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, 2000

                         Commission file number 0-23432

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

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

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

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

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

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

Shares of Beneficial Interest(Title of Class)

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

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

         There is no market for the Shares. The aggregate capital  contributions
made for the Registrant's voting Shares held by non-affiliates of the Registrant
at March 30, 2001 was $39,034,440.

Exhibit Index is located on page 40.
<PAGE>

PART I

Item 1.  Business.

Forward-looking statement advisory

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

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

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

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

(a)  General Development of Business.

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

         The Trust sold whole and  fractional  shares of beneficial  interest in
the Trust ("Investor Shares") at $100,000 per Investor Share, and terminated its
private  placement  offering  on May 31,  1995,  at  which  time  it had  raised
approximately $39.2 million. Net of Offering fees, commissions and expenses, the
Offering  provided  approximately  $32.9  million  of net  funds  available  for
investments  in the  development  and  acquisition  of Projects  and  associated
expenses. The Trust has 764 record holders of Investor Shares (the "Investors").
As described below in Item 1(c)(2), the Trust has invested  substantially all of
its net funds in the Projects.

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

         The Trust is organized  similarly to a limited  partnership.  Ridgewood
Power LLC (the "Managing Shareholder"),  a Delaware corporation, is the Managing
Shareholder of the Trust. For information about the merger of the prior Managing
Shareholder,  Ridgewood  Power  Corporation,  into Ridgewood Power LLC, see Item
10(b)  -  Directors  and  Executive   Officers  of  the  Registrant  -  Managing
Shareholder.

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

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

         The following summarizes some of these relationships.

         Robert E.  Swanson and certain  Swanson  family  trusts own 100% of the
equity of the following entities:

o Ridgewood Securities Corporation - Placement Agent ("Ridgewood Securities");
o Ridgewood Power Management, LLC - Operates the Projects owned by the Trust and
six other trusts ("RPM");
o  Ridgewood  Power  LLC -  Managing  Shareholder  of seven  trusts  ("Ridgewood
Power");
o Ridgewood Energy Holding  Corporation - Corporate  Trustee for all six trusts;
and
o Ridgewood  Capital  Management LLC - A marketing  affiliate and manager of six
venture capital funds ("Ridgewood Capital").

         Mr.  Swanson  has sole  voting and  investment  power over the  Swanson
family trusts and is also the sole manager, chief executive officer of the above
entities.

         In  addition,  the  Trust  is  affiliated  with  the  following  trusts
organized by the Managing Shareholder:

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

(b)  Financial Information about Industry Segments.

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

(c)  Narrative Description of Business.

(1)  General Description.

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

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

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

(2)  The Trust's Investments.

(i)  San Joaquin Project and Byron Project.

         On January 17,  1995,  the Trust and RW Central  Valley,  Inc., a newly
formed  California  corporation,  which is wholly  owned by the Trust  ("Central
Valley"), acquired 100% of the existing partnership interests of JRW Associates,
L.P.  ("JRW"),  a  California  limited  partnership  which owns and  operates an
approximately 8.53 megawatt electric  cogeneration  facility located in the City
of Atwater,  Merced  County,  California  (the "San  Joaquin  Project").  At the
closing, the JRW partnership  agreement was amended and restated so that Central
Valley  became the sole  general  partner  of JRW with a 1% general  partnership
interest and the Trust became the sole limited partner of JRW with a 99% limited
partnership  interest.  The aggregate cash purchase price paid by Central Valley
and the Trust for 100% of the JRW partnership interests was $5,300,000.

         The San Joaquin  Project has been operating since 1991 and uses natural
gas fired reciprocating  engines to generate electricity for sale to Pacific Gas
and Electric Company  ("PG&E") under a long term contract  expiring in 2020 (the
"Power  Contract").  Thermal  energy  from the San  Joaquin  Project  is used to
provide steam to an adjacent food  processing  company under long term contracts
that also terminate in 2020.

         Also in January 1995,  the Trust formed Byron Power  Partners,  L.P., a
California  limited  partnership (the  "Partnership") in which RW Byron, Inc., a
California  corporation  which is wholly  owned by the Trust,  owns a 1% general
partner  interest  and the Trust owns a 99%  limited  partnership  interest.  On
January 17, 1995, the  Partnership  acquired  through a merger all of the assets
and business of Altamont  Cogeneration  Corporation,  including an approximately
5.7-megawatt  electric  cogeneration  facility  located  near the city of Byron,
Alameda County,  California (the "Byron Project").  The total investment made by
the Trust was $3,138,000.

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

         Both the San  Joaquin  and Byron  Projects  are  Qualifying  Facilities
pursuant  to the Public  Utility  Regulatory  Policies  Act of 1978,  as amended
("PURPA").  Historically,  producers  of  electric  power in the  United  States
consisted of regulated  utilities  serving end-use retail  customers and certain
industrial  users that  produced  electricity  to satisfy  their own needs.  The
independent  power  industry  in  the  United  States  was  created  by  federal
legislation  passed in response to the energy crises of the 1970s.  PURPA, among
other things,  requires  utilities to purchase  electric  power from  Qualifying
Facilities, including "cogeneration facilities" and "small power producers," and
also exempts  these  Qualifying  Facilities  from most federal and state utility
regulatory requirements. In addition, the price paid by electric utilities under
PURPA for electricity produced by Qualifying Facilities is the utility's avoided
cost of producing  electricity  (i.e.,  the incremental  costs the utility would
otherwise  face to  generate  electricity  itself or purchase  electricity  from
another source).  Pursuant to PURPA,  and state  implementation  of PURPA,  many
electric utilities have entered into long-term power contracts with rates set by
contract formula approved by state regulatory  commissions.  The San Joaquin and
Byron  Projects  entered into such  contracts with PG&E. The capacity and energy
price paid by PG&E pursuant to the Power Contracts were determined pursuant to a
contract formula approved by the California Public Utilities Commission ("CPUC")
with the energy payment  originally based upon a benchmark energy price adjusted
for changes  over time in a gas index;  the so called  "Short Run  Avoided  Cost
Methodology"  or SRAC.  Historically,  the contract  formula rates in most Power
Contracts have been significantly higher than the rates the utility could obtain
in a  competitive  market.  In some areas of the country this still may be true.
However, beginning during the summer of 2000 in California,  where the Byron and
San Joaquin Projects are located, due to the electric energy crisis, competitive
market rates were significantly  higher than the formula rates contained in many
Qualifying Facilities Power Contracts.

         The  deregulation  legislation  in  California  passed in 1996  allowed
Qualifying  Facilities  to  exercise  a one-time  option to elect to  thereafter
receive  energy  payments  based on the energy  clearing price on the California
Power Exchange ("CalPx"), a short term day-ahead and day-off energy spot market,
which was created by the  deregulation  legislation.  On September 1, 2000, both
the San Joaquin and Byron Projects  exercised such option and switched from SRAC
payment methodology to the CalPx energy clearing price. Thus, the energy payment
earned by the Projects subsequent to the election was significantly  higher than
the energy payment incorporated in the SRAC formula. However,  subsequent events
in California,  including certain orders issued by the Federal Energy Regulatory
Commission  ("FERC") have caused the CalPx to suspend  trading as of January 31,
2001 such that no CalPx "energy  clearing price"  currently  exists.  Therefore,
even though the San Joaquin  and Byron  Projects  are  currently  off-line  (see
below), the energy price that PG&E would pay the Projects if currently operating
is  unclear.  See Item 1(c)4 for further  discussion  regarding  current  issues
raised by California's electricity crises.

         Currently, and as a result of the deregulation of the California energy
market,  PG&E has  allegedly  suffered  billions of dollars in losses during the
latter  part of  2000  and to date in 2001  and is  teetering  on the  brink  of
bankruptcy.  This  has  resulted  in part  because  PG&E,  like  the  other  two
investor-owned  electric utilities  ("IOUs") in California,  was required by the
1996  deregulation  law  to  sell  50% of its  fossil-fuel  electric  generation
resources  located in California to  unaffiliated  third parties,  although PG&E
sold more than such 50% amount. In addition, the law required that PG&E sell all
the electricity  produced by its remaining electric generation resources to, and
purchase all of its  electric  energy  needs from,  the CalPX.  During the early
years of  deregulation,  this framework  worked well and was profitable for PG&E
because  the  wholesale  price  of  electricity  purchased  from the  CalPx  was
substantially  lower than the  "frozen"  retail price of  electricity  that PG&E
charged its end-use customers. The difference between the two prices was used by
PG&E to recoup  stranded  investments  and pay  dividends  to its  parent,  PG&E
Corporation,  which dividends were then invested in unregulated subsidiaries and
used for other corporate purposes. However, beginning in the summer of 2000, due
to explosive growth of power consumption in California, the lack of new electric
generation,  water and fuel shortages,  and other reasons, the situation changed
dramatically and the CalPx price for electricity was  substantially  higher than
the  retail  price that PG&E was  permitted  by law to  charge.  Therefore,  the
difference  between what PG&E paid for electricity and what it could resell such
electricity for resulted in huge losses. See, Section 4 - Trends in the Electric
Utility and Independent Power Industries.

         PG&E has been unable to pay in full for electrical  energy and capacity
delivered in December  2000 and January 2001.  Accordingly,  the San Joaquin and
Byron  Projects  were  unable  to pay their  natural  gas  supplier  for the gas
delivered  for  those  months.  In  late  January,  the gas  supplier  requested
assurance  of  payment  before it would  agree to  provide  natural  gas  during
February.  The Projects were unable 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.  A  number  of other  small  cogeneration  projects  selling
electrical energy and capacity to California utilities have similar problems and
have shut down or expect to shut down their facilities shortly.

         On February 1, 2000,  PG&E made a partial  payment  equal to 15% of the
amount due for  December  2000.  On March 5,  2001,  PG&E made  another  partial
payment  equal to 15% of the amount due for  January  2001.  Those  amounts  are
insufficient  to cover the amount owed to the natural gas supplier.  On Tuesday,
February 6, 2001, the Trust shut down the San Joaquin and Byron Projects because
the supplier of natural gas to the Projects terminated deliveries of natural gas
as of that date. The shut down will be for an indefinite period of time.

         In addition to its failure to pay the full amount due for  December and
January  deliveries,  PG&E has indicated in letters to the Projects,  as well as
documents filed with the Securities and Exchange  Commission,  that it is unable
or unwilling to make full future payments to Qualifying Facilities,  such as the
San Joaquin and Byron  Projects.  The Trust  believes that PG&E's ability to pay
for the  electrical  energy and  capacity  it  received  or will  receive in the
future,  depends upon,  among other things,  positive  action by the  California
governor and legislature to fund  approximately  $12 billion of losses allegedly
suffered by California utilities during the last eight months. The Trust expects
that any such political solution may be accompanied by executive, legislative or
regulatory  attempts  to  reduce  unilaterally  the  amounts  owed  by  PG&E  to
Qualifying Facilities. In an effort to resolve the California crises, there have
been  numerous  proposals  by the CPUC,  as well as the  legislature,  to adjust
downward the prices paid by California utilities to Qualifying  Facilities.  The
Trust expects that any regulatory  proceeding to set an energy price  applicable
to Qualifying  Facilities  will be extremely  protracted  and that a legislative
solution,  if one were to be enacted and approved by the governor,  is likely to
be arbitrary and significantly below the avoided cost of the energy to PG&E.

