which has now been transferred to Rhode Island.

Following is a summary of long-term debt at December 31, 2003 and 2002:


                                               2003           2002
                                           -----------    -----------
Senior collateralized non-recourse notes   $   952,607    $ 1,227,674
payable
Less - current maturity ................      (299,921)      (275,067)
                                           -----------    -----------
Total long-term debt ...................   $   652,686    $   952,607
                                           -----------    -----------


<PAGE>


Remaining scheduled repayments of long-term debt principal are as follows:

Year Ended
December 31,         Repayment
------------         ---------
       2004           $299,921
       2005            327,022
       2006            325,664
                      --------
       Total          $952,607
                      --------

5. Commitments

The Brea  project has a long-term  agreement  to purchase  landfill gas from its
supplier.  The agreement  expires in December 2018 and is adjusted  annually for
inflation through December 31, 2004.

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


                                   Year Ended
                                   December 31,            Purchases
                                   ------------            ---------
                                   2004                    $ 774,266
                                   2005                      720,000
                                   2006                      720,000
                                   2007                      720,000
                                   2008                      720,000
                                   Thereafter              7,200,000
                                                        ------------
                                   Total                $ 10,854,266
                                                        ------------

6. 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 1% of the prior year's net assets
of the  Trust  payable  monthly.  During  2003,  2002 and 2001,  the Trust  paid
management  fees to the Managing  Shareholder  of $68,118,  $77,734 and $87,406,
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 15%  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.

As a result of the distributions paid in January of 2004, the Trust's cumulative
distributions  have  reached  Payout.  Accordingly,   the  Managing  Shareholder
received, and will continue to receive, 20% of the distributions of the Trust.

The Managing  Shareholder  and affiliates  own, in the  aggregate,  3.0 investor
shares of the Trust with a cost of  $273,000.  The Trust  granted  the  Managing
Shareholder a single  Management Share  representing the Managing  Shareholder's
management rights and rights to distributions of cash flow.

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  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 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 Brea Project  $129,716,
$181,563 and $165,083,  respectively, for overhead items allocated in proportion
to the amount invested in projects  managed.  During the year ended December 31,
2003,  2002 and 2001,  Ridgewood  Management  charged the Olinda Project $9,277,
$14,214 and $0, respectively,  for overhead items allocated in proportion to the
amount invested in projects managed.  Ridgewood Management also charged the Brea
and Olinda projects for all of the direct operating and  non-operating  expenses
incurred during the period.

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 do not bear  interest.  At December 31, 2003 and 2002,  the Trust had
short-term  receivables  from  affiliates in the amounts of $45,354 and $48,354,
respectively.

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,  and  accounts  payable and  accrued  expenses
approximates their fair value. The fair value of the long-term debt,  calculated
using  current  rates  for  loans  with  similar  maturities,  does  not  differ
materially from its carrying value.

8. Sale of Trade Receivables

In January  2001,  SCE  informed  the Brea  Project,  as well as numerous  other
unaffiliated  electric  generating   facilities  in  California,   that  it  was
temporarily suspending payments to such facilities due to SCE's severe financial
problems.  SCE did not pay the Brea Project for energy and capacity delivered to
SCE for the months of November and December 2000,  January and February 2001. In
April  2001,  the  Brea  Project  entered  into an  agreement  with a  financial
institution  whereby it sold,  irrevocably and without  recourse,  its undivided
interest in all eligible  trade  accounts  receivables  for those months.  Costs
associated with the sale of receivables of $480,252 in 2001,  primarily  related
to the discount and loss on sale,  is included in provision for bad debt expense
in the Consolidated Statements of Operations. SCE is current in its payments for
energy and capacity delivered after February 2001.
<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 ..........   $   731,000   $   706,000    $ 1,072,000    $   702,000
Income (loss) from
 operations ......       117,000      (132,000)    (1,366,000)        51,000
Net income (loss)        100,000      (127,000)    (1,386,000)         4,000




                                          2002
                     ---------------------------------------------------
                        First        Second        Third        Fourth
                       Quarter       Quarter      Quarter       Quarter
------------------   ----------    ----------    ----------   ----------
Revenue ..........   $  539,000    $  845,000    $1,235,000   $  733,000
Income (loss) from
 operations ......      (43,000)      (87,000)      447,000     (148,000)
Net income (loss)       (69,000)     (194,000)      402,000      (37,000)


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 the Managing
Shareholder.  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.

