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, 2001

                         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

         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, 2002 was $39,034,440.

Exhibit Index is located on page [  ].


<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 Ridgewood Electric Power Trust III (the "Trust") from time to time,
includes forward-looking statements. These statements discuss business trends
and other matters relating to the Trust's future results and business. In order
to make these statements, the Trust has had to make assumptions as to the
future. It has also had to make estimates in some cases about events that have
already happened, and to rely on data that may be found to be inaccurate at a
later time. Because these forward-looking statements are based on assumptions,
estimates and changeable data, and because any attempt to predict the future is
subject to other errors, what happens to the Trust in the future may be
materially different from the Trust's statements here.

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

         Some of these are changes in political and economic conditions, federal
or state regulatory structures, government taxation, spending and budgetary
policies, government mandates, demand for electricity and thermal energy, the
ability of customers to pay for energy received, supplies and prices of fuels,
operational status of plant, mechanical breakdowns, availability of labor and
the willingness of electric utilities to perform existing power purchase
agreements in good faith.

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

(a)  General Development of Business.

         The Trust was organized as a Delaware business trust on 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") pursuant to a private placement offering (the
"Offering"), which terminated on May 31, 1995. Net of Offering fees, commissions
and expenses, the Offering provided approximately $32.9 million of net funds
available for investments in the development and acquisition of Projects. The
Trust has 780 record holders of Investor Shares (the "Investors"). As described
below in Item 1(c)(2), the Trust has invested substantially all of its net funds
in the Projects.

    The Trust made an election to be treated as a "business development company"
under the Investment Company Act of 1940, as amended (the "1940 Act"). On
February 14, 1994, the Trust notified the Securities and Exchange Commission of
such election and registered the Investor Shares under the Securities Exchange
Act of 1934, as amended (the "1934 Act"). On April 16, 1994, the election and
registration became effective. On November 5, 2001, the Trust issued to the
Investors a "Notice of Solicitation of Consents," in which the Trust sought the
consent of the Investors to withdraw its election to be treated as a "business
development company" under the 1940 Act and to make certain amendments to the
Trust's Declaration of Trust ("Declaration") as a result of such withdrawal,
including, but not limited to, deleting the section of the Declaration requiring
Independent Trustees. Consents were tabulated at the close of business on
December 18, 2001. A total of 391.8444 Investor Shares were outstanding and
entitled to be voted. Based on such tabulation, a majority of Investor Shares
consented to such withdrawal and amendments. On January 10, 2002, the Trust
filed with the Securities and Exchange Commission a notification to withdraw its
election to be treated as a "business development company." As a result of such
withdrawal, the Trust now utilizes generally accepted accounting principles for
operating companies.

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

         Ridgewood Energy Holding Corporation ("Ridgewood Holding"), a Delaware
corporation, is the Corporate Trustee of the Trust. The Corporate Trustee acts
on the instructions of the Managing Shareholder and is not authorized to take
independent discretionary action on behalf of the Trust. See Item 10. Directors
and Executive Officers of the Registrant below for a further description of the
management of the Trust.

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

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

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

o Ridgewood Electric Power Trust 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 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 6 small cogeneration facilities located in California, New
         York and Massachusetts purchased from Eastern Utilities Associates,
         Inc. (the "On-site Cogeneration Projects"); (iv) an additional
         cogeneration project located at an airline food preparation facility in
         Los Angeles, California (the "El Segundo Project"); (v) Ridgewood/AES
         Power Partners, L.P., a joint venture that operates 8 small
         cogeneration projects in New York; (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").

(2)  The Trust's Investments.

(i)  San Joaquin Project and Byron Project.

         On January 17, 1995, the Trust and a wholly-owned subsidiary acquired
100% of the existing partnership interests of JRW Associates, L.P., a California
limited partnership which owns and operates an approximately 8.53 megawatt
electric cogeneration facility located in the City of Atwater, Merced County,
California (the "San Joaquin Project"). The aggregate cash purchase price paid
by the Trust for 100% of the partnership interests was $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 "Byron Partnership"). On January 17, 1995,
the Byron Partnership acquired through a merger all of the assets and business
of Altamont Cogeneration Corporation, including an approximately 5.7-megawatt
electric cogeneration facility located near the city of Byron, Alameda County,
California (the "Byron Project"). The 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 electric output to PG&E under a Power Contract substantially
similar to that of the San Joaquin Project (collectively the "Power Contracts").
The Power Contract for the Byron Project also expires in 2020. The Byron
Project's heat output is used to evaporate brine from oil and gas wells, with
payments by the Byron Project for the site lease offsetting the thermal host's
payments for heat.

