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 0-21304

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

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

         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, 2003 was $23,537,750.

     Exhibit Index is located on Page 27.


<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 II (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 November 20, 1992
to participate  in the  development,  construction  and operation of independent
power  generating  facilities  ("Independent  Power  Projects"  or  "Projects").
Christiana Bank & Trust Company, a ("Christiana"),  a Delaware trust company, is
the Corporate Trustee of the Trust.

     The  Trust  sold  shares of  beneficial  interest  in the Trust  ("Investor
Shares") in a private placement offering (the "Offering") which ended on January
31,  1994,  at which  time it had raised  approximately  $23.5  million.  Net of
offering fees,  commissions and expenses,  the Offering  provided  approximately
$19.4 million of net funds  available for  investments  in the  development  and
acquisition  of Projects.  The Trust has 525 record  holders of Investor  Shares
(the  "Investors").  As  described  below in Item  1(c)(2),  the Trust  (and its
subsidiaries) own interests in four Projects.

     The  Trust  made an  election  to be  treated  as a  "business  development
company" under the Investment  Company Act of 1940, as amended (the "1940 Act").
On February 27, 1993, the Trust notified the Securities and Exchange  Commission
of such  election  and  registered  the  Investor  Shares  under the  Securities
Exchange  Act of 1934,  as amended  (the "1934  Act").  On April 29,  1993,  the
election  and  registration  became  effective.  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") as a result of such withdrawal,  including,
but not  limited to,  deletion of the  provision  of the  Declaration  requiring
Independent  Trustees.  Consents  were  tabulated  at the close of  business  on
January 7, 2002.  A total of  235.3775  Investor  Shares  were  outstanding  and
entitled  to be  voted.  Based on such  tabulation,  a  two-third  majority,  as
required  by  the  Declaration  of  Trust,  consented  to  such  withdrawal  and
amendments.  On  January  10,  2002,  the Trust  filed with the  Securities  and
Exchange  Commission a notification  to withdraw its election to be treated as a
"business  development  company." As a result of such withdrawal,  the Trust now
utilizes generally accepted accounting principles for operating companies.

     The  Trust is  organized  similarly  to a  limited  partnership.  Ridgewood
Renewable Power LLC (the "Managing  Shareholder"),  a Delaware limited liability
company,  is the Managing  Shareholder  of the Trust.  In general,  the Managing
Shareholder has the powers of a general partner of a limited partnership. It has
complete  control  of the  day-to-day  operation  of  the  Trust.  The  Managing
Shareholder is not regularly  elected by the owners of the Investor  Shares (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 organized by
the Managing Shareholder (the "Other Power Trusts"):

o Ridgewood Electric Power Trust I ("Power I");
o Ridgewood Electric Power TrustIII ("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 Ridgewood Power B Fund/Providence Expansion (the "B Fund").

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

o Ridgewood Renewable PowerBank LLC;
o Ridgewood Renewable Powerbank II, LLC; and
o Ridgewood Renewable PowerBank III, LLC.

         (b) Financial Information about Industry Segments.

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

(c) Narrative Description of Business.

      (1)  General Description.

     The Trust was formed to participate in the  development,  construction  and
operation of Projects that generate  electricity  or related forms of energy for
sale to  manufacturers,  utilities and other users. The Trust also may invest in
facilities related to those Projects.

         (2)   Projects.

         (i) Berkshire Project and B-3 Project.

     On January 4, 1994,  the Trust made an  approximately  $2.3 million  equity
investment in  Pittsfield  Investors  Limited  Partnership  ("PILP"),  which was
formed to acquire the  Berkshire  Project,  including the assets and business of
the Pittsfield  Resource Recovery Facility.  The Berkshire Project is a waste to
energy plant located in Pittsfield,  Massachusetts. The Berkshire Project, which
has been operating since 1981,  burns municipal solid waste supplied by the City
of Pittsfield  ("Pittsfield"),  surrounding communities and other providers. The
Trust's  partners in the Berkshire  Project were  subsidiaries of Energy Answers
Corporation ("EAC"). EAC made an equity investment of approximately $1.3 million
in the  Berkshire  Partnership  and also serves as manager  and  operator of the
facility.  In  addition,  on August 31,  1994,  the Trust  entered  into the B-3
Limited Partnership,  with affiliates of EAC, the same firm with which the Trust
participated  in  the  Berkshire  Project.  The  Trust  made  an  investment  of
approximately  $4  million  into the B-3  Limited  Partnership  to  construct  a
municipal  waste transfer  station  located in Columbia  County,  New York ("B-3
Project").  The B-3 Project is a waste transfer  station where  municipal  waste
collected from nearby towns by smaller,  short haul trucks can be transferred to
larger,  long haul  trucks  for more  efficient  transportation  of the waste to
distant landfills.

     The Trust was  entitled to an annual  preferred  distribution  of available
cash flow,  representing revenue from the Berkshire Project, (after funding debt
service,  debt service  reserves and operating and  maintenance  expenses) in an
amount equal to 15% of its  investment.  With  respect to the B-3  Project,  the
Trust  was  entitled  to  receive  a  cumulative  priority  return  on the Trust
investment of 18% per annum,  with any  shortfalls  being  carried  forward into
subsequent years.

     Distributions  from the  Berkshire  Project  ceased in the third quarter of
1998 and did not resume.  In the third  quarter of 1998,  EAC informed the Trust
that  significant  and undisclosed  cost overruns in the  construction of an ash
handling system for the Berkshire  Project had depleted the Project's funds. EAC
further  advised the Trust that  distributions  from Berkshire to the Trust were
unlikely to resume.  As a result of the  expiration of certain key agreements at
the  end of  2004,  the  Berkshire  Project's  ability  to  continue  operations
thereafter was uncertain. As with the Berkshire Project,  distributions from the
B-3 Project were impaired by repeated  extensions  of the closing  deadlines for
some local landfills and capacity expansions at other local landfills.  If waste
can  be  cheaply  deposited  at  local  landfills,  there  is  less  demand  for
consolidating the waste for transfer to distant sites.

     As a result of the financial difficulties experienced by both the Berkshire
and B-3 Projects and the lack of  distributions  from either project,  the Trust
began negotiations with EAC in 2002 to either renegotiate certain aspects of the
contractual  documents that the Trust believed hindered  operation and failed to
properly motivate EAC or, in the alternative, sell its interest in the Berkshire
Project and B-3 Project to EAC. Ultimately, the parties agreed to a sale.

     On September 20, 2002 the Trust, sold 100% of its ownership interest in the
B-3 Project and the Berkshire Project to EAC. The acquisition agreement provided
for the sale of 100% of the Trust's  ownership in the two projects in return for
$1,200,000 cash and $5,000,000 of interest bearing  promissory  notes. The notes
bear  interest  at a rate of 10% per  annum,  and will be repaid  over a 17-year
term. The notes are  collateralized  by all the assets of the  partnerships.  To
date, EAC has made all required payments under the notes.

         (ii)  Monterey Project.

     On January 9, 1995,  the Trust  purchased  100% of the equity  interests in
Sunnyside  Cogeneration Partners,  L.P., which owns a 5.5-megawatt  cogeneration
project  located  in  Salinas,   Monterey  County,   California  (the  "Monterey
Project"). The aggregate purchase price was approximately $5.2 million including
transaction  costs.  The Monterey Project has been operating since 1991 and uses
natural  gas fired  reciprocating  engines to generate  electricity  for sale to
Pacific Gas and Electric Company ("PG&E") under a long term contract expiring in
2020 (the "Power Contract"). Thermal energy from the Monterey Project is used to
provide warm water to an adjacent  greenhouse  under a long- term  contract that
also terminates in 2020. The Monterey Project is operated on behalf of the Trust
by Ridgewood Power Management LLC ("RPM").