         Finally,  PG&E has attempted to justify its non-payment by invoking the
"force majeure" provisions of the Power Contracts.  In essence, PG&E argues that
it is excused  from its  payment  obligations  because its failure to pay is the
result of the  California  Public  Utilities  Commission  actions  in failing to
increase  its rates to retail  customers  and is beyond its  control.  The Trust
disagrees  and  believes  that PG&E has breached  the Power  Contracts.  The San
Joaquin and Byron Projects,  along with the Monterey  Project owned by Power II,
filed a lawsuit on February 6, 2001  against PG&E to that effect and are seeking
damages  equal  to lost  net  revenues  for  the  remaining  term  of the  Power
Contracts. By this lawsuit the Trust seeks to have the Power Contracts with PG&E
declared  null and void so that both the San Joaquin and Byron  Projects will be
able to sell its electric power on the open market to third party purchasers who
will be able to pay currently for such electric power. The Trust expects that it
will be able to purchase  natural gas if it is free from the PG&E  contract  and
able to sell to credit worthy  purchasers.  The Trust is seeking an  accelerated
determination by the California  court. The Trust is hopeful that an accelerated
determination  by the court is a possibility  considering the power emergency in
California,  which may get worse as warm  weather  approaches  and power  demand
increases  dramatically.  Also,  in an attempt to get the Projects  back on-line
quickly, on March 8, 2001, the Managing Shareholder,  on behalf of the Trust and
Power II,  filed with FERC a "Request  For  Emergency  Relief and  Extension  Of
waiver OF Qualifying  Facility  Regulations"  in which the Managing  Shareholder
likewise  seeks an order for FERC  permitting  Qualifying  Facilities to sell to
third parties.

         See Item  1(a)(3) - Project  Operations,  Item  1(c)(4) - Trends in the
Electric and Independent Power Industries,  and Item 3 - Legal Proceedings below
for  additional  information  concerning  the potential  effect of  California's
electric energy crises and the litigation proceedings against PG&E.

(ii)  On-site Cogeneration Projects

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

         Returns from the On-site Cogeneration  Projects have deteriorated since
their  purchase and  beginning in the third quarter of 1997 the Trust has closed
the  majority  of the  Projects  due to  unprofitability  or because of contract
expirations. Because of closures and contract expirations, the Trust has written
down the value of its investment from $3.7 million to $1.1 million.

         The  Massachusetts  Projects include the Globe Project,  a 3.5 Megawatt
turbine  with backup  diesel  engines,  located at a Fall  River,  Massachusetts
facility owned by Globe  Manufacturing Corp.  ("Globe").  In October 1999, Globe
claimed that the Globe Project was unreliable and cancelled the Power  Contract.
As a result,  the Globe Project  ceased  operation on October 8, 1999. The Trust
believes that Globe's claims are exaggerated and that any service  interruptions
were caused by Globe's own actions.  The Trust brought suit in Federal  District
Court in  Massachusetts  against the Globe in October 1999, as described at Item
3,  Legal  Proceedings,  for a $4 million  termination  payment.  Discovery  and
certain  other  pre-trial  matters took place during 2000.  On January 13, 2001,
Globe filed a voluntary  petition for bankruptcy in the United States Bankruptcy
Court for the Northern District of Alabama,  where Globe is headquartered.  As a
result of such filing, the Trust's litigation in Massachusetts was closed by the
District  Court in  Massachusetts  without  prejudice  to restore it pending the
termination  and outcome of the  bankruptcy  proceeding.  According to documents
filed  with the  Bankruptcy  Court,  Globe has  entered  into an Asset  Purchase
Agreement  to sell  substantially  all of its assets,  including  the Fall River
facility.  The  Asset  Purchase  Agreement  and the  terms of the  sale  must be
approved by the Bankruptcy Court. Such approval has not yet occurred,  but it is
likely that no other offers will be  forthcoming  and the sale will be approved.
The Power  Contract  that the Trust has with Globe has been rejected by Globe in
the  Bankruptcy  Court  proceedings.  Effectively  the Power  Contract  has been
terminated and the Trust has "rejection" damages claims against Globe, but given
Globe's financial  condition it is not likely that significant  amounts of money
will be available to pay such rejection damages. The Trust has made contact with
the proposed purchaser of the Globe assets and is hopeful that a new contractual
arrangement  can be negotiated  such that the Trust can sell power to either the
new purchaser,  pursuant to the same or renegotiated  Power Contract,  or to the
wholesale  market.  There is a  possibility  that the new  purchaser  will close
and/or  sell the  Fall  River  facility.  In such  event,  the  Globe  Project's
equipment may have to be removed from the Fall River site at significant cost.

         The  Coca-Cola  Project is located  at a  bottling  plant of  Coca-Cola
Bottling  Company of New York at Elmsford,  New York and has a rated capacity of
1.3 Megawatts with a .6 Megawatt  standby  diesel  generator set. The Project is
profitable but is not meeting  projections  because the bottling  plant's demand
for heat has decreased  and because of design  defects in the Project which make
it incapable of avoiding a large  portion of the bottling  plant's  charges from
the local utility.  The Coca-Cola project was off-line for a substantial portion
of 2000 due to the  extremely  high costs of natural  gas,  the fuel used by the
Project,  although steam sales continue.  The Trust anticipates,  however,  that
natural  gas prices  will  stabilize  and/or  decrease  such that the  Coca-Cola
Project will resume production during the summer months of 2001.

         The Rhode  Island  Project  was  located at a textile  manufacturer  in
Centerdale,  Rhode Island and had a rated  capacity of 4.2 Megawatts  from three
natural-gas  fired  engines.  The Trust sold the  Project in  December  1997 for
$900,000 and the Trust recorded a loss of $2,752,000 in that year.

         The  remaining 31 On-site  Cogeneration  Projects,  all of which are or
were  natural-gas-fueled,  were  located in  California  and New York and had an
aggregate  rated  capacity  of 5.5  Megawatts.  In 1997 the  Trust  discontinued
operation  of and wrote off 15 Projects (4 Projects  had been  discontinued  and
written off in 1996) with a rated capacity of 2.1 Megawatts in this group, for a
total of $4.8 million.  After further  review in 1998,  the Trust wrote down the
value of the  remaining 12 Projects by an  additional  $4.1  million.  The Trust
received an arbitration award of $2.6 million against EUA for misrepresentations
made by EUA as to the condition of certain of the On-Site Cogeneration  Projects
and other misrepresentations.  Like the Coca-Cola Project, many of the remaining
On-Site Cogeneration Projects that have not been discontinued have been idle for
much of 2000  due to the high  costs  of  natural  gas.  However,  many of these
Projects are still producing steam for sales to thermal hosts.

         Management  responsibility  for the On-site  Cogeneration  Projects was
substantially  transferred  to the  Managing  Shareholder  and  Ridgewood  Power
Management Company at the end of 1995. In April 1999, Ridgewood Power Management
Company was merged into a  newly-formed  limited  liability  company,  Ridgewood
Power Management LLC ("RPM"). See Item 10 -- Directors and Executive Officers of
the Registrant.

 (iii) Ridgewood/AES Power Partners, LLC.

     Instead of operating eight of the smallest  On-Site  Cogeneration  Projects
located in New York and  Connecticut  itself or through RPM,  the Trust  engaged
AES-NJ Cogen, Inc., a small operator of cogeneration plants in that area ("AES")
that is not  affiliated  with the  Trust to  operate  them  under  contract.  In
September  1997 the Trust and AES created a joint venture,  Ridgewood/AES  Power
Partners,  L.P.  ("Ridgewood  AES") to  develop  additional  small  cogeneration
projects in the New York  metropolitan  area. The Trust supplies capital and AES
supplies  development  services.  At December 31, 2000  Ridgewood AES owned five
cogeneration  projects at hotels and  hospitals  in New York and New Jersey.  At
December 31, 2000 the Trust's total investment was $561,000.

         In January 1999 the Trust transferred five small cogeneration  projects
with a total  electric  capacity of .4 Megawatts to Ridgewood AES. In connection
with  that  contribution,  AES  agreed  to a  reduction  of  its  operating  and
maintenance fee to 1.1 cents per kilowatt-hour.  During 2000, the Massapequa and
Great Gorge  cogeneration  projects were shutdown due to the  bankruptcy  and/or
financial  difficulties  of the host  facility.  The  trust  recorded  a loss of
$322,500 in 2000 to reduce the book value of the project to zero.

(v)  Ridgewood El Segundo, LLC

     In April 1998,  the Trust  purchased  an  additional  cogeneration  project
located at a food preparation facility for the Los Angeles International Airport
from a private  developer.  The project is located within one mile of an On-Site
Cogeneration  Project  also  owned  by the  Trust  at  the  Airport.  The  total
investment  was $763,000 at December 31, 1999.  During much of 2000, the project
was idle due to the high costs of natural  gas.  In the fourth  quarter of 2000,
the Trust  determined that it would be unlikely to recover its investment in the
project and recorded a writedown to reduce the book value of the  investment  to
zero.

(vi)  Providence Project

         The  Trust  and  Power  IV  acquired  in April  1996 all of the  equity
interest in the Providence State Landfill Power Plant,  located near Providence,
Rhode  Island.  The Trust  invested  $7.1  million in the  Project  and Power IV
supplied  the  remainder  of the $20  million  investment  in the  Project.  The
acquisition cost was approximately $15.5 million (including a $3 million partial
prepayment of Project debt as a condition of obtaining the lenders' consents and
transaction  costs)  and  the  remainder  of  the  investment  by  the  programs
represents funds applied to operating reserves, working capital and reserves for
capital  improvements and expansion.  The Project was encumbered by $5.4 million
of debt maturing in  installments  through  2004.  As of December 31, 2000,  the
total investment was $7,494,000.

         The Project  burns  methane gas (the major  component  of natural  gas)
generated  by the  decomposition  of garbage in the  landfill as fuel for a 13.8
Megawatt capacity electric  generation plant. The facility has been in operation
since 1990 and has a Power  Contract for 12.0  Megawatts  with New England Power
Company with a 20 year term remaining.

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

         In order to increase  output to the maximum and to allow  engines to be
rotated  off-line  for  preventative  maintenance,   an  additional  engine  and
generator  set were  installed  at the  Project in spring  1997.  Although  this
increased nominal Project capacity to 13.8 megawatts,  the actual benefit is the
ability  to have one  engine  off-line  at any time for  maintenance  and  still
produce  the entire 12.0  Megawatts  that can be sold under the  existing  Power
Contract.

(vii) Mobile Power Units

         In August  1999 the Trust  purchased  five  Caterpillar  unified  power
modules (the "Mobile  Power  Units") for  $1,696,000.  The Units combine a large
diesel engine with a fuel tank,  emission  equipment,  an electric generator and
control equipment on a single skid and therefore can be moved to remote areas as
a  self-contained  power plant. The owner of the Units is Ridgewood Mobile Power
III, LLC, a  wholly-owned  subsidiary  of the Trust.  The Trust bought the Units
from Hawthorne Power Systems,  Inc.  ("Hawthorne")  of San Diego,  California (a
Caterpillar  distributor).  Hawthorne added the Units to its own rental fleet of
similar  equipment and rents them to  contractors,  engineering  firms and other
industrial or commercial  customers who need emergency,  temporary or peak power
supplies.  The Trust receives 80% of the net rental  revenues and is responsible
for major  maintenance;  Hawthorne  receives  20% of the net rental  revenues to
compensate  it for marketing  and managing the rentals.  For 2000 and 1999,  the
Trust earned $317,000 and $89,000, respectively, of net revenue from the Units.

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

(3)  Project Operation.

         Revenue from the San Joaquin,  Byron and Providence  Projects primarily
comes  from Power  Contracts  with the local  electric  utilities.  The  pricing
provisions of these Power  Contracts have two  components,  energy  payments and
capacity  payments.  Energy  payments  are based on a  facility's  net  electric
output,  with payment rates usually  indexed to the fuel costs of the purchasing
utility or to general inflation indices. Capacity payments are based on either a
facility's net electric output or its available capacity. Capacity payment rates
vary over the term of a Power Contract according to various schedules.

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

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

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

         The  Managing  Shareholder  accordingly  has  organized  RPM to provide
operating management for facilities operated by its investment programs, and has
assigned  day-to-day  management  of all of its  Projects,  other  than 8  small
cogeneration  Projects  located in New York, New Jersey and Connecticut that are
operated  by  Ridgewood  AES, to RPM.  See Item 10 --  Directors  and  Executive
Officers  of the  Registrant  and Item 13 -- Certain  Relationships  and Related
Transactions for further information  regarding the Operation Agreement with RPM
and for the cost reimbursements received by RPM.

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

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

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

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

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


                                           Calendar year
                                   2000           1999          1998
Pacific Gas & Electric Co.
 (San Joaquin & Byron Projects)     43%           47%           56%
New England Electric System
 (Providence Project)               27%           29%           20%
Globe Manufacturing Co.
 (Massachusetts Projects)            -             8%           12%

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

         Generally,  working capital  requirements are not a significant item in
the independent power industry.