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


         In 1996, the State of California deregulated its electric industry and,
among other things, required PG&E, as well as the other two investor-owned
utilities ("IOUs")in California 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 California
Power Exchange ("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, the price for electricity
increased and 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.


         As a result of the California energy crisis, PG&E did not pay in full
for electrical energy and capacity delivered by the NorCal Projects in December
2000 and January 2001. Accordingly, the NorCal 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 NorCal 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. 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 January 2001. These amounts were
insufficient, after payroll costs are met, to cover the amount owed to the
natural gas supplier. On Tuesday, February 6, 2001, the Trust shut down the
NorCal Projects because the supplier of natural gas terminated deliveries of
natural gas as of that date. Many QFs under contract with PG&E suffered the same
fate and were forced to shut operations because of PG&E's failure to pay for
energy and capacity delivered. The NorCal Projects, along with the Sunnyside
Cogeneration Partners, L.P., owner of the Monterey Project, which is owned by
Power II and has a Power Contract with PG&E, instituted a lawsuit in California
state court against PG&E for breach of the power contract. On April 4, 2001, as
a result of its financial problems, PG&E filed for protection under the U.S.
Bankruptcy laws. As a result of such filing, the action the NorCal Projects
brought against PG&E in California state court was stayed pursuant to and as
required under the Bankruptcy Code.

         In April of 2001, the NorCal Projects entered into an agreement with
AMROC Investment, LLC ("AMROC") to sell to AMROC the NorCal Projects' rights to
the outstanding PG&E accounts receivable. AMROC simply acted as the NorCal
Projects' counterparty and was an intermediary for the real purchaser of the
accounts receivable who entered into a purchase agreement for such receivables
with AMROC. The NorCal Projects sold their accounts receivable at a discount but
did so at time when PG&E was bankrupt. As indicated, the Projects had not been
paid in full for the electric energy and capacity delivered during December 2000
and January 2001 and, although it had shut down operations on February 6, 2001,
was nonetheless incurring substantial expenses. Selling the accounts receivable
provided the NorCal Projects with available cash to pay outstanding and current
expenses and shifted the risk of PG&E's bankruptcy to a third party.

         In the second half of 2001, the natural gas supplier made demands for
payment of the arrears owed by the NorCal Projects. In December 2001, the
Monterey and NorCal Projects (each of whom used the same natural gas supplier)
and the natural gas supplier executed settlement agreement. Pursuant to the
settlement agreement, the Monterey and NorCal Projects were required to pay the
natural gas supplier an upfront payment against the arrearage and the remainder
to be paid over the next two years at 8% interest rate per annum. The entire
balance is required to be discharged no later than the end of July 2003. The
payments to the natural gas supplier were based upon the amount of gas used by
each project. As a result of the upfront payment, the Monterey Project has
completely discharged its obligation to the natural gas supplier. The NorCal
Projects are responsible for the remaining balance.

         Subsequent to its bankruptcy filing, PG&E found itself under intense
pressure to pay the QFs that had shut downs operations in order to get their
electric generation back online and supplying the electric starved State of
California. Therefore, in an effort to get as many QFs back online as possible,
PG&E sought and received approval from the CPUC to offer each QF an agreement,
and corresponding amendment to their Power Contracts, which, for a term of five
(5) years, would effectively replace the variable SRAC formula for determining
the energy price with a fixed energy price. Such amendment, if signed by the QF
and PG&E and approved by the U.S. Bankruptcy Judge, would enable the QF to
operate at a price that appeared to be reasonable in light of the circumstances
at that time. In addition, a QF that executed the amendment agreed that it would
not institute or dismiss existing litigation against PG&E and wait for payment
from PG&E of any outstanding balance until such time as the Bankruptcy Plan of
Reorganization is confirmed by the Bankruptcy Judge. Such plan has not yet been
confirmed. Finally, in order to execute an amendment to the Power Contract with
a fixed energy price, it was necessary to procure natural gas at a fixed price.
The NorCal Projects were able to procure such supply of natural gas from Coral
Energy Services, Inc., ("Coral") a subsidiary of Shell Oil. As a result, the
NorCal Projects each executed the agreement and amendment. Until approximately
August 2006, the NorCal Projects will be operating under the Amendment, which is
expected to result in positive cash flow to the Projects.