     The Monterey  Project is a  "Qualifying  Facility" or "QF" under the Public
Utility Regulatory  Policies Act of 1978, as amended ("PURPA").  The independent
power industry in the United States was created in large part by PURPA and other
federal legislation passed in response to the energy crises of the 1970s. PURPA,
among other things,  requires utilities to purchase electric power from QFs, and
also  exempts  these  QFs  from  most  federal  and  state  utility   regulatory
requirements.  In addition, the price paid by electric utilities under PURPA for
electricity  produced  by  QFs  is  the  utility's  avoided  cost  of  producing
electricity  (i.e.,  the  incremental  costs the utility would otherwise face to
generate  electricity  itself or  purchase  electricity  from  another  source).
Pursuant to PURPA, and state  implementation of PURPA,  many electric  utilities
have entered into  long-term  Power  Contracts with QFs at rates set by contract
formula approved by state regulatory commissions. The Monterey Project sells its
output  to PG&E  under a Power  Contract  with a  capacity  and  energy  payment
determined  pursuant to a contract  formula  approved by the  California  Public
Utilities  Commission  ("CPUC").  According  to the Power  Contract,  the energy
payment is based upon a benchmark energy price adjusted for changes over time in
a gas  index;  the so- called  "Short Run  Avoided  Cost  Methodology"  or SRAC.
However,  as described further below, the Monterey Project executed an Amendment
to the Power Contract with PG&E,  which provides that the Monterey  Project will
receive a fixed energy payment (as well as the required  capacity payment) for a
term of five (5) years, until approximately August 2006.

     During calendar years 2000 and 2001, California experienced severe electric
energy  crises  brought  on my  many  factors  including,  but not  limited  to,
implementation of flawed electric deregulation  legislation.  As a result of the
energy crises,  PG&E, among other things,  experienced severe cash shortages and
losses due primarily to the fact that it was required  under the law to purchase
electric energy at wholesale prices  significantly  above the regulated rates it
could legally charge retail  customers.  As a result,  PG&E filed for protection
under  the  U.S.  Bankruptcy  Code in  April  of  2001.  At the  time of  PG&E's
bankruptcy  filing,  the  Monterey  Project  had not  been  paid by PG&E for the
electric energy and capacity it had delivered in the last several months of 2000
and the first few months of 2001.  In  addition,  given PG&E's  bankruptcy,  the
prospects for payment in the near future were  extremely  remote.  However,  the
Monterey Project needed to have a reserve of cash to maintain operations and pay
certain fixed costs that would be incurred regardless of whether it operated and
sold to PG&E.  Therefore,  as further  detailed in the Trust's  Annual Report on
Form 10K for the Year 2001, the Trust sold its PG&E receivables at a discount.

     Subsequent  to its  bankruptcy  filing,  PG&E found  itself  under  intense
pressure to pay the QFs offline some amount of the outstanding  balance owed and
to renegotiate  Power  Contracts in order to get their electric  generation back
online and supply the electric  starved State of  California.  Therefore,  in an
effort to get as many QFs back  online as  possible,  PG&E  sought and  received
approval from the California Public Utilities  Commission ("CPUC") to offer each
QF an agreement,  and  corresponding  amendment to their Power Contracts,  for a
term of five (5) years, which would effectively  replace,  for such 5 year term,
the variable SRAC formula for  determining  the energy price with a fixed energy
price.  Such  amendment  would  allow  the QF to  operate  at a price  that  was
reasonable in light of the  circumstances  at that time. In addition,  a QF that
executed  the  amendment  agreed that it would not  institute,  or proceed  with
outstanding,  litigation  against  PG&E.  The  Monterey  Project  executed  such
amendment. However, in order to execute the amendment with a fixed energy price,
it was  necessary to procure  natural gas at a fixed  price.  As a result of the
sale of the PG&E receivables, the Monterey Project had sufficient cash available
and was able to procure such supply of natural gas from Coral  Energy  Services,
Inc., ("Coral") a subsidiary of Shell Oil. Therefore, until approximately August
2006,  the  Monterey  Project will be operating  under the  Amendment,  which is
expected to result in positive  cash flow to the Monterey  Project.  Thereafter,
the Power  Contract with the SRAC formula  becomes the energy price and there is
no  guarantee  that  SRAC at that  time  will  provide  sufficient  cash for the
Monterey Project to operate profitably.  However,  under the Power Contract, the
Monterey Project is also paid a capacity  payment.  Such payment,  along with an
SRAC  based  energy  payment,  even if  somewhat  low,  should be enough for the
Monterey  Project to operate and have a positive  cash flow.  In addition to the
gas supply  agreement  mentioned,  Coral and the Byron and San Joaquin  Projects
have a master  re-sale  agreement,  which  also  expires  in August  2006.  Such
agreement enables the NorCal Projects not to take delivery and sell back certain
of the natural  gas to Coral once  predetermined  prices have been  established.
Certain re-sale pricing for 2004 has already been determined, which is in excess
of the underlying cost.


         (iii) California Pumping Project

     In 1995, the Trust  purchased a package of irrigation  service engines (the
"Pumping  Project")  located in Ventura County,  California and also in 1995 the
Trust bought  additional  engines from unaffiliated  sellers.  The Trust's total
investment in the Pumping Project was approximately  $952,000.  RPM operates and
manages the Pumping Project.

     The   Pumping   Project  has  been   operating   since  1992  and  uses  26
natural-gas-fired  reciprocating  engines with a rated equivalent  capacity of 3
Megawatts to provide power for irrigation  wells that furnish water for orchards
of lemon and other citrus  trees.  The power is  purchased by local  farmers and
farmers' co-operatives pursuant to electric services contracts.  Presently,  the
Pumping  Project's rates are  approximately  85% of Southern  California  Edison
Company's agricultural rate of 12.2 cents/kwh. The discount was provided because
of the low natural gas prices experienced during most of 2002. However,  natural
gas  prices  have risen and the  Pumping  Project is  considering  lowering  the
discount to 90% of SCE's rate or even less,  if natural  gas prices  continue to
rise.

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

         (iv) San Diego Project.

     The Trust acquired its interest in the San Diego Project on March 21, 1994,
when it made an  investment  of  approximately  $2.3  million  to acquire an 80%
interest  in the  Project.  The Trust  made  additional  capital  contributions,
totaling  approximately $1.2 million, to the Project to fund working capital and
to purchase various leased equipment. On June 25, 1997 the Trust sold its entire
interest  in the San Diego  Project  to  subsidiaries  of NRG  Energy,  Inc.  of
Minneapolis,  Minnesota ("NRG").  The sale price was $6,200,000 in both cash and
notes. As of June 25, 2003, NRG has paid in full.

 (3) Project Management and Operations.

     The Managing  Shareholder has organized RPM to provide operating management
for the Projects, and has assigned day-to-day management of the Monterey Project
and  California  Pumping  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  Party  Transactions  for
further  information  regarding the Operation Agreement and RPM and for the cost
reimbursements received by RPM.

     The  Monterey  Project's  revenue from its Power  Contract  consists of two
components,  energy payments and capacity payments. Energy payments are based on
a facility's  net electric  output,  with payment rates (other than during the 5
year amendment)  usually indexed to the fuel costs of the purchasing  utility or
to general inflation indices. Capacity payments are based on either a facility's
net electric output or its available capacity.  Capacity payment rates vary over
the term of a Power Contract according to various schedules.

     The  Pumping  Project  sells its  power to the  farmers  on whose  land its
engines are situated  under  contracts  terminable at any time on 60 days' prior
notice  to  the  Trust.  Although  the  Trust  is  at  risk  if  many  customers
concurrently  terminate  contracts,  as might  happen if an electric  utility or
other supplier were to offer substantially  discounted rates, the Trust believes
that it is currently a competitive  supplier and that alternate customers can be
secured in the event contracts are terminated.

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

     Electricity  produced by a Project is  delivered to the  purchaser  through
transmission  lines that are built to interconnect  with the utility's  existing
power grid.  Steam  produced  by a Project is  conveyed  directly to the user by
pipeline  and the  energy  produced  by the  engines in the  Pumping  Project is
applied directly to pumps.

     Generally,  revenues from the sales of electric  energy from a cogeneration
facility will represent the most  significant  portion of the  facility's  total
revenue.  However,  to maintain its status as a QF under PURPA, it is imperative
that the Monterey Project continues to satisfy PURPA  cogeneration  requirements
as to the amount of thermal  products  generated.  See Item 1(c)(6) - Regulatory
Matters, for an explanation of these requirements. Therefore, since the Monterey
Project has only two customers  (the electric  energy  purchaser and the thermal
products  purchaser),  loss of either of these  customers  would have a material
adverse effect on the Monterey Project.