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

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

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

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

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

         In September 1996,  California  enacted Assembly Bill 1890 ("AB 1890"),
which totally restructured  California's  existing monopolistic electric utility
industry into a market-based  competitive industry.  Among other things, AB 1890
required that California's  investor-owned  utilities ("IOUs") sell 50% of their
fossil-fueled  electric  generation assets to unaffiliated  thirds parties.  The
money  received  for these  assets was used,  among  other  purposes,  to reduce
stranded  investments.  The IOUs,  however,  were  permitted  to retain  certain
generation  assets,  including  generation from Qualifying  Facilities,  certain
hydroelectric  generation  facilities,  fossil-fueled  generation  not sold, and
nuclear generation facilities ("IOU Retained Generation").  In addition, AB 1890
created the CalPx, a day-ahead and day-of energy spot market,  and required that
the IOUs sell all of the electric  generation from their IOU Retained Generation
to, and  purchase  all of their  electric  supply  needs  from,  the  CalPx.  In
addition,  the rates that the IOUs were permitted to charge their retail end-use
customers were frozen at certain levels until the end of the transition  period,
which for PG&E was expected to be in approximately 2003.

         From the passage of AB 1890 until approximately the summer of 2000, the
framework  instituted  by AB 1890  worked well in that the  wholesale  price for
electricity   purchased   from  the  CalPx  by  PG&E  and  the  other  IOUs  was
significantly  lower than the frozen  retail  rates that PG&E was  permitted  to
charge to retail customers.  The resulting "profit" made by PG&E was used, among
other things,  to recoup  PG&E's  stranded  investments  and to pay dividends to
PG&E's corporate parent,  PG&E Corporation ("PG&E Corp.").  PG&E Corp. then used
such  funds  to  invest  in  unregulated  assets  as well as for  other  general
corporate  purposes.  However,  during the summer of 2000 the situation  changed
dramatically.  The CalPx wholesale price of electricity increased  significantly
due in  large  part to  California's  explosive  growth  in  power  consumption,
environmental regulation, natural gas shortages, the failure of the state to add
any significant  electric generation  facilities for over a decade, and the lack
of  available  electric  energy  from  other  areas  of the  West.  PG&E was now
purchasing its electric generation needs at wholesale prices significantly above
the  frozen  retail  rates  it was  permitted  by AB 1890 to  charge  to  retail
customers.  As a result, PG&E has incurred  substantial losses and, as described
above, has suspended payments to Qualifying Facilities,  as well as to the CalPx
and other  creditors.  Unless some resolution is worked out, PG&E may ultimately
declare bankruptcy. In such event, the Power Contract with PG&E would be subject
to modification or rejection and given the situation in California  there can be
no assurance that PG&E will not declare bankruptcy.

         There have been  numerous  proposals  and actions taken by a variety of
parties in California in an attempt to find a reasonable  and workable  solution
to the electric crises. For example,  FERC removed the requirement that the IOUs
purchase all of their electricity needs from the CalPx. In addition, a wholesale
rate soft cap or  "breakpoint"  of $150 Mwh has been  imposed by FERC,  however,
most believe it is a short-term  measure as such cap may provide a  disincentive
to the  construction of new power plants and transmission  facilities.  Although
the market cap is a short-term solution,  there is a reasonable probability that
such wholesale rate caps may be continued for an indefinite  period of time. The
CalPx was unable to institute and operate under the $150 Mwh breakpoint  and, as
a result of this and certain other FERC orders,  suspended trading as of January
31, 2001.

         The IOUs in  California  have also  sought to remedy  the  problems  by
seeking regulatory and legal relief from the losses they have incurred. PG&E and
Southern  California  Edison  Company  ("SCE") each  petitioned the CPUC seeking
relief from the rate retail rate freeze and an increase of approximately  30% in
retail rates.  The CPUC approved  only a 10% increase,  significantly  less than
requested and far below what was  necessary for PG&E and SCE to remain  solvent.
PG&E and SCE have also  instituted  separate  court actions  seeking to have the
court rule that the high  wholesale  power costs they have incurred in obtaining
power for their  retail  load must by law be  allowed  to be passed  through  to
retail rate payers.

         In  addition,  the CPUC gave IOUs  permission  to enter into  long-term
bilateral power contracts with independent energy producers  ("IPPs").  However,
due to PG&E's failure to make payments to the CalPx for past energy  deliveries,
which in turn meant that the CalPx could not pay such IPPs, many large IPPs were
reluctant to make  further  energy  deliveries  to the CalPx or directly to PG&E
without  being  paid for past  deliveries  and  receiving  assurances  of future
payments.  PG&E  could do  neither  and  during the later part of 2000 and early
2001,  such IPPs were  ordered  either by the  Secretary  of the  United  States
Department of Energy or by the federal courts to continuing selling power. These
orders  essentially  required  the  IPPs  to  sell to the  CalPx,  prior  to its
suspension of trading,  the California  Independent  System  Operator,  which is
still operating,  but primarily to the California  Department of Water Resources
("DWR"),  a state agency that has been  purchasing  power at wholesale from IPPs
(but not from Qualifying Facilities) and reselling it to the IOUs at prices that
approximate the IOUs retail rate  authorization,  which is  significantly  lower
that the wholesale price. As a result,  the California DWR is losing substantial
sums of money such that approximately every month the California legislature has
to  appropriate  more funds for the DWR to  continue  purchasing.  None of those
orders forcing electric sales, however, applied to Qualifying Facilities.

         Finally,  the  California  legislature  has  been  considering  certain
proposals to substitute an arbitrarily  derived price for the energy price to be
paid to Qualifying Facilities.  Any regulatory proceeding to set an energy price
applicable  to  Qualifying   Facilities  will  be  extremely  protracted  and  a
legislative solution, if one were to be enacted and approved by the governor, is
likely to be  arbitrary  and below the  avoided  cost of the energy to the IOUs.
Because  federal law requires  that  Qualifying  Facilities be paid at least the
avoided  cost to IOUs of  obtaining  the same  amount of energy  from a marginal
supplier,  if the energy price set by California is less than that avoided cost,
Qualifying  Facilities  will have the right to sue for the correct  avoided cost
price in  federal  court or before  the FERC.  Such  proceedings  could  also be
protracted  and  expensive  unless the FERC acts on its own or other  generators
bring a proceeding before the Commission or a court.

         Prior to the summer of 2000,  many IOUs were attempting to purchase and
terminate the Power Contracts of Qualifying  Facilities  because,  historically,
the electric rates paid to Qualifying  Facilities have been  significant  higher
than wholesale  power rates.  Currently,  however,  the rates paid to Qualifying
Facilities by California IOUs are lower than current  wholesale power rates and,
if the legislation  proposed to substitute a legislatively  derived energy price
is enacted and  survives  legal  challenges,  Qualifying  Facilities  will be an
attractive generating asset for California's IOUs.

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

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

         The remaining On-site  Cogeneration  Projects and the Ridgewood AES and
El Segundo Projects,  which have "shared savings" contracts,  are exposed to the
changes in the electric  industry  that are being caused by wholesale and retail
deregulation,  as explained below. To date, these deregulation  efforts have not
had material  adverse effects on these Projects,  but there is the potential for
some impact on revenues in 2000 and later years.

(5)  Competition

         The San Joaquin, Byron and Providence Projects, as described above, are
not currently  subject to  competition  because those Projects have entered into
long-term agreements to sell their output at specified prices.  However, the San
Joaquin and Byron Projects could be subject to future  competition to market its
electricity  output if its Power Contracts expire or are terminated because of a
default or failure to pay by the purchasing  utility or other purchaser;  due to
bankruptcy or insolvency of the  purchaser;  because of the failure of a Project
to comply with the terms of the Power  Contract;  regulatory  changes;  or other
reasons.  The San  Joaquin and Byron  Projects  would then face  competition  to
market its capacity and energy output.  However,  the Trust believes that in the
near term,  until  additional  generation  resources  are  completed and brought
on-line,  it could  sell its output in  California  profitably,  although  for a
variety of factors,  including the volatility of natural gas prices,  unexpected
legislation and litigation, there is no guarantee that it may be able to do so.

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

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

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

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

(iv)  Potential Legislation and Regulation.

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

(6)  Regulatory Matters.

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

(i)  Energy Regulation.

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

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

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

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

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

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

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

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

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

(ii)  Environmental Regulation.

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

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

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

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

         The Trust's  Projects are 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.

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

(iii)  The 1940 Act

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

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

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

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

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

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

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

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

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

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

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

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

(e)  Employees.

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

Item 2.  Properties.

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

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

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

Byron         Byron,      Leased    2021         2      28,000      Gas-fired
            California                                            cogeneration
                                                                      facility
San Joaquin  Atwater,     Leased    2021         1      25,000       Gas-fired
            California                                            cogeneration
                                                                      facility
On-Site      9 sites     Leased   various       n/a       n/a     Inside-the-
 Cogen-        in CA,       or                                          fence,
 eration      MA and     licensed                                   gas-fired
                 NY                                                 or diesel-
                                                                       fueled
                                                                  cogeneration
                                                                   engines and
                                                                    generators
Providence   Providence,  Leased    2020         4      10,000       Landfill
             Rhode Island                                            gas-fired
                                                                    generation
                                                                      facility
Ridgewood   11 sites in  Licensed  various     n/a       n/a      Inside-the-
 AES          NY and NJ                                             fence, gas-
                                                                   fired
                                                                 cogeneration
                                                                  engines and
                                                                  generators
Ridgewood    Los Angeles, Licensed              n/a        n/a   Inside-the-
 El Segundo   CA                                                  fence, gas-
                                                                  fired
                                                                  cogeneration
                                                                  facility

Item 3.  Legal Proceedings.

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

         The  arbitration  panel also awarded the Trust its attorneys'  fees and
expenses  incurred  in  prosecuting  its  case  in  chief  and  awarded  EUA its
attorneys' fees and expenses  incurred in prosecuting its counterclaim for a net
additional recovery by the Trust of $707,000.  Certain final motions resulted in
additional interest to the Trust of $874,000,  net of legal fees, and the United
States  District  Court for the District of  Massachusetts  confirmed the entire
award in October 1999. The matter is closed.

         In  September  1998  the  Region I  office  of the  U.S.  Environmental
Protection  Agency  (the  "EPA")  filed  an  administrative  proceeding  against
Ridgewood  Providence Power Partners,  L.P. ("RPPP"), a subsidiary of the Trust,
seeking to recover civil  penalties of up to $190,000 for alleged  violations of
operational  recordkeeping and training  requirements at the Providence Project.
The penalty was reduced to $86,000,  and was paid by the  Providence  Project in
June 1999.

         In  January  2000 and August  2000,  the  United  States  Environmental
Protection  Agency  ("EPA")  issued  "Administrative  Orders" to the  Providence
Project, the Rhode Island Resource Recovery Corporation ("RIRRC"), the owner and
operator of the Johnston,  Rhode Island  landfill,  and Central Gas Corporation,
Central Gas LTD  Partnership,  LKD Central  Limited  Partnership  and LKD Energy
Corporation  (collectively  "GASCO"), the owner and operator of a gas collection
system at the  landfill  which  provides  gas to the  Providence  Project.  With
respect to the  Providence  Project,  the EPA  believed it to be in violation of
certain  provisions  of the Clean Air Act and  certain  federal  regulations  in
connection  with the  Providence  Project's  operations at the  Johnston,  Rhode
Island landfill.  Although Ridgewood denies EPA's claims, EPA and Ridgewood have
agreed to settle  EPA's  claims  against  Ridgewood  through the  mechanism of a
Consent  Agreement and Order that will fully  resolve  EPA's claims  against the
Providence  Project in consideration of payment of an administrative  penalty of
approximately $25,000.