(ii)  On-site Cogeneration Projects

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

         Returns from the On-site Cogeneration Projects 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
recorded writedowns of $10.7 million relating to On-site Cogeneration Projects
the since their purchase.

         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"). 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 and
dismissed by the District Court in Massachusetts without prejudice to restore it
pending the termination and outcome of the bankruptcy proceeding. 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 were approved by the Bankruptcy Court. 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 purchaser of
the Globe assets regarding the possibility of the Trust selling power to either
the new purchaser, pursuant to the same or renegotiated Power Contract, or to
the wholesale market. Such discussions have not been positive. 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.

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

 (iii) Ridgewood/AES Power Partners, LLC.

         The Trust engaged AES-NJ Cogen, Inc., a small operator of cogeneration
plants ("AES") that is not affiliated with the Trust, to operate eight of the
smallest On-Site Cogeneration Projects. In September 1997 the Trust and AES
created a joint venture, Ridgewood/AES Power Partners, L.P. ("Ridgewood AES") to
develop additional small cogeneration projects in the New York metropolitan
area. The Trust supplies capital and AES supplies development services. At
December 31, 1999 Ridgewood AES owned eight cogeneration projects at hotels and
hospitals in New York and New Jersey.

         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.

(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. During 2000, the
Trust analyzed the carrying value of the El Segundo Project assets using an
estimated undiscounted cash flow analysis and wrote down the value of the
Project to zero. During much of 2001, the project was idle due to the high costs
of natural gas, although negotiations with the owner of the food preparation
facility have begun and the Trust is hopeful that the project will soon be
operating.

(vi)  Providence Project

         The Trust and Power IV acquired in April 1996 all of the equity
interest in an landfill gas-fired electric generating facility, located on land
adjacent to the Central Landfill, near Providence, Rhode Island. The Trust
invested $7.1 million in the Providence Project and Power IV supplied the
remainder of the $20 million investment in the Project. The Trust owns 35.7% of
the Providence Project and Power IV owns the remaining 64.3%. The acquisition
cost was approximately $15.5 million (including a $3 million partial prepayment
of Project debt as a condition of obtaining the lenders' consents and
transaction costs) and the remainder of the investment by the programs
represents funds applied to operating reserves, working capital and reserves for
capital improvements and expansion. The Providence Project was encumbered by
$5.4 million of debt maturing in installments through 2004. As of December 31,
2001, the total investment was $5,478,000.

         The Project burns methane gas generated by the decomposition of garbage
and other waste in the landfill as fuel for a 13.8 Megawatt capacity electric
generation plant. The facility has been in operation since 1990 and has a Power
Contract for 12.0 megawatts (MW)with New England Power Company ("NEP") that
expires in 2020.

         The Project leases the right to use the landfill site from the Rhode
Island Resource Recovery Corporation, a state agency ("RIRRC"), for a royalty of
15% of net Project revenues (increasing from 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.

         As described in more detail in Item 3 - Legal Proceedings, the
Providence Project, RIRRC and Gasco were all named by the United States
Environmental ("EPA") Agency in certain Administrative Orders in which the EPA
alleged various violations of environmental law and regulations. The Providence
Project has entered into a Consent Decree with the EPA settling all alleged
claims against the Providence Project. Currently, RIRRC and Gasco are finalizing
a consent decree with the EPA that will settle the EPA's alleged claims against
RIRRC and Gasco and require that certain actions be taken and maintained in the
future to maintain the landfill and gas collection systems.