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

                                         Calendar year
                                    2003         2002         2001

Pacific Gas & Electric Co.          77.7%        69.0%        63.1%

 (4) Market Trends

     As a result of the energy crises experienced by California during the years
2000 and 2001, both the state  legislature and the California  Public  Utilities
Commission  ("CPUC") have taken significant  action by enacting  legislation and
implementing regulations,  respectively, intended primarily to avoid a repeat of
the energy  crises by creating a more  stable,  efficient  and  economic  energy
market. For example,  various legislation have been introduced in the California
legislature that, if passed,  would  "re-regulate" the electric industry in that
state and  require  that the  California  investor-owned  utilities  be the only
seller of electric  energy.  However,  there is  significant  opposition to such
efforts and a variety of other legislative effort that could enhance competition
are being  introduced  and  considered.  For example,  the  legislature  enacted
legislation  designed to enhance,  promote and encourage renewable generation in
the state by implementing a renewable  portfolio  standard  ("RPS"),  which will
require all California  investor  owned  utilities  ("IOUs"),  as well as retail
electric suppliers to have in their energy supply portfolio a certain percentage
of  renewable  generation.   This  percentage  increases  over  time  until  the
requirement  equals  20%.  However,  RPM,  on  behalf  of some of the  renewable
projects owned by some of the Trust's affiliates,  has been participating in the
California  RPS  proceedings  and believe  that due its  certain  aspects of the
legislation obtained by the IOUs and the power they exert over the CPUC, the RPS
may not result in any significant increase in renewable generation.  As a result
of the RPS, which is not likely to result in increased generation, environmental
requirements  that may cause some  generation to come  off-line,  as well as the
poor  economics of many large power  developers  which has caused them to cancel
development,  there  is a  possibility  that  once  the  economy  of the U.S and
California  improve,  electric  generation  will be in short supply.  This could
drive prices significantly higher.

     In any event,  these market  changes do not  significantly  impact upon the
Monterey  Project,  which  currently has a Power  Contract  with PG&E,  although
market changes which  strengthen PG&E benefit the Monterey Project over the long
term by ensuring PG&E's ability to pay under such Power Contract.

         (5)  Competition

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

     There are a large number of participants in the independent power industry.
Several  large  corporations  specialize in  developing,  building and operating
Independent  Power  Projects.  Equipment  manufacturers,  including  many of the
largest  corporations in the world,  provide equipment and planning services and
provide capital through finance affiliates.  In addition, there are many smaller
firms whose  businesses  are  conducted  primarily on a regional or local basis.
Many of these  companies  focus on  limited  segments  of the  cogeneration  and
independent  power  industry  and do not  provide a wide range of  products  and
services.   There  is  significant   competition  among  non-utility  producers,
subsidiaries  of utilities and utilities  themselves in developing and operating
energy-producing projects and in marketing the power produced by such projects.

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

(6) Regulatory Matters.

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

(i) Energy Regulation.

         (i)  Energy Regulation.

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

     The exemptions  from  extensive  federal and state  regulation  afforded by
PURPA to QFs are important to the Trust and its competitors.  The Trust believes
that each of its Projects is a QF. If a Project loses its QF status, the utility
can reclaim  payments  it made for the  Project's  non-qualifying  output to the
extent those  payments are in excess of current  avoided  costs or the Project's
Power Contract can be terminated by the electric utility.

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

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

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

(ii) Environmental Regulation.

     The construction and operation of Independent Power Projects are subject to
extensive  federal,  state  and  local  laws  and  regulations  adopted  for the
protection  of human health and the  environment  and to regulate  land use. The
laws and  regulations  applicable  to the Trust and Projects in which it invests
primarily  involve the  discharge  of  emissions  into the water and air and the
disposal  of  waste,  but can  also  include  wetlands  preservation  and  noise
regulation.  These  laws and  regulations  in many cases  require a lengthy  and
complex process of renewing licenses,  permits and approvals from federal, state
and local agencies.  Obtaining  necessary  approvals  regarding the discharge of
emissions  into the air is critical to the  development  of a Project and can be
time-consuming  and difficult.  Each Project requires  technology and facilities
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  Trust's  Projects  must  comply  with many  federal and state laws and
regulations  governing  wastewater and storm water discharges from the Projects.
These are  generally  enforced  by states  under  permits  for point  sources of
discharges and by storm water  permits.  Under the Clean Water Act, such permits
must be renewed  every five years and permit  limits can be reduced at that time
or under  re-opener  clauses at any time.  The  Projects  have not had  material
difficulty in complying with their permits or obtaining  renewals.  The Projects
use closed-loop engine cooling systems, which do not require large discharges of
coolant except for periodic  flushing to local sewer systems under permit and do
not make other material discharges to groundwater or streams.

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

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

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

(e) Employees.

     The operating  personnel of the Monterey and Pumping  Projects are employed
by RPM and accordingly the Trust has no employees.  The persons  described below
at Item 10 -  Directors  and  Executive  Officers  of the  Registrant  serve  as
executive  officers  of the  Trust  and  have  the  duties  and  powers  usually
applicable  to similar  officers of a Delaware  corporation  in carrying out the
Trust business.

Item 2.  Properties.

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

     The following  table shows the material  properties  (relating to Projects)
owned or leased by the Trust's  subsidiaries  or partnerships in which the Trust
has an equity  interest.  All of the Projects are described in further detail at
Item 1(c)(2).

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

Monterey    Monterey,                                           Gas-fired cogen
            CA           Leased     2020      2      10,000     eration facility


Pumping     Ventura Cy,  Leased     N/A       N/A      N/A      Natural gas
Project     CA            or                                    engines powering
                         licensed                               irrigation pumps

Item 3.  Legal Proceedings.

         None.

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

         None.

PART  II

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

(a) Market Information.

     The Trust sold 235.3775 Investor Shares of beneficial interest in the Trust
in its private  placement  offering of Investor Shares,  which closed on January
31, 1994.  There is  currently  no  established  public  trading  market for the
Investor Shares. 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,
and are restricted  under federal and state laws regulating  securities when the
Investor  Shares are held by persons in a control  relationship  with the Trust.
Investors   wishing  to  transfer  Investor  Shares  should  also  consider  the
applicability  of state  securities  laws. The Investor Shares have not been and
are not expected to be registered  under the  Securities Act of 1933, as amended
(the "1933 Act"),  or under any other  similar law of any state in reliance upon
what the Trust  believes to be  exemptions  from the  registration  requirements
contained  therein.  Because the Investor Shares have not been registered,  they
are "restricted securities" as defined in Rule 144 under the 1933 Act.

(b)  Holders

     As of the date of this Form 10-K,  there are 525 record holders of Investor
Shares.

(c)  Dividends

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

                                         Year Ended       Year ended
                                         December 31,     December 31,
                                            2003            2002

Total distributions to Investors           $1,412,268      $823,824
Distributions per Investor Share               $6,000       $ 3,500
Distributions to Managing Shareholder         $14,265       $ 8,321

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

     Occasionally,  distributions  may include funds derived from the release of
cash from operating or restricted  cash.  Further,  the  Declaration  authorizes
distributions  to be made from  cash  flows  rather  than  income,  or from cash
reserves in some  instances.  For  purposes  of  generally  accepted  accounting
principles,  amounts  of  distributions  in excess of  accounting  income may be
considered to be capital in nature.  Investors should be aware that the Trust is
organized to return net cash flow rather that accounting income to Investors.

Item 6.  Selected Financial Data.

     The following data is qualified in its entirety by the financial statements
presented  elsewhere  in this Annual  Report on Form 10-K.  As described in such
financial  statements,  financial  information  for the years 1999 and 2000 have
been  restated to reflect the  application  of new  accounting  principles  as a
result of the Trust's election to terminate its status as a business development
company.


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

Total Fund Information:
Revenues         $2,706,744 $3,075,114 $2,374,396 3,530,580  2,507,166
Net income (loss)   272,710    255,529 (1,088,887)  218,437   (203,368)
Net assets
(shareholders'
  equity)         6,073,292  7,227,155  7,803,731  8,892,618  9,388,247
Investments in
 Plant and
 Equipment (net
 of depreciation) 1,570,880  1,798,352  2,003,302  2,221,614  2,446,494
Investment
 in Power
 Contract(net
 of amortization) 1,940,480  2,061,760  2,183,040  2,304,320  2,425,600
Total assets      6,307,760  7,561,005  8,216,155  9,595,529 10,311,744
Long-term
 Obligations             --         --         --         --         --
Per Share:
Revenues             11,500     13,065     10,087     15,000     10,652
Net income(loss)      1,159      1,086     (4,626)       928       (864)
Net asset value      25,802     30,704     33,154     38,163     39,886
Distributions
 to Investors         6,000      3,500         --      3,003      1,200


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

Introduction

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

Outlook

     The Monterey  Project is a QF as defined by PURPA and  currently  sells its
electric output to PG&E under a Power Contract expiring in 2020. During the term
of the Power  Contract,  the utility may or may not attempt to buy out the Power
Contract prior to  expiration.  At the end of the Power  Contract,  the Monterey
Project will become a merchant plant and may be able to sell the electric output
at then current  market  prices.  There can be no assurance  that future  market
prices will be sufficient to allow the Monterey  Project to operate  profitably.
See Item  1(c)(3) - Plant  Operations  for  information  concerning  a potential
challenge to the Project's Power Contract.