         In addition to the  foregoing,  the RIRRC and GASCO  entities are being
pursued by EPA for  alleged  violations  of  federal  statutes  and  regulations
concerning their operations.  RIRRC and GASCO may or may not settle those claims
with EPA.  If GASCO or RIRRC do not settle  EPA's  claims,  there is a potential
that GASCO or RIRRC could assert claims against the Providence  Project based on
contractual  agreements between  Ridgewood,  GASCO and RIRRC. The nature of such
claims and any  evaluation of the range of any  potential  exposure from them is
premature at this time.

         On October 8, 1999,  the Trust,  through a subsidiary,  filed a lawsuit
against Globe Manufacturing  Company in the United States District Court for the
District of Massachusetts,  claiming that Globe had unjustifiably  cancelled the
energy  services  agreement by which the Trust's  subsidiary ran a 3.5 Megawatt,
inside-the-fence,  cogeneration project at Globe's manufacturing plant. The case
is in discovery. The Trust is claiming damages in excess of $4 million. The case
has  been  closed  without  prejudice  pending  the  termination  of  the  Globe
Bankruptcy proceedings.

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

         The Trust did not submit any matters to a vote of the Investors  during
the fourth quarter of 2000.

PART II

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

(a)  Market Information.

         The Trust sold 391.8444  Investor Shares of beneficial  interest in the
Trust in its private  placement  offering of Investor Shares which closed on May
31, 1995.  There is  currently  no  established  public  trading  market for the
Investor Shares. As of the date of this Form 10-K, all such Investor Shares have
been issued and are outstanding. There are no outstanding options or warrants to
purchase, or securities convertible into, Investor Shares.

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

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

(b)  Holders

         As of the date of this Form  10-K,  there  are 779  record  holders  of
Investor Shares.

(c)  Dividends

     The Trust made distributions as follows in the years 2000 and 1999:

                             Year ended                Year ended
                         December 31, 2000      December 31, 2000
Total distributions
 to Investors             $  1,763,304              $  2,353,447
Distributions per
 Investor Share                  4,500                     6,006
Distributions to
 Managing Shareholder           17,811                    23,772

         The Trust's ability to make future  distributions  to the Investors and
their  timing  will  depend on the net cash flow of the Trust and  retention  of
reasonable  reserves  as  determined  by the  Trust  to  cover  its  anticipated
expenses.

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

Item 6.  Selected Financial Data.

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

Selected Financial Data
As of December 31,        2000      1999        1998        1997        1996
Total Fund Information:
Net revenue from
operating projects   $2,064,449  $1,542,695  $2,727,968  $4,075,390  $1,525,613
Net income (loss)    (2,274,063)  2,345,368    (798,415) (1,355,866)  2,541,686
                         (A)          (B)       (C),(D)     (E)
Net assets (shareholders'
 equity)             19,696,005  23,751,183  23,783,034   26,957,314 31,388,939
Investments in project
 development and power
 generation limited
 partnerships        20,091,438  23,202,879  21,714,050  24,613,978  28,050,750
Total assets         20,520,277  23,814,297  24,257,396  27,336,224  31,430,075
Per Investor Share:
  Revenues              $ 5,336     $ 8,130    $10,404      $10,788      $9,630
                         (A)          (B)        (D)
  Expenses               11,140       2,145     12,442       14,249       3,143
                         (A)                     (C)           (E)
  Net income (loss)       5,803       5,985     (2,038)      (3,460)      6,486
  Net asset value        50,265      60,614     60,695       68,796      80,106
Distributions to
 Investors                4,500       6,006      6,003        7,771       9,429

(A) After  writedowns of investments in 2000 of $3,426,722  ($8,745 per Investor
Share).
(B) Includes  $1,581,308 of income from  arbitration  award ($4,036 per Investor
Share)
(C) After writedowns of investments in 1998 of $4,055,214  ($10,349 per Investor
Share).
(D) Includes  $1,265,122  ($3,229 per Investor Share) of income from arbitration
award.
(E) After writedowns of investments in 1997 of $4,743,631  ($12,106 per Investor
Share).

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

Introduction

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

Outlook

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

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

Results of Operations

The year ended December 31, 2000 compared to the year ended December 31, 1999.

The Trust  reported a net loss of  $2,274,000  in 2000 compared to net income of
$2,345,000 in 1999. The 2000 net loss included  $3,427,000 of charges related to
writedowns of investments and the 1999 net income included  $1,581,000 of income
resulting from an arbitration  proceeding  against EUA, as described at Item 3 -
Legal Proceedings.  Excluding the writedowns and arbitration income, the Trust's
net income would have  increased  from  $764,000 in 1999 to  $1,153,000 in 2000.
This  improvement  was  primarily  due to higher  income  from power  generation
projects.

Project                                        2000           1999
----------------------------------------     ----------     ----------
On-site Cogeneration:
   Massachusetts .....................      $       --   $    124,000
   Elmsford ..........................         206,000         85,000
   Others ............................          45,000             --
                                             ----------     ----------
   Subtotal ..........................         251,000        209,000
Mobile Power III .......................       317,000         89,000
Ridgewood AES ..........................            --         70,000
San Joaquin ............................       682,000        464,000
Providence .............................       554,000        445,000
Byron ..................................       260,000        266,000
                                             ----------     ----------
   Total ...........................        $2,064,000     $1,543,000
                                             ----------     ----------

The  $218,000  (47.0%)  increase  in income  from the San  Joaquin  Project  was
attributable  to an increase in revenue due to the Project's  election to switch
the pricing of its  electricity  sales from a cost based price to a market based
price in the third quarter of 2000.

The $109,000  (24.5%)  increase in income from the Providence  Project  reflects
reduced  costs of engine  maintenance  resulting  from  revisions to the plant's
maintenance program.

The income from the two mobile power modules  acquired in August 1999  increased
from $89,000 in 1999 to $317,000 in 2000.

In 1999, the Trust  recorded  $124,000 of income from the  Massachusetts'  Globe
plant  which  was  temporarily  shut  down in the  third  quarter  of  1999  for
maintenance and then at the customer's  request.  No income has been recorded by
the Trust  related to that plant since it was  shutdown.  In October  1999,  the
customer  requested that the project be  permanently  shut down, as described at
Item 3 - "Legal Proceedings." The Trust is challenging that request in court.

Income from the  Elmsford  plant  increased  from $85,000 in 1999 to $206,000 in
2000 due to  increased  revenues.  Income from the AES projects  decreased  from
$70,000 in 1999 to zero in 2000 due to higher fuel prices.

Excluding the writedown of investments,  total expenses  increased by $97,000 to
$938,000 in 2000 from  $841,000 in 1999.  The increase was  primarily  due to an
increase  in legal  expenses  related  to the  disputes  with PG&E as well as an
unsolicited tender offer for investor shares.  See Item 3 - "Legal  Proceedings.
All other 2000 Trust expenses were comparable to 1999.

The year ended December 31, 1999 compared to the year ended December 31, 1998.

The Trust  reported net income of  $2,345,000  in 1999 compared to a net loss of
$798,000 in 1998. The improvement in the results of operations was primarily due
to the absence of a writedown of  investments  of $4,055,000 in 1998,  partially
offset by lower income from power  generation  projects.  In 1999 and 1998,  the
Trust recorded  income of $1,581,000  and  $1,265,000,  respectively,  of income
resulting from an arbitration  proceeding  against EUA, as described at Item 3 -
Legal Proceedings.

   As summarized below, income from power generation projects decreased 43.4% to
$1,543,000 in 2000 compared to $2,728,000 in 1999:

Project                                         1999        1998
----------------------------------------     ----------     ----------
On-site Cogeneration:
   Massachusetts .....................       $ 124,000     $ 324,000
   Elmsford ..........................          85,000       243,000
   Others ............................              --        65,000
                                             ----------    ----------
   Subtotal ..........................         209,000       632,000
Mobile Power III .......................        89,000            --
Ridgewood AES ..........................        70,000        34,000
San Joaquin ............................       464,000     1,051,000
Providence .............................       445,000       547,000
Byron ..................................       266,000       464,000
                                             ----------    ----------
 Total ...............................      $1,543,000    $2,728,000
                                             ----------    ----------

In 1999, income from the San Joaquin, Byron and Providence Projects decreased by
$587,000  (55.9%),  $198,000  (42.7%) and $102,000  (18.6%),  respectively.  The
decrease in income from these  three  plants  reflects  the  increased  costs of
periodic major engine overhauls and maintenance.

In 1999,  income from the On-Site  Cogeneration  Projects  decreased by $423,000
(66.9%) primarily as a result of the shut-down of Massachusetts' Globe plant and
reduced revenue at the Elmsford plant.

Excluding  the writedown of  investments,  total  expenses  decreased by $68,000
(9.0%) to  $752,000  in 1999 from  $820,000 in 1998.  Management  fees  declined
$79,000  (11.7%) to $595,000 in 1999 from $674,000 in 1998  reflecting the lower
net assets of the Trust. All other 1999 Trust expenses were comparable to 1998.

Liquidity and Capital Resources

For 1999, net cash provided by operating activities was $566,000, which included
deductions of $1,577,000 for additional net  investments in projects.  For 2000,
net cash  provided  by  operating  activities  was  $1,598,000,  which  included
deductions  of  $315,000  for  additional  net  investments  in  projects.   The
additional  net  investments  in 1999  relates to the  Trust's  purchase of five
Caterpillar power modules for $1,696,000.  The additional net investment in 2000
relates to increased  working capital  requirements at the San Joaquin and Byron
Projects due to higher fuel prices.

Cash  distributions  to  shareholders  were $2,377,000 in 1999 and $1,781,000 in
2000. The decrease was primarily a result of the cessation of  distributions  in
the fourth quarter of 2000.

During  1997,  the  Trust and Fleet  Bank,  N.A.  (the  "Bank")  entered  into a
revolving  line of credit  agreement,  whereby  the Bank  provides  a three year
committed  line of credit  facility of  $750,000.  The credit line was  extended
until March 2001.  Outstanding borrowings bear interest at the Bank's prime rate
or, at the Trust's choice, at LIBOR plus 2.5%. The credit agreement requires the
Trust to maintain a ratio of total debt to tangible  net worth of no more than 1
to 1 and a minimum debt service  coverage  ratio of 2 to 1. The credit  facility
was  obtained in order to allow the Trust to operate  using a minimum  amount of
cash,  maximize the amount invested in Projects and maximize cash  distributions
to  shareholders.  There were no borrowings under the line of credit in 1999. In
the second quarter of 2000, the Trust borrowed $725,000 under the line of credit
which it repaid in the fourth quarter.

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

The Trust  anticipates  that during 2001 its cash flow from operations will meet
its 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, 2000
                       Expected Maturity Date
                            2001
                           (U.S. $)

Bank Deposits and Certificates of Deposit     $ 421,000
Average interest rate                              5.6%

Item 8.  Financial Statements and Supplementary Data.

Index to Financial Statements

     Report of Independent Accountants                       F-2
     Balance Sheet at December 31, 2000 and 1999             F-3
     Statement of Operations for Three Years
      ended December 31, 2000                                F-4
     Statement of Changes in Shareholders'
      Equity for Three Years ended December 31,
      2000                                                   F-5
     Statement of Cash Flows for Three Years
      ended December 31, 2000                                F-6
     Notes to Financial Statements                   F-7 to F-12

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

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

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

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

PART III

Item 10.  Directors and Executive Officers of the Registrant.

(a)  General.

         As Managing  Shareholder of the Trust,  Ridgewood  Power LLC has direct
and exclusive  discretion in management  and control of the affairs of the Trust
(subject to the general  supervision and review of the Independent  Trustees and
the  Managing  Shareholder  acting  together  as the  Board of the  Trust).  The
Managing  Shareholder will be entitled to resign as Managing  Shareholder of the
Trust  only  (i)  with  cause   (which  cause  does  not  include  the  fact  or
determination  that  continued  service  would be  unprofitable  to the Managing
Shareholder) or (ii) without cause with the consent of a majority in interest of
the  Investors.  It may be removed from its capacity as Managing  Shareholder as
provided in the Declaration.

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

Managing Shareholder.