         In addition, throughout the Trusts' ownership of the Providence
Project, there situation have occurred at the landfill regarding Gasco's
operation and maintenance of the gas collection system, which has convinced the
Trust and Power IV that the gas collection system could be operated and
maintained more efficiently and economically and could provide higher quality,
and greater quantities of, landfill gas. The resulting savings in costs and
increase in quantity and quality of methane gas will benefit the Providence
Project. In addition, RIRRC currently anticipates that the Central Landfill will
be capable of providing landfill gas from new phases that could fuel an
additional 12 MW.

         Therefore, the Trust and Power IV have formed Ridgewood Gas Services,
LLC, which is currently negotiating with RIRRC and Gasco for the right to
operate and maintain the gas collection systems owned by RIRRC and Gasco. As
part of the transaction, Ridgewood Rhode Island Generation, LLC, also owned by
the Trust and Power IV, will obtain rights to landfill gas from RIRRC and
develop and additional 7.5 MW landfill gas-fired electric generation facility.
Such negotiations, however, are not final and there is no guarantee that such
transaction will be negotiated and finalized.

(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.

(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 Managing Shareholder organized RPM to provide operating management
for the Projects. See Item 10 -- Directors and Executive Officers of the
Registrant and Item 13 -- Certain Relationships and Related Transactions for
further information regarding the Operation Agreement with RPM and for the cost
reimbursements received by RPM.

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

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

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

                                           Calendar year
                                   2001           2000          1999
Pacific Gas & Electric Co.
 (San Joaquin & Byron Projects)    53.1%          68.3%        42.6%
Coca Cola Bottling Plant of New
  York (Coca Cola Project)         17.4%          11.4%         8.1%
Globe Manufacturing Co.
 (Globe Project)                    -               -          24.3%

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

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

         Compliance with environmental laws is also a material factor in the
independent power industry. The Trust believes that capital expenditures for,
and other costs of, environmental protection have not materially disadvantaged
its activities relative to other competitors and will not do so in the future.
See Item 1(c)(6) -- Business -- Narrative Description of Business -- Regulatory
Matters.

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

         The year 2001 was an extremely volatile and unpredictable year for the
electric generation and independent electric power industry. In the State of
California, where the NorCal Projects are located, the year began with the state
experiencing severe electricity shortages. Such shortages were due to a variety
of factors including, but not limited to, seriously flawed electric deregulation
legislation and implementation, explosive growth in California's electric
consumption, the failure of the state to add significant electric generation,
environmental regulations, electric transmission constraints, natural gas
shortages, and the lack of available electric supply from other areas of the
western United States. As a result, California, particularly San Francisco,
experienced rolling blackouts, high wholesale electric prices, and subsequently,
retail electric rates soared, and the California investor owned electric
utilities ("IOUs") experienced severe and critical cash shortages due, in large
part, to the fact that for 2000 and part of 2001 their rates to retail consumers
were frozen such that increased wholesale prices could not be passed on to
consumers. PG&E thus declared bankruptcy in April 2001 and for much of the
summer and fall of 2001, it was not at all clear whether Southern California
Edison Company would be able to survive without declaring bankruptcy. Moreover,
other parts of the United States, particularly New England, experienced
wholesale price spikes and shortages and while there was speculation that such
areas would experience California type blackouts and shortages, such events
never materialized.

         Predictably, legislators, regulators and consumer advocates diverted
blame for the "electric crisis" on attempts by independent power producers,
other generators of electric energy and marketers of such energy to exert market
power and manipulate the market to, effectively, extract monopoly type prices
from California. Such assertions, however, have not been proven to be factual,
although investigations at various levels of government still continue. It
appears that the causes of the crisis are much more complex and the assertions
typical political rhetoric. Nevertheless, despite such rhetoric, the legislators
and regulators did respond rather rapidly to the electric crisis. For example,
the Federal Energy Regulator Commission ("FERC") removed certain vestiges of
California's deregulation legislation (such as the requirement that all
California IOUs buy and sell all of the electricity through a short term, highly
unpredictable energy market), imposed wholesale price caps, allowed excess power
from QFs to be sold to third parties, and instituted certain price mitigation
policies. In addition, the State of California responded also by increasing the
retail electric rates to reflect more accurately the wholesale electric price,
providing incentives for conservation, streamlining the permitting process so as
to increase and speed the construction of new electric generation, and beginning
itself, through the California Department of Water Resources ("DWR"), to
purchase power on behalf of the IOUs and enter into long-term power contract to
ensure and maintain adequate supply.