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

     The Columbia Project receives revenue in the form of tipping fees for waste
delivered to the facility by local waste  haulers and  transferred  to long haul
trucks for  delivery to distant  landfills.  The  Project's  profit  margins are
affected by the level of competition  from national waste  management  companies
operating  in the same  region and the  availability  of other  sources of waste
disposal.

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

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

Significant Accounting Policies

     The Trust's plant and equipment is recorded at cost and is depreciated over
its estimated  useful life. The estimated  useful lives of the Trust's plant and
equipment  range from 3 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 $368,000,  or 12%, to $2,707,000 in 2003
compared to  $3,075,000  in 2002.  The decrease is  primarily  due to the higher
precipitation  experienced in Southern California,  thus reducing the California
Pumping  project's  operations,  in addition to the reduced rates charged to its
customers as a result in the change in current market conditions in California.

     Gross profit,  which  represents  total revenues  reduced by cost of sales,
decreased  by $115,000  to a gross  profit of $29,000 in 2003.  The  decrease is
primarily the result of the lower revenues and corresponding decrease in cost of
sales from the California Pumping projects.

     General and administrative expenses decreased $116,000, or 45%, to $142,000
in 2003 from  $258,000 in 2002.  The  decrease is  partially  attributed  to the
professional fees incurred in the sale of B-3 and PILP projects in 2002.

     In 2002, the Trust recovered  $157,000 relating to PG&E revenues from prior
years,  which  had been  treated  as  uncollectible  due to  PG&E's  filing  for
bankruptcy protection.

     The management fee paid to the Managing Shareholder decreased by $9,000, or
8%, to $108,000  in 2003 from  $117,000  reflecting  the lower net assets of the
Trust.

     Loss from operations  increased $147,000,  to $221,000 in 2003 from $74,000
in 2002,  primarily  due to the  decrease in gross  profit  from the  California
Pumping projects.

     Other income, net, increased by $165,000, to $494,000 in 2003 from $329,000
in 2002. The increase is primarily due to the Trust recording an unrealized gain
of  $488,000,  in the current  year,  for the  increase  in the market  price of
natural gas , partially offset by the $190,000 of cash received in 2002 from the
1999 settlement of the  Waukesha-Pierce  litigation,  as well as the $104,000 of
equity income received from the B-3 project, which was sold in 2002.

     Net income increased $17,000,to $273,000 in 2003 from $256,000 in 2002. The
increase in income is a result of the unrealized gain on gas purchase contracts
partially  offset  by  decrease  in gross  profit  from the  California  Pumping
projects in addition to the $190,000 of other  income  received in 2002 from the
Waukesha-Pierce  litigation and the $104,000 of equity income  received from the
B-3 project.

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

     Power generation revenue increased $704,000,  or 30%, to $3,075,000 in 2002
compared to  $2,3748,000  in 2001. The increase is primarily due to the Monterey
project  operating  on its normal  schedule in 2002 as compared to 2001 when the
plant was idle from February to August due to PG&E's  failure to pay the project
for power delivered since December 1, 2000, as a result of the California energy
crisis.

     Gross profit,  which  represents  total revenues  reduced by cost of sales,
increased  by $96,000 to a gross profit of $144,000 in 2002 from a gross loss of
$460,000 in 2001. The increase is a result of an increase in energy generation.

     General and administrative expenses decreased $81,000, or 24%, to $258,000
in 2002 from $339,000 in 2001. The decrease primarily reflects the legal costs
associated with the Monterey Project's dispute with PG&E that ended in 2001 with
a favorable result for the project.

     The $127,000 of bad debt expense in 2001 is associated with the sale of the
Monterey Project's PG&E receivables to AMROC. In 2002, the Trust recovered
$157,000 relating to prior year PG&E revenues.

     The management fee paid to the Managing  Shareholder  decreased by $60,000,
or 34%, to $117,000 in 2002 from $177,000 reflecting the lower net assets of the
Trust.

     Loss from operations decreased $1,030,000,  or 93%, to $74,000 in 2002 from
$1,104,000  in 2001 as a result of the  increase in revenues and the decrease in
operating expenses.

     Other income, net, increased by $314,000,  to $329,000 in 2002 from $15,000
in 2001.  The increase is primarily due to the $190,000 of cash received in 2002
from the 1999 settlement of the Waukesha-Pierce litigation, as well as the costs
incurred  in 2001 in  issuing  the  "Notice  of  Solicitation  of  Consents"  to
investors.

     Net  income  increased  $1,296,000,to  $207,000  in 2002 from a net loss of
$1,089,000  in 2001.  The  increase  in income is a result  of the  increase  in
revenues and the decrease in operating expenses.

Liquidity and Capital Resources

     In 2003 and 2002, the Trust's  operating  activities  provided $618,000 and
$81,000 of cash, respectively.

     Cash  generated  from  investing  activities in 2003 was $678,000  compared
$1,925,000  in 2002.  The decrease is primarily due to the  $1,224,000  received
from the transfer of the B-3 and PILP projects in 2002.

     Cash used by financing  activities of  $1,427,000  and $832,000 in 2003 and
2002, respectively, represents distributions to shareholders.

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

     In August  2003,  the Trust  issued  through  its bank a standby  letter of
credit,  in the amount of $504,000 to secure the gas  purchases for the Monterey
project. The Trust used Managing  Shareholder's credit facility to collateralize
the letters of credit.

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

     The Monterey Project has certain long-term  obligations relating to its Gas
Agreement with Coral (See Note 5 of the Consolidated  Financial  Statements) and
its Power Contract with PG&E. These long-term  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     $1,218,000
Average interest rate                               1.04%


Item 8.  Financial Statements and Supplementary Data.

A. Index to Consolidated Financial Statements

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



                        Ridgewood Electric Power Trust II

                        Consolidated Financial Statements

                        December 31, 2003, 2002 and 2001



<PAGE>




                        Report of Independent Accountants

Managing Shareholder and Shareholders'
Ridgewood Electric Power Trust II



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

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 II 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 II
Consolidated Balance Sheets
--------------------------------------------------------------------------------

                                                           December 31,
                                                   -----------------------------
                                                       2003             2002
                                                   -----------      ------------
Assets:
Cash and cash equivalents ....................     $ 1,218,009      $ 1,348,825
Restricted cash ..............................            --            550,000
Trade receivables ............................         224,497          255,082
Current portion of note receivable
 from sale of investment .....................            --            277,528
Due from affiliates ..........................          16,628           14,512
Current portion of unrealized gain
  on gas purchase contract ...................         217,583             --
Other current assets .........................          41,569           47,151
                                                   -----------      -----------

       Total current assets ..................       1,718,286        2,493,098

Notes receivable from transfer of
   investment in Limited Partnership
   interests under contractual agreements ....         807,795        1,207,795

Plant and equipment ..........................       3,441,432        3,441,432
Accumulated depreciation .....................      (1,870,552)      (1,643,080)
                                                   -----------      -----------
                                                     1,570,880        1,798,352
                                                   -----------      -----------

Electric power sales contract ................       3,032,000        3,032,000
Accumulated amortization .....................      (1,091,520)        (970,240)
                                                   -----------      -----------
                                                     1,940,480        2,061,760
                                                   -----------      -----------

Unrealized gain on gas purchase contract,
    net of current portion ...................         270,319             --
                                                   -----------      -----------

        Total assets .........................     $ 6,307,760      $ 7,561,005
                                                   -----------      -----------

Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ........     $     2,371      $   156,036
Accrued fuel expense .........................          81,679           71,833
Accrued professional fees ....................          66,561           58,138
Due to affiliates ............................          83,857           47,883
                                                   -----------      -----------
         Total current liabilities ...........         234,468          333,890

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

Shareholders' Equity:
Shareholders' equity (235.3775
  investor shares issued and outstanding) ....       6,213,803        7,356,088
Managing shareholder's accumulated
   deficit (1 management share
   issued and outstanding) ...................        (140,511)        (128,973)
                                                   -----------      -----------
         Total shareholders' equity ..........       6,073,292        7,227,115
                                                   -----------      -----------
         Total liabilities and
           shareholders' equity ..............     $ 6,307,760      $ 7,561,005
                                                   -----------      -----------



        See accompanying notes to the consolidated financial statements.