         Ridgewood  Power  Corporation  was  incorporated  in February 1991 as a
Delaware corporation for the primary purpose of acting as a managing shareholder
of business  trusts and as a managing  general  partner of limited  partnerships
which  are  organized  to  participate  in  the  development,  construction  and
ownership of  Independent  Power  Projects.  It organized the Trust and acted as
managing  shareholder until April 1999. On or about April 21, 1999 it was merged
into the current Managing Shareholder,  Ridgewood Power LLC. Ridgewood Power LLC
was  organized in early April 1999 and has no business  other than acting as the
successor to Ridgewood Power Corporation.

         Robert  E.  Swanson  has been the  President,  sole  director  and sole
stockholder of Ridgewood Power  Corporation since its inception in February 1991
and is now the  controlling  member,  sole manager and President of the Managing
Shareholder.  All of the equity in the Managing  Shareholder is or will be 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  Power I, Power II, Power
IV, Power V, the Growth Fund and the Egypt Fund, as Delaware  business trusts to
participate in the independent  power industry.  Ridgewood Power LLC is now also
their  managing  shareholder.  The business  objectives of these five trusts are
similar to those of the Trust.

         A number of other companies are affiliates of Mr. Swanson and Ridgewood
Power.  Each of these also was organized as a corporation  that was wholly-owned
by Mr. Swanson.  In April 1999, most of them were merged into limited  liability
companies  with  similar  names and Mr.  Swanson  became  the sole  manager  and
controlling  owner of each  limited  liability  company.  For  convenience,  the
remainder of this Memorandum will discuss each limited liability company and its
corporate predecessor as a single entity.

         The  Managing   Shareholder   is  an  affiliate  of  Ridgewood   Energy
Corporation  ("Ridgewood  Energy"),  which has organized and operated 48 limited
partnership  funds and one  business  trust  over the last 18 years (of which 25
have  terminated)  and which had total capital  contributions  in excess of $190
million.  The  programs  operated by Ridgewood  Energy have  invested in oil and
natural  gas  drilling  and  completion  and  other  related  activities.  Other
affiliates  of  the  Managing   Shareholder  include  Ridgewood  Securities  LLC
("Ridgewood Securities"),  an NASD member which has been the placement agent for
the private  placement  offerings of the seven trusts  sponsored by the Managing
Shareholder  and the funds  sponsored by  Ridgewood  Energy;  Ridgewood  Capital
Management  LLC  ("Ridgewood  Capital"),  which assists in offerings made by the
Managing  Shareholder and which is the sponsor of four privately offered venture
capital funds (the  Ridgewood  Capital  Venture  Partners and Ridgewood  Capital
Venture  Partners II funds);  Ridgewood  Power VI LLC ("Power  VI"),  which is a
managing  shareholder  of the Growth Fund,  and RPM. Each of these  companies is
controlled by Robert E. Swanson, who is their sole director or manager.

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

         Robert E.  Swanson,  age 54, has also served as  President of the Trust
since its  inception in 1991 and as  President of RPM,  Power I, Power II, Power
IV, Power V and the Growth Fund, since their respective inceptions.  Mr. Swanson
has been President and registered  principal of Ridgewood  Securities and became
the Chairman of the Board of Ridgewood  Capital on its  organization in 1998. He
also is Chairman of the Board of the Ridgewood Capital Venture Partners I and II
venture capital 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.

         Robert L. Gold,  age 42, has served as Executive  Vice President of the
Managing  Shareholder,  RPM, the Trust, Power I, Power II, Power IV, Power V and
the Growth Fund since their respective  inceptions,  with primary responsibility
for marketing and acquisitions. He has been President of Ridgewood Capital since
its  organization  in 1998. As such,  he is President of the  Ridgewood  Capital
Venture  Partners I and II 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.

         Martin V. Quinn,  age 53, has been the  Executive  Vice  President  and
Chief Operating Officer of Ridgewood Power since April 2000. Before that, he had
assumed the duties of Chief  Financial  Officer of  Ridgewood  Power in November
1996 under a  consulting  arrangement.  In April  1997,  he became a Senior Vice
President and Chief Financial Officer of Ridgewood Power.

         Mr. Quinn has over 30 years of experience in financial  management  and
corporate mergers and acquisitions, gained with major, publicly-traded companies
and an  international  accounting  firm. He formerly served as Vice President of
Finance  and Chief  Financial  Officer of  NORSTAR  Energy,  an energy  services
company,  from February 1994 until June 1996. From 1991 to March 1993, Mr. Quinn
was  employed by  Brown-Forman  Corporation,  a  diversified  consumer  products
company and distiller, where he was Vice President-Corporate  Development.  From
1981 to 1991, Mr. Quinn held various officer-level positions with NERCO, Inc., a
mining and natural resource  company,  including Vice President-  Controller and
Chief  Accounting  Officer  for his last six years and Vice  President-Corporate
Development.  Mr.  Quinn's  professional  qualifications  include his  certified
public  accountant  qualification in New York State,  membership in the American
Institute of Certified  Public  Accountants,  six years of  experience  with the
international accounting firm of PricewaterhouseCoopers,  LLP, and a Bachelor of
Science degree in Accounting and Finance from the University of Scranton (1969).

         Daniel V. Gulino,  age 40, has been Senior Vice  President  and General
Counsel of the Managing Shareholder since August 2000. He began his legal career
as an associate for Pitney,  Hardin,  Kipp & Szuch, a large New Jersey law firm,
where his experience included corporate acquisitions and transactions.  Prior to
joining  Ridgewood,  Mr. Gulino was in-house  counsel for several large electric
utilities,  including GPU, Inc.,  Constellation Power Source, 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,  36,  has been the Vice  President  and Chief
Financial  Officer of the Managing  Shareholder  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, which is the Trust's
independent   certified   public   accountant.    Mr.   Naunton's   professional
qualifications   include  his  certified  public  accountant   qualification  in
Pennsylvania,   membership  in  the  American   Institute  of  Certified  Public
Accountants  and a Bachelor of Science  degree in Business  Administration  from
Bucknell University (1986).

         Mary Lou Olin,  age 48, has served as Vice  President  of the  Managing
Shareholder,  RPM,  Ridgewood  Capital,  the Trust, Power I, Power II, Power IV,
Power V and the Growth  Fund since  their  respective  inceptions.  She has also
served as Vice President of Ridgewood Energy since October 1984, when she joined
the  firm.  Her  primary  areas  of  responsibility   are  investor   relations,
communications and administration.  Prior to her employment at Ridgewood Energy,
Ms. Olin was a Regional  Administrator at McGraw-Hill Training Systems where she
was employed for two years.  Prior to that, she was employed by RCA Corporation.
Ms. Olin has a Bachelor of Arts degree from Queens College.

(c)  Management Agreement.

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

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

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

         The Board of the Trust (including  Independent  Trustees) have approved
the initial  Management  Agreement and its renewals.  Each Investor consented to
the terms and conditions of the initial  Management  Agreement by subscribing to
acquire  Investor Shares in the Trust.  The Management  Agreement will remain in
effect year to year  thereafter  as long as it is approved at least  annually by
(i) either the Board of the Trust or a majority in interest of the Investors and
(ii) a  majority  of the  Independent  Trustees.  The  agreement  is  subject to
termination  at any time on 60 days'  prior  notice by the Board,  a majority in
interest of the Investors or the Managing Shareholder.  The agreement is subject
to  amendment  by the  parties  with the  approval  of (i) either the Board or a
majority  in interest of the  Investors  and (ii) a majority of the  Independent
Trustees.

(d) Executive Officers of the Trust.

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

(e)  The Trustees.

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

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

         Ralph O.  Hellmold,  age 60,  is  Chairman  of The  Private  Investment
Banking  Company  ("PIBC") and President of Hellmold  Associates,  Inc., both of
which are financial  advisory firms that assist companies raise capital,  divest
or acquire businesses or restructure  corporate  organizations.  Other financial
advisory services provided by PIBC and Hellmold Associates, Inc. include mergers
and  acquisitions  advice,  valuations,  fairness  opinions  and expert  witness
testimony.  In addition to working with troubled  companies or their  creditors,
Hellmold  Associates,  Inc. also acts as general partner of funds that invest in
the securities of financially distressed companies.

         From  1987 to 1990,  when he  formed  Hellmold  Associates,  Inc.,  Mr.
Hellmold was a Managing Director at Prudential-Bache  Capital Funding,  where he
served as co-head of the  Corporate  Finance  Group,  co-head of the  Investment
Banking  Committee and head of the Financial  Restructuring  Group. From 1974 to
1987, Mr. Hellmold was a partner at Lehman Brothers and its successors, where he
worked in the General  Corporate  Finance  Group and  co-founded  the  Financial
Restructuring Group. Prior thereto, he was a research analyst at Lehman Brothers
and at Francis I. du Pont & Company. He received his undergraduate  degree magna
cum laude from Harvard College and an M.I.A. from Columbia  University.  He is a
Chartered  Financial  Analyst  and a member of the New York  Society of Security
Analysts.  Mr.  Hellmold is the holder of one- half share in each of Power I and
Power II, a shareholder of one-half Share in the Trust and a limited  partner or
shareholder in numerous  limited  partnerships and a business trust sponsored by
Ridgewood  Energy to invest in oil and gas development  and related  businesses.
Mr. Hellmold is a director of Core Materials Corporation,  Columbus, Ohio and of
International Aircraft Investors, Torrance, California.

         Jonathan C. Kaledin,  age 43, has been New York Regional Counsel of The
Nature  Conservancy,  the international  land conservation  organization,  since
September  1995.  From 1990 to June 1995, he was the  Executive  Director of the
National  Water  Funding  Council  ("NWFC"),  an  advocacy  and  public  affairs
organization representing municipalities, businesses, financial institutions and
others on the financial aspects of clean water infrastructure  projects required
by the federal Clean Water Act and the federal Safe Drinking Water Act. Prior to
running  the NWFC,  Mr.  Kaledin  practiced  law in both the  private and public
sectors,  specializing in  environmental  and real estate  matters.  Mr. Kaledin
received his undergraduate degree magna cum laude from Harvard College and a law
degree from New York University.

         The  Independent  Trustees  and the Managing  Shareholder  expanded the
number of  Independent  Trustees  to three in January  2000 and  elected  Joseph
Ferrante,  Jr. as the additional  Independent Trustee. Mr. Ferrante, age 56, has
been a lawyer in private  practice in  Ridgewood,  New Jersey for more than five
years specializing in business and taxation matters.  He received a Juris Doctor
degree  in  law  from  the  George   Washington   University  in  1970  and  his
undergraduate  degree  from the Johns  Hopkins  University.  He  advises a large
number of start-up and entrepreneurial companies.

         The Corporate Trustee of the Trust is Ridgewood Holding. Legal title to
Trust  Property  is now and in the future  will be in the name of the Trust,  if
possible,  or Ridgewood Holding as trustee.  Ridgewood Holding is also a trustee
of Power I, Power II, Power IV,  Ridgewood Power V and the Growth Fund and of an
oil and gas business trust sponsored by Ridgewood Energy and is expected to be a
trustee  of  other  similar  entities  that  may be  organized  by the  Managing
Shareholder  and  Ridgewood  Energy.  The  President,  sole  director  and  sole
stockholder  of  Ridgewood  Holding is Robert E.  Swanson;  its other  executive
officers  are  identical to those of the  Managing  Shareholder.  See - Managing
Shareholder.  The principal office of Ridgewood  Holding is at 1105 North Market
Street, Suite 1300, Wilmington, Delaware 19899.

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

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

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

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

(g)  RPM.

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

         Initially,  the Managing  Shareholder does not anticipate  charging RPM
for the full amount of rent,  utility supplies and office expenses  allocable to
RPM.  As a  result,  both  initially  and  on  an  ongoing  basis  the  Managing
Shareholder believes that RPM's charges for its services to the Trust are likely
to be  materially  less  than its  economic  costs  and the  costs  of  engaging
comparable  third persons as managers.  RPM will not receive any compensation in
excess of its costs.

         Allocations  of costs will be made either on the basis of  identifiable
direct costs,  time records or in proportion to each  program's  investments  in
Projects  managed by RPM; and  allocations  will be made in a manner  consistent
with generally accepted accounting principles.