     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 (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, an NASD member, which has been the placement agent
for the private placement offerings of the eight trusts and three LLCs sponsored
by Ridgewood  Renewable Power, LLC and the funds sponsored by Ridgewood Capital,
which  assists in offerings  made by the Managing  Shareholder  and which is the
sponsor of privately  offered venture capital funds.  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 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  ("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.  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,  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 since August 2000. 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, Inc., 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, 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,  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
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  principal  officers of the Trust
are identical to those of the Managing Shareholder.

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

(e) Corporate Trustee

     The  Corporate  Trustee of the Trust is  Christiana  Bank & Trust  Company.
Legal title to Trust  Property is in the name of the Trust.  Christiana  Bank 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

     All individuals  subject to the requirements of Section 16(a) have complied
with those reporting requirements during 2003.

(g) RPM.

     As discussed above at Item 1 - Business,  RPM assumed day-to-day management
responsibility  for the Brea Project,  effective June 1, 1997. Like the Managing
Shareholder,  RPM is  wholly  owned by  Robert  E.  Swanson.  RPM also  provided
management services to the Olinda 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 will be borne by
the Managing Shareholder.

     The Managing  Shareholder  does not charge RPM for the full amount of rent,
utilities,  supplies and office  expenses  allocable to RPM. As a result,  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 are 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  are 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 does 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.

     The  Operation  Agreement  does not have a fixed term and is  terminable by
RPM,  by the  Managing  Shareholder  or by vote of a  majority  in  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 the officers 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 10P.

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 105.5 Investor Shares  (approximately $10.5 million of gross
proceeds) of beneficial  interest in the Trust  pursuant to a private  placement
offering under Rule 506 of Regulation D under the  Securities  Act. The offering
closed on March 31, 1992.  Further details concerning the offering are set forth
above  at  Item  1--Business.  No  person  beneficially  owns  5% or more of the
Investor Shares.

     The Managing Shareholder of the Trust, purchased for cash in the offering 1
Investor Share,  equal to .9 of 1% of the outstanding  Investor Shares,  and Mr.
Swanson  purchased an additional 2.1 Investor Shares.  The total cost of the 3.0
Investor Shares was $273,000.  By virtue of its purchase of that Investor Share,
Ridgewood  Power 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 Ridgewood Power
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  Ridgewood  Power 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 that the Trust deems necessary to cover anticipated Trust expenses,  is
to be distributed to the Investors and the Managing  Shareholder  (collectively,
the "Shareholders"), from time to time, as the Trust deems appropriate. Prior to
Payout (the point at which  Investors  have  received  cumulative  distributions
equal to the amount of their capital contributions), each year all distributions
from the Trust,  other than  distributions of the revenues from  dispositions of
Trust Property,  are to be allocated 99% to the Investors and 1% to the Managing
Shareholder until Investors have received annual  distributions  equal to 15% of
their Capital  Contributions (a "15% Priority  Distribution") and thereafter any
remaining  distributions  will be allocated  80% to the Investors and 20% to the
Managing  Shareholder.  Revenues from  dispositions  of Trust Property are to be
distributed 99% to Investors and 1% to the Managing Shareholder until Payout. In
all cases, after Payout,  Investors are to be allocated 80% of all distributions
and the Managing Shareholder 20%.

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

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

     In 2003 and 2002, the Trust made distributions to the Managing  Shareholder
(which is a member of the Board of the  Trust) as stated at Item 5 - Market  for
Registrant's  Common Equity and Related Stockholder  Matters.  In addition,  the
Trust  and  its  subsidiaries  paid  fees  and  reimbursements  to the  Managing
Shareholder and its affiliates as follows:

                        2003       2002      2001       2000       1999
Paid to
Managing
Shareholder           $68,118    $77,734    $87,406    $70,083    $76,332
Cost
reimbursement
RPM                $2,176,067 $2,418,929 $1,842,315 $1,255,007 $1,334,451


     The management fee,  payable monthly under the Management  Agreement at the
annual rate of 1% of the Trust's prior year net asset value (until June 1994, of
the Trust's total capital  contributions),  began on the closing of the offering
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  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  $26,000.  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  $17,000 and $31,000,
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  $28,000. 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
PricewaterhouseCoopers LLP and engaging Perselson Weiner LLP.

     (c) Exhibits.

     2A. Acquisition Agreement, by and between GSF Energy, L.L.C. and Olinda,
L.L.C., dated as of May 31, 1997. Incorporated by reference to Exhibit 2A in
Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.

     2B. Letter, dated as of May 31, 1997, supplementing Acquisition Agreement.
Incorporated by reference to Exhibit 2B in Registrant's Current Report on Form
8-K dated June 1, 1997.