<PAGE>

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

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

Power generation revenue .........   $ 2,706,744    $ 3,075,114    $ 2,374,396

Cost of sales, including
   depreciation and amortization
   of $348,752, $348,662 and
   $346,209 in 2003, 2002,and 2001     2,677,817      2,931,122      2,834,668
                                     -----------    -----------    -----------

Gross profit (loss) ..............        28,927        143,992       (460,272)
                                     -----------    -----------    -----------

General and
   administrative expenses .......       141,708        257,739        338,815
Provision for bad debt
   (recoveries) expense ..........          --         (156,938)       127,130
Management fee paid to
    managing shareholder .........       108,407        117,058        177,337
                                     -----------    -----------    -----------
     Total other
        operating expenses .......       250,115        217,859        643,282
                                     -----------    -----------    -----------

Loss from operations .............      (221,188)       (73,867)    (1,103,554)
                                     -----------    -----------    -----------

Other income (expense):
   Interest income ...............        21,692         56,641         99,848
   Interest expense ..............          --           (3,506)          --
   Unrealized gain on gas purchase
    contract                             487,902            --            --
  Equity income from B-3
     Limited Partnership .........          --          104,497         43,459
    Other income .................          --          190,331           --
    Other expense ................       (15,696)       (18,567)      (128,640)
                                     -----------    -----------    -----------
     Other income (expense), net .       493,898        329,396         14,667
                                     -----------    -----------    -----------

Net income(loss) .................   $   272,710    $   255,529    $(1,088,887)
                                     -----------    -----------    -----------









        See accompanying notes to the consolidated financial statements.



<PAGE>

Ridgewood Electric Power Trust II
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 ..... $ 9,004,936    $  (112,318)    $ 8,892,618

Net loss for
      the year ........  (1,077,998)       (10,889)     (1,088,887)
                         -----------    -----------     -----------

Shareholders' equity
  (deficit),
  December 31, 2001 ...   7,926,938       (123,207)      7,803,731

Cash distributions ....    (823,824)        (8,321)       (832,145)

Net income for the year     252,974          2,555         255,529
                         -----------    -----------     -----------

Shareholders' equity
  (deficit),
  December 31, 2002 ...   7,356,088       (128,973)       7,227,115

Cash distributions ....  (1,412,268)       (14,265)      (1,426,533)

Net income for the year     269,983          2,727          272,710
                         -----------    -----------      ------------

Shareholders' equity
  (deficit),
  December 31, 2003 ... $ 6,213,803    $  (140,511)      $ 6,073,292
                         -----------    -----------      ------------



        See accompanying notes to the consolidated financial statements.





<PAGE>



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

                                              Year Ended December 31,
                                     -------------------------------------------
                                         2003           2002           2001
                                     -----------    -----------    -------------
Cash flows from
   operating activities:
     Net income (loss) ...........    $  272,710   $   255,529    $(1,088,887)
                                     -----------    -----------    -----------

     Adjustments to
      reconcile net income (loss)
       to net cash flows
        from operating activities:
     Depreciation and
      amortization ...............       348,752        348,662        346,209
     Equity in earnings from
       unconsolidated B-3
       Limited Partnership .......          --         (104,497)       (43,459)
     Unrealized gain on gas
      purchase contract...........      (487,902)          --             --
      Changes in assets
        and liabilities:
       Decrease (increase)
        in restricted cash .......       550,000       (347,430)      (202,570)
       Decrease in
         trade receivables .......        30,585         12,788        634,802
       Decrease (increase) in
          other current assets ...         5,582        (11,242)       (15,477)
       Increase (decrease)
           in accounts payable
         and accrued expenses ....      (153,665)       148,702        (14,425)
       Increase (decrease) in
            accrued fuel expense .         9,846        (95,566)      (134,228)
       Increase in accrued
         professional fees .......         8,423          2,662           --
       Increase (decrease) in
             due to/from
              affiliates, net ....        33,858       (128,644)      (155,860)
                                     -----------    -----------    -----------
         Total adjustments .......       345,479       (174,565)       414,992
                                     -----------    -----------    -----------
         Net cash provided
             by (used in)
              operating activities       618,189         80,964       (673,895)
                                     -----------    -----------    -----------

Cash flows from
    investing activities:
     Distributions from
      B-3 Limited Partnership ....          --          200,000        200,000
     Cash received from transfer
         of investments, net .....          --        1,224,097           --
     Proceeds from
       notes receivable ..........       677,528        522,938        482,861
     Capital expenditures ........          --          (22,432)        (6,617)
                                     -----------    -----------    -----------
         Net cash provided by
          investing activities ...       677,528      1,924,603        676,244
                                     -----------    -----------    -----------
Cash flows from
      financing activities:
     Cash distributions
         to shareholders .........    (1,426,533)      (832,145)          --
                                     -----------    -----------    -----------
         Net cash used in
           financing activities ..    (1,426,533)      (832,145)          --
                                     -----------    -----------    -----------
Net (decrease)
    increase in cash
    and cash equivalents .........      (130,816)     1,173,422          2,349
Cash and cash equivalents,
       beginning of year .........     1,348,825        175,403        173,054
                                     -----------    -----------    -----------
Cash and cash equivalents,
     end of year .................   $ 1,218,009    $ 1,348,825    $   175,403
                                     -----------    -----------    -----------







        See accompanying notes to the consolidated financial statements.


<PAGE>


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


1. Organization and Purpose

Nature of business
Ridgewood  Electric  Power  Trust II (the  "Trust")  was  formed  as a  Delaware
business  trust on November 20, 1992.  The managing  shareholder of the Trust is
Ridgewood Renewable Power LLC (formerly Ridgewood Power Corporation).  The Trust
began offering shares on January 4, 1993 and discontinued its offering of shares
on January 31, 1994.

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

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

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

In November 2001,  through a proxy  solicitation  the Trust  requested  investor
consent to end the BDC status.  On January 7, 2002,  the consents were tabulated
and more than two-thirds of the investor shares  consented to the elimination of
the BDC status. Accordingly,  the Trust is no longer an investment company under
the 1940 Act.

2. Summary of Significant Accounting Policies

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

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

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


New Accounting Standards and Disclosures

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

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

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

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

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

SFAS 149
In April 2003,  the FASB issued SFAS No. 149,  "Amendment  of  Statement  133 on
Derivative  Instruments  and  Hedging  Activities."  SFAS  No.  149  amends  and
clarifies  the  accounting  for  derivative   instruments,   including   certain
derivative  instruments embedded in other contracts,  and for hedging activities
under  SFAS  No.  133,  "Accounting  for  Derivative   Instruments  and  Hedging
Activities."  SFAS No. 149 is generally  effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003.  The Trust adopted SFAS 149 effective  July 1, 2003,  resulting in the
Trust recording an asset at fair value and an unrealized gain of $487,902 on its
gas purchase and re-sale agreements.

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


Significant Accounting Policies

Cash and cash equivalents
The Trust considers all highly liquid investments with maturities when purchased
of  three  months  or  less,  to be cash  and  cash  equivalents.  Cash and cash
equivalents  consist of commercial  paper and funds  deposited in bank accounts.
Cash  balances  with banks as of December 31,  2003,  exceed  insured  limits by
approximately $1,180,000.

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 3 to 20 years  with a  weighted  average  of 15 years at
December  31, 2003 and 2002.  During  2003,  2002 and 2001,  the Trust  recorded
depreciation expense of $227,472, $227,382 and $224,929, respectively.

Electric Power Sales Contract
A portion of the  purchase  price of the  Monterey  Project was  assigned to the
electric  power  sales  contract  and is  being  amortized  over the life of the
contract (25 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 $121,280 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
$0, $3,506 and $0, respectively.

Significant Customer and Supplier
During  2003,  2002 and 2001,  the  Trust's  largest  customer,  Pacific Gas and
Electric Company ("PG&E"), accounted for 78%, 69% and 63%, respectively of total
revenues. In early 2001, PG&E experienced severe financial difficulty,  see Note
10 for additional  discussion.  During 2003,  2002 and 2001, the Trust purchased
100% of the Monterey Projects gas supply from one supplier.