         RPM does not provide any services related to the  administration of the
Trust, such as investment, accounting, tax, investor communication or regulatory
services,  nor will it  participate  in  identifying,  acquiring or disposing of
Projects.  RPM will not have the power to act in the Trust's name or to bind the
Trust,  which will be  exercised  by the  Managing  Shareholder  or the  Trust's
officers,  although it may be  authorized  to act on behalf of the  subsidiaries
that own Projects.

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

     The  executive  officers  of RPM  are Mr.  Swanson  (President),  Mr.  Gold
(Executive  Vice  President),  Mr. Quinn  (Executive  Vice  President  and Chief
Operating Officer),  Mr. Gulino (Senior Vice President and General Counsel), Mr.
Naunton  (Vice  President  and  Chief  Financial  Officer)  and Ms.  Olin  (Vice
President).

Item 11.  Executive Compensation.

         Through  1995,  the  executive  officers of the Trust and the  Managing
Shareholder were compensated by Ridgewood Energy.  The Trust was not charged for
their compensation; the Managing Shareholder remitted a portion of the fees paid
to it by the Trust to reimburse  Ridgewood  Energy for employment costs incurred
on the Managing Shareholder's business.  Since 1996 the Managing Shareholder has
compensated these persons without  additional  payments by the Trust and will be
reimbursed by Ridgewood Energy for costs related to Ridgewood Energy's business.
The Trust will  reimburse RPM at allocable  cost for services  provided by RPM's
employees;  no such reimbursement per employee exceeded $60,000 in 2000 or 1999.
Information  as to the fees  payable to the  Managing  Shareholder  and  certain
affiliates  is  contained  at  Item  13 --  Certain  Relationships  and  Related
Transactions.

         As  compensation  for services  rendered to the Trust,  pursuant to the
Declaration,  each  Independent  Trustee is entitled to be paid by the Trust the
sum of $5,000  annually and to be reimbursed  for all  reasonable  out-of-pocket
expenses  relating to attendance at Board  meetings or otherwise  performing his
duties  to the  Trust.  The  Board  of the  Trust  is  entitled  to  review  the
compensation  payable to the  Independent  Trustees  annually  and  increase  or
decrease it as the Board sees  reasonable.  The Trust is not entitled to pay the
Independent Trustees  compensation for consulting services rendered to the Trust
outside the scope of their duties to the Trust without prior Board approval.

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

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

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

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

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

Item 13.  Certain Relationships and Related Transactions.

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

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

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

         The  Trust  made  distributions  in 1998 and 1999 as stated at Item 5 -
Market for Registrant's Common Equity and Related Stockholder Matters. The Trust
and its subsidiaries paid fees or reimbursements to the Managing Shareholder and
its affiliates as follows:

                 2000         1999        1998          1997         1996
Managing      $592,664     $594,576    $673,933      $766,866     $794,026
Shareholder

Cost
Reimburse-   $12,143,034  $15,813,187   15,617,631   14,308,444   11,566,400
ments
RPM

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

         The management fee,  payable monthly under the Management  Agreement at
the annual rate of 2.5% of the Trust's  net asset  value,  began on the date the
first Project was acquired and compensates the Managing  Shareholder for certain
management,  administrative  and advisory services for the Trust. In addition to
the  foregoing,  the  Trust  reimbursed  the  Managing  Shareholder  at cost for
expenses and fees of unaffiliated  persons  engaged by the Managing  Shareholder
for Trust  business  and in 1995 for payroll and other costs of operation of the
Trust's Projects.  Beginning in 1996, these reimbursements were paid to RPM. The
reimbursements  to RPM,  which do not exceed its actual costs,  are described at
Item 10(g) -- Directors and Executive Officers of the Registrant -- RPM.

         Other  information  in response to this item is reported in response to
Item 11. Executive Compensation,  which information is incorporated by reference
into this Item 13.

PART IV

Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

(a)  Financial Statements.

     See the Index to Financial Statements in Item 8 hereof.

(b) Reports on Form 8-K.

     No Forms 8-K were filed with the  Commission by the  Registrant  during the
quarter ending December 31, 2000.

(c)  Exhibits

     3A.  Certificate of Trust of the Registrant is incorporated by reference to
Exhibit 3A of Registrant's  Registration  Statement filed with the Commission on
February 15, 1994.

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

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

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

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

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

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

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

     21.   Subsidiaries of the Registrant.           Page __

     24.   Powers of Attorney                         Page

     27.   Financial Data Schedule                    Page
<PAGE>

SIGNATURES

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

Signature                      Title                        Date

RIDGEWOOD ELECTRIC POWER TRUST III (Registrant)

By: /s/Robert E. Swanson    President and Chief       March 30, 2001
     Robert E. Swanson       Executive Officer

     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
Registrant and in the capacities and on the dates indicated.

By: /s/Robert E. Swanson    President and Chief       March 30, 2001
     Robert E. Swanson       Executive Officer

By: /s/Christopher I. Naunton  Vice President and    March 30, 2001
     Christopher I. Naunton     Chief Financial Officer

RIDGEWOOD POWER,LLC    Managing Shareholder             March 30, 2001

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

     /s/ Robert E. Swanson  * Independent Trustee      March 30, 2001
        Ralph O. Hellmold

     /s/ Robert E. Swanson    *Independent Trustee      March 30, 2001
        Jonathan C. Kaledin

    /s/ Robert E. Swanson
         Joseph Ferrante, Jr.   * Independent Trustee  March 30, 2001

*  As attorney-in-fact for the Independent Trustee
<PAGE>
                       Ridgewood Electric Power Trust III

                              Financial Statements

                        December 31, 2000, 1999 and 1998


<PAGE>



                        Report of Independent Accountants


To the Shareholders and Trustees of
Ridgewood Electric Power Trust III:

In  our  opinion,   the  accompanying  balance  sheets  and  the  statements  of
operations, changes in shareholders' equity and of cash flows present fairly, in
all material respects,  the financial position of Ridgewood Electric Power Trust
III (the  "Trust")  at  December  31,  2000 and  1999,  and the  results  of its
operations  and its cash flows for each of the three  years in the period  ended
December 31, 2000, 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.

As explained in Note 2, the financial  statements include  investments valued at
$20,091,438 and $23,202,879 (102% and 98% of shareholders' equity, respectively)
as of December 31, 2000 and 1999, respectively, whose values have been estimated
by management in the absence of readily  ascertainable  market  values.  We have
reviewed the  procedures  used by  management  in arriving at their  estimate of
value and have inspected underlying documentation, and, in the circumstances, we
believe  the  procedures  are  reasonable  and  the  documentation  appropriate.
However,  because of the inherent  uncertainty  of  valuation,  those  estimated
values may differ  significantly from the values that would have been used had a
ready  market  for  those  investments  existed,  and the  differences  could be
material to the financial statements.




PricewaterhouseCoopers LLP
New York, NY
March 23, 2001


<PAGE>
Ridgewood Electric Power Trust III
Balance Sheet
--------------------------------------------------------------------------------

                                                       December 31,
                                               ----------------------------
                                                   2000            1999
                                               ------------    ------------
Assets:
Investments in power generation projects ...   $ 20,091,438    $ 23,202,879
Cash and cash equivalents ..................        421,127         603,922
Other assets ...............................          7,712           7,496
                                               ------------    ------------
  Total assets .............................   $ 20,520,277    $ 23,814,297
                                               ------------    ------------

Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ......   $     49,987    $     51,676
Due to affiliates ..........................        774,285          11,438
                                               ------------    ------------
  Total liabilities ........................        824,272          63,114

Commitments and contingencies

Shareholders' equity:
Shareholders' equity (391.8444
 shares issued and outstanding) ............     19,830,080      23,844,706
Managing shareholder's accumulated deficit .       (134,075)        (93,523)
                                               ------------    ------------
  Total shareholders' equity ...............     19,696,005      23,751,183
                                               ------------    ------------

  Total liabilities and shareholders' equity   $ 20,520,277    $ 23,814,297
                                               ------------    ------------







                 See accompanying notes to financial statements.

<PAGE>
Ridgewood Electric Power Trust III
Statement of Operations
--------------------------------------------------------------------------------

                                          Year Ended December 31,
                                ----------------------------------------
                                   2000           1999          1998
                                -----------    -----------   -----------
Revenue:
Income from power generation
 projects ...................   $ 2,064,449    $ 1,542,695   $ 2,727,968
Interest income .............        26,657         61,876        83,807
Income from arbitration award          --        1,581,308     1,265,122
                                -----------    -----------   -----------
         Total revenue ......     2,091,106      3,185,879     4,076,897
                                -----------    -----------   -----------

Expenses:
Management fee ..............       592,644        594,576       673,933
Accounting and legal fees ...       245,508         86,197        94,734
Other .......................        64,096         71,440        51,431
Interest ....................        36,199           --            --
Writedown of investments
 in power generation projects     3,426,722         88,298     4,055,214
                                -----------    -----------   -----------
  Total expenses ............     4,365,169        840,511     4,875,312
                                -----------    -----------   -----------
  Net income (loss) .........   $(2,274,063)   $ 2,345,368   $  (798,415)
                                -----------    -----------   -----------






                 See accompanying notes to financial statements.

<PAGE>
Ridgewood Electric Power Trust III
Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 2000, 1999 and 1998
--------------------------------------------------------------------------------

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

Shareholders' equity,
 January 1, 1998 ......   $ 27,018,776    $    (61,462)   $ 26,957,314

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

Net loss for the year .       (790,431)         (7,984)       (798,415)
                          ------------    ------------    ------------
Shareholders' equity,
 December 31, 1998 ....     23,876,239         (93,205)     23,783,034

Cash distributions ....     (2,353,447)        (23,772)     (2,377,219)

Net income for the year      2,321,914          23,454       2,345,368
                          ------------    ------------    ------------
Shareholders' equity,
 December 31, 1999 ....     23,844,706         (93,523)     23,751,183

Cash distributions ....     (1,763,304)        (17,811)     (1,781,115)

Net loss for the year .     (2,251,322)        (22,741)     (2,274,063)
                          ------------    ------------    ------------
Shareholders' equity,
 December 31, 2000 ....   $ 19,830,080    $   (134,075)   $ 19,696,005
                          ------------    ------------    ------------










                 See accompanying notes to financial statements.

<PAGE>
Ridgewood Electric Power Trust III
Statement of Cash Flows
--------------------------------------------------------------------------------

                                                Year Ended December 31,
                                     -----------------------------------------
                                       2000            1999           1998
                                     -----------    -----------    -----------
Cash flows from operating
 activities:
Net income (loss) ................   $(2,274,063)   $ 2,345,368    $  (798,415)
                                     -----------    -----------    -----------
Adjustment to reconcile net
 income (loss) to net cash
 flows from operating activities:
Writedown of power generation
 project investments .............     3,426,722         88,298      4,055,214
Investments in power
 generation projects .............      (315,281)    (1,577,127)    (1,155,286)
Changes in assets and liabilities:
 Increase (decrease) in due
  to/from affiliates, net ........       762,847       (247,724)       (60,833)
 (Increase) decrease in
 other assets ....................          (216)        90,943        (84,197)
 (Decrease) increase in accounts
  payable and accrued expenses ...        (1,689)      (133,533)       146,672
                                     -----------    -----------    -----------
Total adjustments ................     3,872,383     (1,779,143)     2,901,570
                                     -----------    -----------    -----------
Net cash provided by
 operating activities ............     1,598,320        566,225      2,103,155
                                     -----------    -----------    -----------
Cash flows from financing
 activities:
Cash distributions to
 shareholders ....................    (1,781,115)    (2,377,219)    (2,375,865)
Borrowings under line
 of credit facility ..............       725,000           --             --
Repayments under line
 of credit facility ..............      (725,000)          --             --
                                     -----------    -----------    -----------
Net cash used in financing
 activities ......................    (1,781,115)    (2,377,219)    (2,375,865)
                                     -----------    -----------    -----------
Net decrease in cash and cash
 equivalents .....................      (182,795)    (1,810,994)      (272,710)

Cash and cash equivalents,
 beginning of year ...............       603,922      2,414,916      2,687,626
                                     -----------    -----------    -----------
Cash and cash equivalents,
 end of year .....................   $   421,127    $   603,922    $ 2,414,916
                                     -----------    -----------    -----------





                 See accompanying notes to financial statements.
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
--------------------------------------------------------------------------------


1.       Organization and Purpose

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

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

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

2.       Summary of Significant Accounting Policies

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

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

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

Cash and cash equivalents
The Trust  considers  all highly  liquid  investments  with  maturities of three
months or less when purchased to be cash and cash equivalents.