         During 2001, as a result of the high wholesale prices in California and
other parts of the United States, independent power producers naturally
responded by either purchasing additional existing electric generation or
announcing plans to build additional new electric generation. There were
estimates that an additional 50,000 MWs would be constructed during the next
several years. While such purchasing and proposed construction began prior to
2001 and was not all in response to the California electric crisis, there is not
doubt that such crisis accelerated IPP purchasing and proposed construction.

         However, as 2001 progressed the electric crisis appeared to fade and
wholesale prices fell significantly. Such change was due in large measure to the
work of the DWR, as well as an extremely mild summer in California, an increase
electric conservation and a decrease in natural gas prices, which fuel an
overwhelming majority of the power plants in California.

         In April of 2001, the California Legislature authorized the California
Power Authority ("CPA"), a state agency, to issue up to $5 billion dollars in
revenue bonds to solve the states electricity problems, although such bond issue
has not been completed. The CPA is charged with the responsibility of
maintaining adequate reserves and supplies of electricity at reasonable costs
such that the shortages experienced by California would not likely occur in the
future. To that end, the CPA has been negotiating with IPPs that entered into
long-term contracts with the DWR in an attempt to lower the rates paid by the
DWR (i.e., the State of California) for such electric energy. In addition, the
CPA is responsible for ensuring that California's electric supply portfolio
includes a significant amount of renewable resources.

         In addition to the problems described above regarding California, on
December 2, 2001, Enron Corp. ("Enron") filed for protection under the U.S.
Bankruptcy Code in the largest bankruptcy filing in United States history. While
extremely complicated and still the subject of a large number of congressional
and regulatory agency investigations, it appears that the Enron bankruptcy
resulted in large measure to the restatement of earnings and reduction of
shareholders' equity that Enron announced due to accounting irregularities.
Because Enron is primarily a power marketer that relies heavily on an investment
grade credit to conduct its power marketing business, when the restatements were
announced, rating agencies, such as Moody's and Standard & Poor's, lowered
Enron's credit rating, which in turn caused Enron's trading partners to
liquidate power contracts and/or refuse to continue to conduct business with
Enron. Enron's bankruptcy soon resulted.

         As a result of Enron's bankruptcy, many independent power producers
have seen their stock prices and credit rating plummet. In an attempt to reverse
such events, many have attempted to "clean-up" their balance sheets and reduce
debt by either selling (or attempting to sell) power facilities recently
purchased and have also cancelled proposed new construction. In addition to
Enron's bankruptcy, the extremely low wholesale prices, the erratic regulatory
framework and the act that many states, including California, have either
canceled deregulation or limited its scope and appeal, have all contributed to
decision to discontinue construction of new power plants. Although electric
supply is currently meeting demand nationwide due, in large measure, to mild
weather, low gas prices, new generation already online, and the economic
downturn, there is a possibility that should the economy turn around, gas prices
increase, conservation decrease and demand increase, shortages nationwide could
result. While such shortages could create social and political problems for
entities that own and operate electric generation facilities, such as the Trust,
electric shortages generally equate to higher wholesale electric prices and a
favorable market within which to sell electric energy .

         In conclusion, the trend in the industry, as a result of the matters
detailed below, may be a retrenching and reversion to a more regulated electric
industry, with strict reporting requirements and cost of service regulation.
However, many of those charged with the responsibility of investigating the
Enron or the California problems have not disavowed deregulation. In any event,
such market changes and reporting requirements, if adopted, may not impact upon
the Byron and San Joaquin Projects, both of which currently have a Power
Contract with PG&E.

         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. The Trust has no direct
exposure to Enron. The Trust's indirect exposure to Enron cannot yet be
determined.