Income taxes
No provision is made for income taxes in the accompanying consolidated financial
statements as the income or losses of the Trust are passed  through and included
in the tax returns of the individual  shareholders of the Trust. At December 31,
2003 and  2002,  the  Trust's  net  assets  had a tax basis of  $10,038,615  and
$11,051,680, 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

Sunnyside Cogeneration Partners, L.P. (known as the Monterey project)
On  January  9,  1995,  the  Trust  acquired  100% of the  existing  partnership
interests of Sunnyside  Cogeneration  Partners,  L.P., which owns and operates a
5.5  megawatt  electric  cogeneration  facility,  located  in  Monterey  County,
California.  The aggregate purchase price was $5,198,058  including  transaction
costs. Electricity is sold to PG&E under a long term contract expiring in 2020.

The acquisition of the Monterey  Project was accounted for as a purchase and the
results of operations of the Monterey  Project have been included in the Trust's
consolidated financial statements since the acquisition date. The purchase price
was allocated to the net assets acquired, based on their respective fair values.
Of the purchase  price,  $3,032,000  was  allocated to the electric  power sales
contract and is being amortized over the life of the contract (25 years).

In August 2001,  PG&E and the Monterey  Project entered into an amendment to the
electric power sales contract for a term of five years,  which would effectively
replace,  for such 5 year term, the variable  formula for determining the energy
price with a fixed energy price.  See Note 10 - Pacific Gas and Electric Company
Financial Crisis, for developments affecting the Monterey Project.

On December 31, 1998 the Trust, through subsidiaries, filed a legal complaint in
the Superior  Court of California for Monterey  County against  Waukesha-Pierce,
Inc. and  subsidiaries,  alleging  that the  subsidiaries  had not disclosed the
existence of an obligation  of the Monterey  project to Pacific Gas and Electric
Company and  therefore  breached a warranty in the  acquisition  agreement.  The
claim   was   for   approximately   $273,000   plus   interest   and   expenses.
Waukesha-Pierce, Inc. was included in the proceeding as a contractual guarantor.
On January 17, 1999, a separate action against  Waukesha-Pierce,  Inc. was filed
by the Trust's subsidiaries in the United States District Court for the Northern
District of Texas to enforce  the  guaranty.  The parties  agreed to dismiss the
Texas  case  without  prejudice  before  material  proceedings   resulted.   The
California  case was settled in March 2000;  Waukesha-Pierce  Inc. agreed to pay
the Project  approximately  $190,000  and to  cooperate  with the Project in the
potential FERC proceedings  involving the Monterey  project  discussed above and
the Trust agreed to cooperate with  Waukesha-Pierce  in releasing funds due from
PG&E to  Waukesha-Pierce.  In May 2002, the Project received settlement proceeds
of $190,306.

Pump  Services  Company,  LP (a wholly  owned  subsidiary,  known as  California
Pumping Project)
In 1995, the Trust acquired a package of natural gas and diesel  engines,  which
drive deep  irrigation well pumps in Ventura  County,  California.  The engines'
shaft  horsepower-hours  are sold to  farmers  at a  discount  from the price of
equivalent   kilowatt  hours  of  electricity.   The  operator  pays  for  fuel,
maintenance,  repair  and  replacement.  The  project  has  an  equivalent  of 2
megawatts of power.

B-3 Limited Partnership (known as the Columbia project)
On August 31,  1994,  the Trust made a limited  partnership  investment  in this
partnership,  which was  formed to  construct  and  operate  a  municipal  waste
transfer  station,  located in Columbia County,  New York. The project commenced
operations in January 1995.

In exchange for its  investment,  the Trust was  entitled to receive  annually a
preferred distribution of available net cash flow from the facility equal to 18%
of its  investment.  In the event that in any given year available net cash flow
from the  project  does not at least equal the amount of the  preferred  minimum
return,  the amount of such shortfall was payable on a priority basis out of any
available net cash flow in subsequent  years.  The Trust was also be entitled to
receive  additional  distributions  from any net cash  flow in excess of the 18%
return on its investment. The aggregate purchase price of the Trust's investment
in the partnership was $3,975,240.  The Trust received distributions of $200,000
from the  project  for each of the  years  ended  December  31,  2002 and  2001,
respectively.

Due to the  protective  rights  of the  other  partner  and in  accordance  with
Emerging Issues Task Force ("EITF") 96-16 "Investor's Accounting for an Investee
When the  Investor  Has a  Majority  of the  Voting  Interest  but the  Minority
Shareholder or Shareholders  Have Certain Approval or Veto Rights",  the Trust's
50.5%  ownership  in the B-3 Limited  Partnership  was  accounted  for under the
equity  method of  accounting.  The  Trust's  equity in the  earnings of the B-3
Project  has  been  included  in the  consolidated  financial  statements  since
acquisition in accordance with the terms in the partnership agreement.

The partnership agreement required income (loss) earned by the partnership to be
allocated and distributed to the partners as follows:
     1. Gross income is allocated as distributions  declared have been allocated
        to the partners.
     2. The  difference  between  distributions  declared and net income  before
        depreciation  is  allocated  to  the  partners   according  to
        partnership interests.
     3. Depreciation  expense  is  allocated  to  the  partners  proportionally
        according to their original capital contributions to the partnership.

On January  4, 1994,  the Trust  made a limited  partnership  investment  in the
Pittsfield  Investors  Limited  Partnership  ("PILP"),  a  facility  that  burns
municipal solid waste located in Pittsfield,  Massachusetts. The Trust wrote off
its investment in PILP in 1998.

On September 20, 2002, the Trust, sold 100% of its ownership interest in the B-3
Limited Partnership and PILP, to EAC Operations, Inc., the other limited partner
of both entities. The acquisition agreement provides for the sale of 100% of the
Trust's  ownership in the two  partnerships  in return for  $1,200,000  cash and
$5,000,000 of interest  bearing  promissory  notes. The notes bear interest at a
rate of 10% per annum,  and will be repaid monthly over a 17 year term, of which
the first two years of payments  will  consist of interest  only.  The notes are
collateralized by all the assets of the partnerships.

The purchase  price for the B-3 Project was  $3,400,000,  of which  $400,000 was
paid in cash at the time of closing. The purchase price for PILP was $2,800,000,
of which $800,000 was paid in cash at the time of closing.

Recovery of interest  and  principal  under the  promissory  notes is  dependent
solely upon the operating results of the limited  partnership  investments sold.
Consequently,  in accordance  with SEC Staff  Accounting  Bulletin Topic 5E, the
Trust has not recorded a gain on the sale of its  ownership  interest.  The cash
proceeds  received were recorded as a reduction of its investment in the limited
partnership investments and interest and principal received under the promissory
note will continue to be recorded as a reduction of the note receivable  balance
until the  carrying  value has been  reduced to zero.  In the event the divested
business incur operating losses in future periods, a corresponding  reduction in
the note receivable will be recorded as a valuation allowance.

As of September  20, 2002,  the carrying  value of the Trust's  share in the B-3
Limited Partnership,  was $1,253,016. The carrying value of the note at December
31, 2003 was $807,195.

Summarized financial information for the B-3 Limited Partnership is as follows:

Statement of Operations Information

                                     (Unaudited)           For the Year
                                     Period ended             Ended
                                    --------------         ------------
                                     September 20,         December 31,
                                         2002                 2001
                                    --------------         ------------
Revenue ...................           $4,477,725           $5,948,082
Operating expense .........            4,343,054            5,889,936
                                      ----------           ----------
Net income ................           $  134,671           $   58,146
                                      ----------           ----------

Trust share ...............           $  104,497           $   43,459
                                      ----------           ----------


4. Note Receivable from Sale of Investment

On June 25, 1997, the Trust sold its entire interest in a chilled water facility
to subsidiaries of NRG Energy, Inc. ("NRG").  As part of the consideration,  the
Trust received an 8% promissory note in the amount of $2,700,000 payable monthly
over six  years.  In 2003,  the  Trust  received  the final  payments  under the
promissory note.

5. Commitments and Contingencies

The Monterey  project has a long-term  operating ground lease. The lease expires
May 2021.