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

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

3.       Investments in Power Generation Projects

The Trust had the following investments in power generation projects:

                                           Fair Values as of December 31,
                                             -------------------------
                                                 2000         1999
                                             -----------   -----------

 JRW Associates, L.P. ....................   $ 6,174,707   $ 6,053,585
 Byron Power Partners, L.P. ..............     3,039,827     2,894,633
 Ridgewood Providence Power Partners, L.P.     7,494,380     7,420,544
 Ridgewood Mobile Power III LLC ..........     1,751,881     1,761,969
 Ridgewood AES Power Partners, LLC .......       561,093       614,913
 Ridgewood El Segundo LLC ................          --         762,968
 On-site Cogeneration Projects:
   Ridgewood/Mass PPLP ...................          --       2,092,075
   Ridgewood/Elmsford PPLP ...............       974,142       952,247
   Other On-site Cogeneration
    Project Partnerships .................        95,408       649,945
                                             -----------   -----------
                                             $20,091,438   $23,202,879
                                             -----------   -----------

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

                                       For the Year Ended December 31,
                                    ------------------------------------
                                      2000         1999         1998
                                    ----------   ----------   ----------
JRW Associates, L.P. ............   $  681,966   $  463,887   $1,051,375
Byron Power Partners, L.P. ......      259,563      266,328      464,530
Ridgewood Providence Power
 Partners, L.P. .................      554,215      445,164      546,690
Ridgewood Mobile Power III LLC ..      317,452       88,732         --
Ridgewood AES Power Partners, LLC         --         70,006       33,807
On-site Cogeneration Projects:
 Ridgewood/Mass PPLP ............         --        124,058      323,694
 Ridgewood/Elmsford PPLP ........      206,052       84,520      242,881
 Other On-site Cogeneration
  Project Partnerships ..........       45,201         --         64,991
                                    ----------   ----------   ----------
                                    $2,064,449   $1,542,695   $2,727,968
                                    ----------   ----------   ----------

   JRW Associates, L.P. (known as San Joaquin Power Company)
   On January 17, 1995,  the Trust  acquired  100% of the  existing  partnership
   interests of JRW  Associates,  L.P.,  which owns and operates an 8.5 megawatt
   electric  cogeneration  facility,  located  in  Atwater,  California.  As  of
   December  31,  2000  and  1999,  the  aggregate  cost of the  investment  was
   $6,174,707 and $6,053,585,  respectively. The Trust received distributions of
   $681,966,  $463,887 and $1,051,375  from the project in 2000,  1999 and 1998,
   respectively.

   Byron Power Partners, L.P. (known as Byron Power Company)
   In January 1995, the Trust caused the formation of Byron Power Partners, L.P.
   in which  the Trust  owns  100% of the  existing  partnership  interests.  On
   January 17, 1995, Byron Power Partners, L.P. acquired a 5.7 megawatt electric
   cogeneration facility,  located in Byron, California. As of December 31, 2000
   and 1999, the aggregate cost of the Trust's investment in the partnership was
   $3,039,827 and $2,894,633,  respectively. The Trust received distributions of
   $259,563,  $266,328  and  $464,530  from the project in 2000,  1999 and 1998,
   respectively.

   Ridgewood Providence Power Partners, L.P. (known as the Providence Project)
   In 1996, Ridgewood  Providence Power Partners,  L.P. was formed as a Delaware
   limited  partnership  ("Providence  Power")  which  acquired a 12.3  megawatt
   capacity electrical  generating  station,  located at the Central Landfill in
   Johnston,  Rhode Island (the "Providence Project"). In 1997, the capacity was
   increased  to 13.8  megawatts.  The Trust  owns a 35.7%  limited  partnership
   interest in Providence Power and its general partner. As of December 31, 2000
   and  1999,  the total  cost of the  Trust's  investment  was  $7,494,380  and
   $7,420,544, respectively.

   The  Providence  Project is fueled by methane gas produced and collected from
   the  landfill.  The  electricity  generated  is  sold  to New  England  Power
   Corporation  under a long-term  contract..  The remaining  64.3% of Ridgewood
   Power is owned by  Ridgewood  Electric  Power  Trust IV ("Trust  IV"),  whose
   managing partner is Ridgewood Power Corporation.  In 2000, 1999 and 1998, the
   Trust   received   distributions   of  $554,215,   $445,164   and   $546,690,
   respectively, from the Providence Project.

   Ridgewood Mobile Power III LLC
   Effective  August  1999,  the  Trust,  through a  subsidiary,  acquired  five
   Caterpillar  mobile power modules with a total  capacity of 4.2 megawatts for
   $1,695,558. These modules are rented to domestic and international customers.
   The Trust pays Hawthorne Power Systems, a California company that maintains a
   large fleet of similar rental modules,  a fee of 20% of gross rental revenues
   to arrange and  administer  the rental of the units.  As of December 31, 2000
   and  1999,  the total  cost of the  Trust's  investment  was  $1,751,881  and
   $1,761,969,  respectively. For the year ended December 31, 2000 and 1999, the
   Trust recorded $317,452 and $88,732 of net revenue from the units.

   Ridgewood AES Power Partners, LLC (known as  Ridgewood AES)
   In 1997, the Trust formed  Ridgewood AES Power Partners,  LLC entered into an
   agreement with AES-NJ Cogen,  Inc.  (AES-NJ) to invest in five  co-generation
   facilities  operated by AES-NJ.  The  facilities are all located in New York.
   During  2000,  two  of  the  facilities  were  shut  down  due  to  financial
   difficulties  of the host  companies.  The Trust  determined that it would be
   unlikely to recover its investment in the two projects and, as a result,  the
   Trust  recorded a  writedown  of $322,500 in 2000 to reduce the book value of
   the projects to their estimated fair value of zero. The aggregate cost of the
   investment  was  $561,093  and  $614,913  at  December  31,  2000  and  1999,
   respectively.  The Trust received  distributions  of $70,006 and $33,807 from
   the  projects  in 1999 and 1998,  respectively.  In January  1999,  the Trust
   transferred five of its Other On-site Cogeneration Projects with a fair value
   of $283,966 to Ridgewood AES.

   Ridgewood El Segundo, LLC (known as the Dobbs  project)
   In April 1998, the Trust purchased an on-site  cogeneration  facility located
   near one of its  existing  on-site  cogeneration  facilities  in Los Angeles,
   California.  The total purchase price was approximately  $590,733,  including
   the payment of liabilities that encumbered the project. The aggregate cost of
   the  investment  was $762,743 at December 31,  1999.  During 2000,  the Trust
   analyzed the financial  outlook for the project and determined  that it would
   be unlikely to generate significant positive cash flows and, accordingly, the
   Trust  would be  unlikely  to recover its  investment  in the  project.  As a
   result, the Trust recorded a writedown of $814,737 in 2000 to reduce the book
   value of the project to its estimated fair value of zero.

   On-site Cogeneration Projects
   In 1995,  the Trust  acquired a portfolio of 35 projects  from  affiliates of
   Eastern  Utilities  Associates  ("EUA"),  which sell  electricity and thermal
   energy to industrial and commercial customers. The projects are held in eight
   limited  partnerships  of which the Trust is the sole limited  partner and is
   the  sole  owner  of each of the  general  partners.  In the  aggregate,  the
   projects  had 13.7  megawatts  of base load and 5.7  megawatts  of backup and
   standby capacity.  The Trust paid a total of $11,300,000 for the projects and
   invested  additional  amounts for capital  repairs and  improvements  and for
   working capital. The Trust received  distributions of $251,253,  $208,578 and
   $631,566 from these projects in 2000, 1999 and 1998, respectively. See Note 6
   -  Arbitration  and  Litigation,  for  information  relating  to  arbitration
   proceedings against EUA.

   Ridgewood/Massachusetts Power Partners L.P.
   Ridgewood/Massachusetts  Power  Partners  L.P. (the  "Partnership")  owns two
   projects.  The first is a 3.5 megawatt power plant which sells electric power
   and steam to a manufacturing facility on whose site the plant is located. The
   project sells  electric and thermal energy to the  manufacturing  facility at
   the project's  production  cost (as defined in the Energy Service  Agreement)
   plus a share of the savings  (the  difference  between  what the electric and
   thermal  energy would have cost the company absent the  cogeneration  plant).
   The Energy  Service  Agreement  expires at the end of 2005.  During 1998, the
   Trust  completed an  intensive  review of the project and  determined  that a
   write-down of the fair value of $1,236,002  was required.  As of December 31,
   1999,  the  total  cost of the  Trust's  investment  in the  partnership  was
   $2,092,075,  respectively.  The Trust received  distributions of $124,058 and
   $323,694  from the  project in 1999 and 1998,  respectively.  The project was
   temporarily  shut  down in the  third  quarter  of 1999 for  maintenance.  In
   October 1999, the customer  requested  that the project be  permanently  shut
   down. In October  1999,  the Trust brought suit against the customer for a $4
   million termination  payment. In January 2001, the customer filed for Chapter
   11 bankruptcy in the U.S.  District Court. As a result,  the Trust determined
   that it would be  unlikely  to recover  its  investment  in  partnership  and
   recorded a writedown of $2,131,913 to reduce the estimated  fair value of the
   investment to zero.

   The Partnership also owns a smaller group of four cogeneration generator sets
   totaling  255  kilowatts   serving  a   residential   complex  in  Worcester,
   Massachusetts.  The  energy  services  agreement  ("ESA")  provides  that the
   partnership  receives from the customer the cost to purchase  electricity and
   natural gas from the local  utility,  less a guaranteed  savings based on the
   utility's current rates. The ESA expires in 2004.

   Ridgewood/Elmsford Power Partners, L.P.
   Ridgewood/Elmsford  Power  Partners,  L.P.  (the  "Partnership")  owns a 1.33
   megawatt  cogeneration project. The Energy Services Agreement ("ESA") expires
   in 2005 and provides that the Partnership  receives its production  costs (as
   defined in the ESA) plus a share of the excess of the customer's avoided cost
   over production  costs.  During 1998, the Trust completed an intensive review
   of the project and determined that a write-down of the fair value of $505,390
   was required. As of December 31, 2000 and 1999, the total cost of the Trust's
   investment in the  partnership was $974,142 and $952,247,  respectively.  The
   Trust  received  distributions  of $206,052,  $84,520 and  $242,881  from the
   project in 2000, 1999 and 1998, respectively.

   The "Other On-site Cogeneration Project Partnerships"
   The  "other  on-site   cogeneration   project   partnerships"   include  five
   partnerships,  which  owned  31 of  the 35  projects  acquired  from  Eastern
   Utilities Associates.  These 31 projects represented  approximately one-third
   of the Trust's original investment in the on-site cogeneration  projects. All
   thirty-one  were  gas-fired  cogeneration  projects,  located in  California,
   Connecticut or New York.  Their energy service  agreements had terms expiring
   between September 1996 and 2011. The projects represented 5.5 MW of base load
   capacity.  The projects  ranged in size from 30  kilowatts to 660  kilowatts.
   During 2000,  1999 and 1998,  the Trust shut down several of the projects and
   recorded writedowns of $157,572, $88,298 and $2,313,822,  respectively, based
   on detailed  financial  reviews of the projects.  In January 1999,  the Trust
   transferred five of its Other On-site Cogeneration Projects with a fair value
   of $283,966 to  Ridgewood  AES.  Currently,  three of the  projects are still
   operated  by the Trust.  The Trust  received  distributions  of  $45,201  and
   $64,991 from the projects in 2000 and 1998, respectively.  As of December 31,
   2000 and 1999, the total cost of the Trust's investment in the "other on-site
   cogeneration partnerships" was $95,408 and $649,945, respectively.