(5)  Competition

         The San Joaquin, Byron and Providence Projects, as described above, are
not currently subject to competition because those Projects have entered into
long-term agreements to sell their output at specified prices. However, if the
Power Contracts were terminated for any reason, the San Joaquin and Byron
Projects could be subject to future competition to market its electricity output
However, the Trust believes that in the near term, until additional generation
resources are completed and brought on-line, 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 QF
due to failure to meet minimum steam output requirements; or other reasons. It
is impossible at this time to estimate the level of marketing competition that
the Trust would face in any such event.

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

(iv)  Potential Legislation and Regulation.

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

(6)  Regulatory Matters.

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

(i)  Energy Regulation.

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

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

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

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

         (C) The Federal Power Act("FPA"). The FPA grants FERC exclusive
rate-makingjurisdiction 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 QF under PURPA are exempt from the rate-making and certain
other provisions of the FPA, non-QFs are subject to the FPA and to FERC
rate-making jurisdiction.

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

         (E) State Regulation. State public utility regulatory commissions have
broad jurisdiction over Independent Power Projects which are not QFs under
PURPA, and which are considered public utilities in many states. In addition,
states may assert jurisdiction over the siting and construction of non-QFs and,
among other things, issuance of securities, related party transactions and sale
and transfer of assets. The actual scope of jurisdiction over non-QFs by state
public utility regulatory commissions varies from state to state.

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

(ii)  Environmental Regulation.

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

         The 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 permits for point sources of
discharges and by stormwater permits. Under the Clean Water Act, such permits
must be renewed every five years and permit limits can be reduced at that time
or under re-opener clauses at any time. The Projects have not had material
difficulty in complying with their permits or obtaining renewals. The Projects
use closed-loop engine cooling systems which do not require large discharges of
coolant except for periodic flushing to local sewer systems under permit and do
not make other material discharges to 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.

(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        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     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 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 denied the EPA's claims, the EPA and
Ridgewood settled the EPA's claims against Ridgewood through the mechanism of a
Consent Agreement and Order that will fully resolve the EPA's claims against the
Providence Project in consideration and paid an administrative penalty of
approximately $25,000 in 2001.

         In addition to the foregoing, the RIRRC and GASCO entities are being
pursued by the EPA for alleged violations of federal statutes and regulations
concerning their operations. RIRRC and GASCO may or may not settle those claims
with the EPA. If GASCO or RIRRC do not settle the 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. Given the financial condition of Globe, the Trust does
not believe that sufficient assets will remain to pay any judgment against Globe
and therefore has determined not to pursue the litigation and is awaiting a
determination from the Bankruptcy Court as to whether any funds are available to
pay rejection damages.

         In March of 2001, the NorCal Projects, along with the Monterey Project
owned by Power II, instituted a lawsuit in California State Court against PG&E
for its failure to pay for energy and capacity delivered during December 2000
and January 2001. As detailed above, that lawsuit was stayed when PG&E filed for
bankruptcy on April 4, 2001 and ultimately dismissed when the NorCal Projects
and the Monterey Project executed an agreement and amendment to the Power
Contract with PG&E.

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

         On November 5, 2001, the Trust issued to the owners of Investor Shares
(the "Investors") a "Notice of Solicitation of Consents," in which the Trust
sought the consent of the Investors to withdraw its election to be treated as a
"business development company" under the 1940 Act and to make certain amendments
to the Trust's Declaration as a result of such withdrawal, including, but not
limited to, deleting of the section of the Declaration requiring Independent
Trustees. Consents were tabulated at the close of business on December 18, 2001.
A total of 391.8444 Investor Shares were outstanding and entitled to be voted.
Based on such tabulation, a majority of Investor Shares consented to such
withdrawal and amendments. On January 10, 2002, the Trust filed with the
Securities and Exchange Commission a notification to withdraw its election to be
treated as a "business development company."

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 has investigated the possibility and
feasibility of a combination of the six Trusts and the 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, and a change in the
federal income tax status of the Trust 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. After conducting investigations during 2001, the Managing
Shareholder concluded, and informed the Investors, that given current market
conditions caused by, among other things, the general U.S. economic down turn,
the September 11th terrorist attacks, the Enron bankruptcy and general
volatility in the independent power business, it is preferable to delay
significant expenditures pursuing any such combination until market conditions,
as described above, improve.