     3A. Certificate of Trust of the Registrant is incorporated by reference to
Exhibit 3A of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.

     3B. Declaration of Trust of Registrant is incorporated by reference to
Exhibit 3B of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.

     3C. Agreement of Limited Partnership of Ridgewood Energy Electric Power,
L.P. dated as of March 6, 1991 is incorporated by reference to Exhibit 3C of
Registrant's Registration Statement which was filed with the Commission on May
26, 1994.

     10A. Management Agreement between the Registrant and Ridgewood Power
Corporation is incorporated by reference to Exhibit 10A of Registrant's
Registration Statement which was filed with the Commission on May 26, 1994.

     10B. Stillwater Hydro Partners L.P. Amended and Restated Agreement of
Limited Partnership dated as of July 29, 1991 and letter of amendment thereof
dated as of May 16, 1994 is incorporated by reference to Exhibit 10B of
Registrant's Registration Statement which was filed with the Commission on May
26, 1994.

     10C. Power Purchase Agreement dated as of September 19, 1989 between
Stillwater Hydro Partners L.P. and Niagara Mohawk Power Corporation and
amendment thereof dated as of August 28, 1990 is incorporated by reference to
Exhibit 10C of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.

     10D. RW Power Partners L.P. Agreement and Restated Agreement of Limited
Partnership dated as of October 1, 1992 among Ridgewood Energy Electric Power,
L.P., Ridgewood Power Corporation and WE GEN, Inc. is incorporated by reference
to Exhibit 10D of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.

     10E. The Registrant has terminated the agreement designated 10E in its
prior Annual Reports on Form 10-K.

     10F. The Registrant has terminated the agreement designated 10F in its
prior Annual Reports on Form 10-K.

     10G. Agreement of Limited Partnership of Brea Power Partners, L.P. dated as
of October 12, 1994 by and between Brea Power (I), Inc., GSF Energy Inc. and
Ridgewood Electric Power Trust I is incorporated by reference to Registrant's
Form 8-K filed with the Commission on October 27, 1994.

     10H. Agreement, dated as of January 16, 1997, by and between RW Power
Partners, L.P. and Virginia Electric Power Company Incorporated by reference to
Exhibit 10H in the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1997.

     10I. Amendment to Transaction Documents, dated as of May 31, 1997, by and
among GSF Energy, L.L.C., Brea Power Partners, L.P. and Ridgewood Electric Power
Trust I. Incorporated by reference to Exhibit 10I in Registrant's Amendment No.
1 to Current Report on Form 8-K dated June 1, 1997.

     10J. Parallel Generation Agreement, by and between Southern California
Edison Company and GSF Energy, Inc. (Brea Power Partners, L.P., assignee), as
amended. Incorporated by reference to Exhibit 10J in Registrant's Amendment No.
1 to Current Report on Form 8-K dated June 1, 1997.

     10K. Partial Assignment and Assumption Agreement, dated as of November 29,
1994, by and between GSF Energy, Inc. and Brea Power Partners, L.P. Incorporated
by reference to Exhibit 10K in Registrant's Amendment No. 1 to Current Report on
Form 8-K dated June 1, 1997.

     10L. Amended and Restated Gas Lease Agreement, dated as of December 14,
1993, by and between the County of Orange, California and GSF Energy, Inc., as
modified. Incorporated by reference to Exhibit 10L in Registrant's Amendment No.
1 to Current Report on Form 8-K dated June 1, 1997.

     10M. Gas Sale and Purchase Agreement, dated November 29, 1994 by and
between GSF Energy, Inc. and Brea Power Partners, L.P. Incorporated by reference
to Exhibit 10M in Registrant's Amendment No. 1 to Current Report on Form 8-K
dated June 1, 1997.

     10N. Support Agreement, dated as of November 29, 1994, by and among Brea
Power Partners, L.P., the Trust and GSF Energy, Inc. Incorporated by reference
to Exhibit 10N in Registrant's Amendment No. 1 to Current Report on Form 8-K
dated June 1, 1997.

       10O. Amended and Restated Gas Sale and Purchase Agreement, dated June 11,
2001, by and between GSF Energy, LLC and Ridgewood Power Management, LLC, on
behalf of Brea Power Partners, L.P. and Ridgewood Olinda, LLC.

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

       23.1 Consents of independent accountants.

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

     Exhibits  and  schedules to these  exhibits  are omitted,  and lists of the
omitted  documents are found in their tables of contents.  The Registrant agrees
to furnish  supplementally  a copy of any  omitted  exhibit or schedule to these
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 I (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
I ("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 I ("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