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

                            Year Ended
                            December 31,          Repayment
                            ------------          ---------
                            2004                   $ 12,396
                            2005                     12,396
                            2006                     12,396
                            2007                     12,396
                            Thereafter              165,280
                                                  ---------
                            Total                 $ 227,260
                                                  ---------

Rent expense for each of the years ended  December  31, 2003,  2002 and 2001 was
$12,396.

The Monterey project has a long-term  agreement to purchase natural gas from its
supplier at a fixed price throughout the term, which as of December 31, 2003, is
below market prices. The agreement expires in August 2006.

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

                            Year Ended
                            December 31,          Purchases
                            ------------          ---------
                            2004                  $ 893,187
                            2005                  1,365,903
                            2006                    910,602
                                                  ---------
                            Total               $ 3,169,692
                                                  ---------

In order to hedge  exposure to commodity  price risks and to maximize the impact
of the increase in natural gas prices,  the Trust entered into a master  re-sale
agreement with its supplier of natural gas to the Monterey  project.  The master
re-sale  agreement,  which  expires in August  2006,  compels  the  supplier  to
repurchase from the Trust any natural gas the Trust chooses not to take delivery
of if a  predetermined  re-sale price has been  established.  As of December 31,
2003, a re-sale price to the supplier,  in excess of the underlying  cost of the
natural gas, has been  established  for 2004. In 2003, the Trust has recorded an
unrealized gain of $487,902 in accordance with SFAS 149 utilizing re-sale prices
committed for and fair value prices for re-sale prices uncommitted for.

In  addition  to the  letter  of  credit  discussed  in Note 6,  the gas  supply
agreement is collateralized by the Monterey Projects trade accounts receivable.

6. Line of Credit Facility and Letters of Credit

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

In August 2003, the Trust issued through its bank a standby letter of credit, in
the amount of $504,000 to secure the gas purchases for the Monterey project. The
Trust used Ridgewood  Renewable  Power's credit  facility to  collateralize  the
letters of credit.

7. 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 to the
managing  shareholder an annual management fee equal to 1.5% of the prior year's
net asset value of the Trust payable  monthly.  During 2003,  2002 and 2001, the
Trust paid management fees to the managing  shareholder of $108,407 and $117,058
$177,337, 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.

Where permitted,  in the event the managing shareholder or an affiliate performs
brokering  services  in  respect of an  investment  acquisition  or  disposition
opportunity for the Trust, the managing shareholder or such affiliate may charge
the Trust a brokerage  fee. Such fee may not exceed 2% of the gross  proceeds of
any such  acquisition or  disposition.  No such fees have been incurred  through
December 31, 2003.

The managing  shareholder  owns 1.45 investor shares of the Trust with a cost of
$121,800.  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 power generation projects operated by the Trust.
Ridgewood  Management charges the project at its cost for these services and for
the allocable amount of certain overhead items.  Allocations of costs are on the
basis of  identifiable  direct  costs,  time records or in  proportion to amount
invested  in projects  managed by  Ridgewood  Management.  During the year ended
December  31,  2003,  2002 and  2001,  Ridgewood  Management  charged  Sunnyside
Cogeneration  Partners  $120,252,  $132,810  and  $153,354,   respectively,  for
overhead  items  allocated  in  proportion  to the amount  invested  in projects
managed.  During the years ended  December  31, 2003,  2002 and 2001,  Ridgewood
Management charged the California Pumping Project $21,141,  $20,973 and $77,103,
respectively,  for overhead items allocated in proportion to the amount invested
in projects managed.  Ridgewood  Management also charged Sunnyside  Cogeneration
Partners and the California  Pumping Project for all of the direct operating and
non-operating expenses incurred during the periods.

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
outstanding  payables  of  $83,148  and  $47,883,   respectively,  to  Ridgewood
Management.  At December 31, 2003 and 2002, the Trust had short-term receivables
from affiliates in the amounts of $16,628 and $14,512, respectively.

8. 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 letter of credit does not
differ materially from its carrying value.

9. Financial Information by Business Segment

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

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



<PAGE>


The financial data for business segments are as follows:


                                                     Wholesale
                                    --------------------------------------------
                                        2003            2002            2001
                                    -----------     -----------     ------------
Revenue .......................     $ 2,104,050     $ 2,122,189     $ 1,498,420
Depreciation and
  amortization ................         245,159         245,718         245,813
Operating income (loss) .......         115,945         442,677        (794,616)
Total assets ..................       4,033,297       3,838,577       4,026,379
Capital expenditures                       --              --             6,617



                                                       Retail
                                    --------------------------------------------
                                        2003            2002            2001
                                    -----------     -----------     ------------
Revenue .......................       $ 602,694       $ 952,925       $ 875,976
Depreciation and
amortization ..................         103,593         102,944         100,396
Operating income (loss) .......         (94,224)         17,289          15,544
Total assets ..................         255,984         321,862         488,289
Capital expenditures ..........            --            22,432            --



                                                     Corporate
                                    --------------------------------------------
                                        2003            2002            2001
                                    -----------     -----------     ------------
Revenue .......................     $      --        $     --        $     --
Depreciation and
  amortization ................            --              --              --
Operating loss ................        (242,909)       (533,833)       (324,482)
Total assets                          2,018,479       3,400,566       3,701,487
Capital expenditures ..........            --              --              --



                                                       Total
                                    --------------------------------------------
                                        2003            2002            2001
                                    -----------     -----------     ------------
Revenue .......................     $ 2,706,744     $ 3,075,114     $ 2,374,396
Depreciation and
  amortization ................         348,752         348,662         346,209
Operating loss ................        (221,188)        (73,867)     (1,103,554)
Total assets                          6,307,760       7,561,005       8,216,155
Capital expenditures ..........            --            22,432           6,617


10. Pacific Gas and Electric Company Financial Crisis

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

In April 2001, the Monterey  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  December  2000 and
January 2001. Costs associated with the sale of receivables of $127,130 in 2001,
primarily  related to the discount  and loss on sale,  are included in provision
for bad debt expense in the Consolidated Statements of Operations.

In August 2001,  PG&E and the Monterey  Project entered into an amendment to the
electric power sales contract for a term of five years,  which would effectively
replace,  for such 5 year term, the variable  formula for determining the energy
price with a fixed  energy  price.  Also in August 2001,  the  Monterey  Project
entered  into a five year fixed price  natural gas supply  agreement  with Coral
Energy Services, Inc., a subsidiary of Shell Oil.



<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 .................    $ 669,000    $ 607,000     $ 759,000     $ 672,000
Income (loss) from
 operations .............       18,000      (73,000)     (101,000)      (65,000)
Net income (loss) .......       24,000      (70,000)      160,000       159,000



                                                  2002
                            ---------------------------------------------------
                               First        Second        Third        Fourth
                              Quarter       Quarter      Quarter       Quarter
                            ---------      --------     ---------     ---------
Revenue ................    $ 737,000     $ 771,000     $ 900,000     $ 667,000
Income (loss) from
 operations ............      (22,000)      (17,000)       27,000       (62,000)
Net income (loss) ......      (69,000)      281,000       (23,000)       67,000



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  over  the  last 17  years  (of  which  25 have
terminated) and which had total capital contributions in excess of $190 million.
The programs  operated by Ridgewood  Energy have invested in oil and natural gas
drilling and completion and other related  activities.  Other  affiliates of the
Managing  Shareholder  include  Ridgewood  Securities  Corporation   ("Ridgewood
Securities"),  an NASD member which has been the placement agent for the private
placement  offerings of the eight trusts  sponsored by the Managing  Shareholder
and the funds sponsored by Ridgewood Energy;  Ridgewood  Capital  Management LLC
("Ridgewood  Capital"),   which  assists  in  offerings  made  by  the  Managing
Shareholder  and which is the sponsor of six privately  offered  venture capital
funds  (the  Ridgewood  Capital  Venture  Partners,  Ridgewood  Capital  Venture
Partners II and Ridgewood  Capital Venture Partners III funds);  Ridgewood Power
VI LLC ("Power VI"),  which is a managing  shareholder  of the Growth Fund,  and
RPM. Each of these  companies is  controlled by Robert E. Swanson,  who is their
sole director or manager.

     Set forth below is certain  information  concerning  Mr.  Swanson and other
executive officers of the Managing Shareholder.