   4.    Transactions With Managing Shareholder And Affiliates

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

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

   The Trust entered into a management agreement with the managing  shareholder,
   under   which  the   managing   shareholder   renders   certain   management,
   administrative  and advisory  services  and  provides  office space and other
   facilities to the Trust.  As compensation  to the managing  shareholder,  the
   Trust pays the managing shareholder an annual management fee equal to 2.5% of
   the net asset  value of the Trust  payable  monthly  upon the  closing of the
   Trust.  For the years ended December 31, 2000,  1999 and 1998, the Trust paid
   management  fees  to the  managing  shareholder  of  $592,644,  $594,576  and
   $673,933, respectively.

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

   Where  permitted,  in the  event the  managing  shareholder  or an  affiliate
   performs  brokering  services  in respect  of an  investment  acquisition  or
   disposition  opportunity  for the Trust,  the  managing  shareholder  or such
   affiliate may charge the Trust a brokerage fee. Such fee may not exceed 2% of
   the gross proceeds of any such acquisition or disposition.  No such fees have
   been paid through December 31, 2000.

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

   Effective from January 1, 1996, under an operating  agreement with the Trust,
   Ridgewood  Power   Management  LLC  (formerly   Ridgewood  Power   Management
   Corporation,  "Ridgewood  Management),  an  entity  related  to the  managing
   shareholder  through  common  ownership,  provides  management,   purchasing,
   engineering,  planning and  administrative  services to the power  generation
   projects operated by the Trust.  Ridgewood Management charges the projects at
   its cost for these services and for the allocable  amount of certain overhead
   items.  Allocations of costs are on the basis of  identifiable  direct costs,
   time  records or in  proportion  to amounts  invested in projects  managed by
   Ridgewood Management. During the year ended December 31, 2000, 1999 and 1998,
   Ridgewood   Management  charged  the  following  to  the  projects  based  on
   proportionate amounts invested:

                                 For the Year Ended December 31,
                                 ------------------------------
                                   2000       1999       1998
                                 --------   --------   --------
JRW Associates, L.P. .........   $108,859   $150,621   $119,960
Byron Power Partners, L.P. ...     64,396     89,092     70,956
Ridgewood Providence Power
 Partners, L.P. ..............    344,040    404,056    401,290
Ridgewood El Segundo LLC .....     12,452     17,055      9,120
On-site Cogeneration Projects:
 Ridgewood/Mass PPLP .........     57,590     91,296    106,685
 Ridgewood/Elmsford PPLP .....     25,660     40,374     47,385
 Other On-site Cogeneration
 Project Partnerships ........     40,862     56,532    100,005

   5.    Line of Credit Facility

   During the fourth quarter of 1997,  the Trust and the Trust's  principal bank
   executed a revolving line of credit agreement,  whereby the bank will provide
   a three year committed line of credit facility of $757,000. In December 2000,
   the credit facility was extended until March 5, 2001.  Outstanding borrowings
   bear  interest at the bank's prime rate or, at the Trust's  choice,  at LIBOR
   plus 2.5% (9.07% and 7.81% at December 31, 2000 and 1999, respectively).  The
   credit  agreement  requires  the Trust to  maintain  a ratio of total debt to
   tangible net worth of no more than 1 to 1 and a minimum debt service coverage
   ratio of 2 to 1. In the second quarter of 2000,  the Trust borrowed  $725,000
   under the line of credit facility, at an average rate of approximately 8.94%,
   which was repaid in the fourth  quarter of 2000.  At  December  31,  2000 and
   1999, there were no borrowings outstanding under the credit facility.

   6.    Arbitration and Litigation

   In December 1996, the Trust's  subsidiaries that own the on-site cogeneration
   projects brought an arbitration proceeding against EUA, claiming that EUA had
   breached  its  representations  in the  acquisition  agreement  and had  also
   defrauded the Trust through  misrepresentations,  improper billing  practices
   and  violations  of state fair trade  practice  laws.  In October  1998,  the
   arbitrators  awarded the Trust  damages of  approximately  $2,600,000  on its
   claims  and  awarded  approximately   $400,000  to  EUA  for  alleged  unpaid
   management  services  thereon.  In  November  1998,  EUA  made a  payment  of
   $2,210,184  to the Trust to  liquidate  the  claims.  After  deducting  costs
   associated with the arbitration  proceeding,  the Trust recognized  income of
   $1,265,122.  In April 1999, the arbitration  panel also awarded the Trust its
   attorneys' fees and expenses  incurred in prosecuting  the claim,  net of EUA
   attorneys'  fees and expenses.  The panel also awarded the Trust  interest on
   the award, net of interest on EUA's counterclaim.  The trust received payment
   from EUA in 1999 and  recorded  income  of  $1,581,308  in the  statement  of
   operations.

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

7.       Administrative Proceeding at the Providence Project

In  September  1998,  the Region I office of the U.S.  Environmental  Protection
Agency  ("EPA") filed an  administrative  proceeding  against  Providence  Power
seeking to recover civil  penalties of up to $190,000 for alleged  violations of
operational  recordkeeping and training  requirements at the Providence Project.
In June  1999,  Providence  Power  settled  the  administrative  proceeding  for
approximately $86,000.

8.       Subsequent Event - Pacific Gas and Electric Company Financial Crisis

All energy  generated  by the San Joaquin and Byron  projects is sold to Pacific
Gas and Electric  Company ("PG&E') under power  contracts.  Currently,  and as a
result of the deregulation of the California  energy market,  PG&E has allegedly
suffered billions of dollars in losses during the later part of 2000 and to date
in 2001.  Due to the California  energy  crisis,  PG&E has been unable to pay in
full for electrical  energy and capacity  delivered in December 2000 and January
2001.  Accordingly,  the San Joaquin and Byron projects were unable to pay their
natural gas supplier for the gas delivered  for those  months.  In late January,
the gas supplier requested assurance of payment before it would agree to provide
natural gas during February. Due to PG&E's financial crisis and its inability to
pay, the San Joaquin and Byron  projects  were unable on their own to provide an
acceptable  assurance  or to pay the  arrears  and,  as a result,  the  supplier
refused to provide natural gas beyond February 6, 2001.

On February 1, 2000, PG&E made a partial payment equal to  approximately  15% of
the amount due for December  2000. On March 5, 2001,  PG&E made another  partial
payment equal to approximately 15% of the amount due January 2001. Those amounts
are  insufficient,  after payroll costs are met, to cover the amount owed to the
natural gas supplier.  PG&E effectively  acknowledges  that it owes the projects
for  December  and  January by virtue of  announcing  and  making a 15%  partial
payments.  On  February  6, 2001,  the Trust shut down the San Joaquin and Byron
projects  because the supplier of natural gas  terminated  deliveries of natural
gas as of that date. The shut down will be for an indefinite time.

In  addition to its  failure to pay the full  amount due for  December  2000 and
January 2001  deliveries,  PG&E has  indicated in letters to the San Joaquin and
Byron  projects,  as well as documents  filed with the  Securities  and Exchange
Commission, that it is unable or unwilling to make future payments to Qualifying
Facilities,  such as the projects. The Trust believes that PG&E's ability to pay
for the  electrical  energy and  capacity  it  received  or will  receive in the
future,  depends upon,  among other things,  positive  action by the  California
governor and legislature to fund  approximately  $12 billion of losses allegedly
suffered by California utilities during the last eight months. The Trust expects
that any such political solution may be accompanied by executive, legislative or
regulatory  attempts  to  reduce  unilaterally  the  amounts  owed  by  PG&E  to
Qualifying Facilities. In an effort to resolve the California crisis, there have
been numerous proposals by the California Public Utilities  Commission ("CPUC"),
as well as the  legislature,  to adjust  downward the prices paid by  California
utilities  to  Qualifying  Facilities.  The Trust  expects  that any  regulatory
proceeding to set an energy price  applicable to Qualifying  Facilities  will be
extremely protracted and that a legislative  solution, if one were to be enacted
and approved by the governor,  is likely to be arbitrary and significantly below
the avoided cost of the energy to PG&E.

PG&E has attempted to justify its  non-payment  by invoking the "force  majeure"
provisions of the power  contracts.  In essence,  PG&E argues that it is excused
from its  payment  obligations  because  its failure to pay is the result of the
CPUC actions in failing to increase its rates to retail  customers and is beyond
its  control.  The Trust  disagrees  and  believes  that PG&E has  breached  the
contract.  The  projects,  along with the  Monterey  project  owned by Ridgewood
Electric  Power  Trust II  ("Trust  II"),  filed a lawsuit on  February  6, 2001
against PG&E to that effect and are seeking  damages  equal to lost net revenues
for the remaining term of the power  contracts.  By this lawsuit the Trust seeks
to have  the  power  contracts  with  PG&E  declared  null  and void so that the
projects will be able to sell their  electric  power on the open market to third
party  purchasers who will be able to pay currently for such electric power. The
Trust expects that it will be able  purchase  natural gas if it is free from the
PG&E contract and able to sell to credit worthy purchasers. The Trust is seeking
an accelerated  determination by the California court. The Trust is hopeful that
an accelerated determination by the court is a possibility considering the power
emergency  in  California,  which may get worse as warm weather  approaches  and
power demand  increases.  Also,  in an attempt to get the projects  back on-line
quickly, on March 8, 2001, the managing shareholder,  on behalf of the Trust and
Trust II,  filed  with the  Federal  Energy  Regulatory  Commission  ("FERC")  a
"Request For Emergency  Relief and  Extension of Waiver of  Qualifying  Facility
Regulations" in which the managing shareholder likewise seeks an order from FERC
permitting Qualifying Facilities to sell to third parties.

Until the San  Joaquin and Byron  projects  can  restart  profitably,  they will
remain shut down,  they will incur payroll and shutdown  costs and they will not
earn revenue. For the reasons described above, the Trust cannot estimate when it
will  restart the San Joaquin and Byron  projects or what their  short-term  and
long-term  prospects  may be. At this time,  the Trust does not  believe  that a
long-term impairment of the San Joaquin and Byron projects' value has occurred.


<PAGE>

POWER OF ATTORNEY

         KNOW ALL  PERSONS BY THESE  PRESENTS,  that the  undersigned,  Ralph O.
Hellmold,  appoints Robert E. Swanson and Martin V. Quinn,  and each of them, as
his true and lawful  attorneys-in-fact  with full power to act and do all things
necessary,  advisable or  appropriate,  in their  discretion,  to execute on his
behalf as an  Independent  Trustee of Ridgewood  Electric  Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form 10-K for the year
ended December 31, 2000 for each of the above-named  trusts,  and all amendments
or documents relating thereto.

         IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 24th day of March, 2001, at Carlsbad, California.

                                                    /s/Ralph O. Hellmold
                                                       Ralph O. Hellmold

POWER OF ATTORNEY


         KNOW ALL PERSONS BY THESE PRESENTS,  that the undersigned,  Jonathan C.
Kaledin,  appoints  Robert E. Swanson and Martin V. Quinn,  and each of them, as
his true and lawful  attorneys-in-fact  with full power to act and do all things
necessary,  advisable or  appropriate,  in their  discretion,  to execute on his
behalf as an  Independent  Trustee of Ridgewood  Electric  Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form 10-K for the year
ended December 31, 2000 for each of the above-named  trusts,  and all amendments
or documents relating thereto.

         IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 24th day of March, 2001, at Carlsbad, California.

                                                     /s/Jonathan C. Kaledin
                                                     Jonathan C. Kaledin

POWER OF ATTORNEY


     KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned,  Joseph Ferrante,
Jr.,  appoints  Robert E. Swanson and Martin V. Quinn,  and each of them, as his
true and  lawful  attorneys-in-fact  with  full  power to act and do all  things
necessary,  advisable or  appropriate,  in their  discretion,  to execute on his
behalf as an  Independent  Trustee of Ridgewood  Electric  Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form 10-K for the year
ended December 31, 2000 for each of the above-named  trusts,  and all amendments
or documents relating thereto.

         IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 24th day of March, 2001, at Carlsbad, California.

                                                     /s/ Joseph Ferrante, Jr.
                                                       Joseph Ferrante, Jr.