     Robert E. Swanson,  age 57, has also served as Chief  Executive  Officer of
the Trust since its inception in 1991 and as Chief Executive Officer of RPM, the
Other Power Trusts and the Ridgewood LLCs,  since their  respective  inceptions.
Mr. Swanson has been President and registered  principal of Ridgewood Securities
and became the Chairman of the Board of Ridgewood Capital on its organization in
1998. He also is Chairman of the Board of the Ridgewood Capital Venture Partners
I,  II,  III and IV  venture  capital  funds  (collectively  "Ridgewood  Venture
Funds").  In addition,  he has been President and sole  stockholder of Ridgewood
Energy since its inception in October 1982. Prior to forming Ridgewood Energy in
1982,  Mr.  Swanson was a tax partner at the former New York and Los Angeles law
firm of Fulop & Hardee and an officer in the Trust and  Investment  Division  of
Morgan  Guaranty Trust  Company.  His specialty is in personal tax and financial
planning,  including income, estate and gift tax. Mr. Swanson is a member of the
New York State and New Jersey bars,  the  Association  of the Bar of the City of
New York and the New York State Bar  Association.  He is a  graduate  of Amherst
College and Fordham University Law School.

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

     Robert L. Gold,  age 45,  has served as  Executive  Vice  President  of the
Managing  Shareholder,  RPM, the Trust, the Other Power Trusts and the Ridgewood
LLCs since their  respective  inceptions.  He has been  President  of  Ridgewood
Capital  since  its  organization  in 1998.  As  such,  he is  President  of the
Ridgewood  Venture Funds. He has served as Vice President and General Counsel of
Ridgewood Securities  Corporation since he joined the firm in December 1987. Mr.
Gold has also served as  Executive  Vice  President  of  Ridgewood  Energy since
October 1990. He served as Vice President of Ridgewood Energy from December 1987
through  September 1990. For the two years prior to joining Ridgewood Energy and
Ridgewood Securities  Corporation,  Mr. Gold was a corporate attorney in the law
firm of Cleary, Gottlieb, Steen & Hamilton in New York City where his experience
included mortgage finance,  mergers and acquisitions,  public offerings,  tender
offers,  and other business legal matters.  Mr. Gold is a member of the New York
State bar. He is a graduate of Colgate University and New York University School
of Law.

     Daniel V. Gulino,  age 43, is Senior Vice President and General  Counsel of
the Managing Shareholder,  RPM, Ridgewood Capital, the Trust, Other Power Trusts
and the  Ridgewood  LLCs.  He began his legal career as an associate for Pitney,
Hardin, Kipp & Szuch, a large New Jersey law firm, where his experience included
corporate acquisitions and transactions.  Prior to joining Ridgewood, Mr. Gulino
was in-house counsel for several large electric utilities,  including GPU, Inc.,
Constellation Power Source,  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, is 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, the Other Power Trusts, and the
Ridgewood LLCs since their  respective  inceptions.  She has also served as Vice
President of Ridgewood  Energy since October 1984, when she joined the firm. Her
primary  areas of  responsibility  are investor  relations,  communications  and
administration.  Prior to her  employment  at Ridgewood  Energy,  Ms. Olin was a
Regional  Administrator  at McGraw-Hill  Training Systems where she was employed
for two years. Prior to that, she was employed by RCA Corporation.  Ms. Olin has
a Bachelor of Arts degree from Queens College.

(c) Management Agreement.

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

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

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

     Each  Investor  consented  to the  terms  and  conditions  of  the  initial
Management Agreement by subscribing to acquire Investor Shares in the Trust. The
Management Agreement is subject to amendment by the parties with the approval of
a majority in interest of the Investors.

(d) Executive Officers of the Trust.

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

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

     (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

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


      (g) RPM.

     As  discussed  above  at  Item 1 -  Business,  RPM has  assumed  day-to-day
management  responsibility  for the Monterey Project,  effective January 1, 1996
and  operating  responsibility  for the Pumping  Project in October 1998 and had
assumed certain  responsibilities  for the San Diego Project in early 1997 until
its sale. Like the Managing Shareholder, RPM is controlled by Robert E. Swanson.
It has  entered  into an  "Operation  Agreement"  with  certain  of the  Trust's
subsidiaries,  effective January 1, 1996, under which RPM, under the supervision
of the Managing Shareholder, provides the management,  purchasing,  engineering,
planning and  administrative  services for those  Projects that were  previously
furnished  by  employees  of  the  Trust  or by  unaffiliated  professionals  or
consultants and that were borne by the Trust or Projects as operating  expenses.
To the extent that those services were provided by the Managing  Shareholder and
related  directly to the operation of the Project,  RPM charges the Trust at its
cost for these services and for the Trust's allocable amount of certain overhead
items.  RPM shares space and facilities  with the Managing  Shareholder  and its
Affiliates.  To the extent that common  expenses can be reasonably  allocated to
RPM, the Managing  Shareholder  may, but is not required to,  charge RPM at cost
for the allocated  amounts and such allocated amounts will be borne by the Trust
and other  programs.  Common expenses that are not so allocated are borne by the
Managing Shareholder.

     The Managing  Shareholder  does not charge RPM for the full amount of rent,
utility  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; all 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,  although it may be  authorized  to act on behalf of the  subsidiaries
that own Projects.

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

     The  executive  officers  of RPM are  the  same as  those  of the  Managing
Shareholder 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 10U.

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

     The  Managing  Shareholder  purchased  for cash of $121,800 in the offering
1.45 Investor Shares (.6 of 1% of the outstanding Investor Shares). The Managing
Shareholder  was  issued  one  Management  Share in the Trust  representing  the
beneficial  interests and management  rights of the Managing  Shareholder in its
capacity as such  (excluding its interest in the Trust  attributable to Investor
Shares it acquired  in the  offering).  Additional  information  concerning  the
management  rights of the  Managing  Shareholder  is at Item 1 - Business and at
Item 10 -- Directors and Executive  Officers of the  Registrant.  Its beneficial
interest  in cash  distributions  of the  Trust and its  allocable  share of the
Trust's  net  profits  and  net  losses  and  other  items  attributable  to the
Management  Share are  described  in further  detail  below at Item 13 - Certain
Relationships and Related Transactions.

Item 13.  Certain Relationships and Related Transactions.

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

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

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

     In 2003 and  2002,  as stated at Item 5 - Market  for  Registrant's  Common
Equity and Related  Stockholder  Matters,  as well as in prior years,  the Trust
made  distributions to the Managing  Shareholder (which is a member of the Board
of the Trust) 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

Managing
Shareholder         $108,407  $117,058   $177,727  $   -0-      $55,607
RPM Cost
Reimbursements     2,486,469 2,862,273  2,955,915  3,032,954  2,841,952

     The management fee,  payable monthly under the Management  Agreement at the
annual rate of 2.5% of the Trust's prior year net asset value, began on the date
the first  Project was acquired and  compensates  the Managing  Shareholder  for
certain  management,  administrative  and advisory services for the Trust. Under
the  Declaration  of Trust,  the  annual  rate  fell to 1.5% per year  beginning
February 1, 1999.  Beginning April,  1999, the Managing  Shareholder  waived the
fee.  Effective January 1, 2001, it resumed payment of the management fee at the
1.5% of net asset value annual rate.

     In addition to the foregoing, the Trust reimbursed the Managing Shareholder
at cost for expenses and fees of  unaffiliated  persons  engaged by the Managing
Shareholder  for Trust  business.  Payroll and other costs of  operation  of the
Trust's Projects are reimbursed to RPM. The  reimbursements to RPM, which do not
exceed its actual costs and  allocable  overhead,  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  $20,000 and $32,000,
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  $25,000. There were
no tax  services  rendered  by  PricewaterhouseCoopers  LLP for the years  ended
December 31, 2003 and 2002. Tax services principally include tax compliance, tax
advice and planning  (including  foreign tax  services,  as well as tax planning
strategies for the preservation of net operating loss carryforwards).

     Audit Related Fees

     None.


     All Other Fees

     None.

PART IV

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

The following documents are filed as part of this report:

(a) Financial Statements.

     See the Index to Financial Statements in Item 8 hereof.

(b) Reports on Form 8-K.

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


(c)  Exhibits

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

      10S.  Master Sale Agreement, dated August 8, 2001, by and between
            Sunnyside Cogeneration Partners, L.P. and Coral Energy
            Resources, L.P. (the terms of the actual transaction are
            subject to confidentiality provisions).

      10T.   Acquisition Agreement, dated September 20, 2002, by and
             between the Trust and EAC Operations, Inc.

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

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

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




<PAGE>


SIGNATURES

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


RIDGEWOOD ELECTRIC POWER TRUST II (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
II ("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 II ("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