(b)  Holders

         As of the date of this Form 10-K, there are 780 record holders of
Investor Shares.

(c)  Dividends

     The Trust made distributions as follows for the years ended December 31,
2001 and 2000:

                             Year ended            Year ended
                         December 31, 2001      December 31, 2000
Total distributions
 to Investors             $  --                 $  1,763,304
Distributions per
 Investor Share           $  --                        4,500
Distributions to
 Managing Shareholder     $  --                       17,811

         The Managing Shareholder discontinued quarterly distributions effective
January 1, 2001. The Trust's decision whether to make future distributions to
Investors and their timing will depend on, among other things, the net cash flow
of the Trust and retention of reasonable reserves as determined by the Trust to
cover anticipated expenses. See Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations.

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

Item 6.  Selected Financial Data.

     The following data is qualified in its entirety by the financial statements
presented elsewhere in this Annual Report on Form 10-K. As described in such
financial statements, financial information for the years 1997 through 2000 have
been restated to reflect the application of new accounting principles as a
result of the Trust's election to terminate its status as a business development
company. The selected financial data for 1997 and 1998 were derived from
unaudited data.

Selected Financial Data
                        As of and for the year ended December 31,
                     2001      2000      1999       1998        1997
                             Restated   Restated  Restated    Restated
Total Fund Information:

Revenues         $6,383,067 $9,590,113 $9,735,514 $11,364,992 $13,355,865
Net income (loss)(1,482,487)(2,521,130) 1,091,759  (2,049,175) (3,092,980)
                               (A)        (B)         (C)         (D)
Net assets
(shareholders'
  equity)        15,629,674 17,112,161 21,414,406  22,699,866  25,044,088
Investments in
 Plant and
 Equipment (net
 of depreciation) 7,863,053  8,468,270 11,904,223  11,152,886  11,499,289
Investment
 in Power
 Contract(net
 of amortization) 1,291,320  1,363,060  1,434,800   1,506,540   1,434,798
Total assets     17,480,795 18,919,336 21,255,421  24,405,244  25,732,315
Long-term
obligations         250,000         --         --          --          --
Per Share:
Revenues             16,290     24,474     24,845      29,004      34,084
Net income(loss)     (3,783)    (6,434)     2,786      (5,230)     (7,893)
                       (A)        (B)         (C)         (D)
Net asset value      39,887     43,671     54,650      57,931      63,913
Distributions
 to Investors            --      4,500       6,006      6,003        7,771

(A) Includes writedowns of investments of $2,780,083 ($7,095 per Investor
Share). (B) Includes $1,581,308 of income from arbitration award ($4,036 per
Investor Share) (C) Includes writedowns of investments of $4,055,214 ($10,349
per Investor Share) and income of $1,265,122 ($3,229 per Investor Share) from
arbitration award. (D) Includes 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 below. Dollar
amounts in this discussion are generally rounded to the nearest $1,000.

Outlook

The Providence, San Joaquin and Byron Projects are "Qualified Facilities" as
defined under the Public Utility Regulatory Policies Act of 1978 and currently
sell their electric output to utilities under long-term contracts expiring in
2020. During the term of the contracts, the utilities may or may not attempt to
buy out the contracts prior to expiration. At the end of the contracts, the
Projects will become merchant plants and may be able to sell the electric output
at then current market prices. There can be no assurance that future market
prices will be sufficient to allow the Projects to operate profitably.

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

Significant Accounting Policies

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

Results of Operations

The year ended December 31, 2001 compared to the year ended December 31, 2000.

Total revenues decreased $3,207,000, or 33%, to $6,383,000 in 2001 from
$9,590,000 in 2000. The decrease in revenues is due primarily to the shut down
of the San Joaquin and Byron Projects from February to August 2001 due to PG&E's
non-payment of amounts owed to the project (see Item 1(c)iii).

Gross profit, which represents total revenues reduced by cost of sales,
decreased by $1,674,000 to a gross loss of $162,000 in 2001 from a gross profit
of $1,512,000 in 2000. The decrease in gross profit primarily reflects the
decrease in revenues discussed above. Cost of sales decreased by $1,533,000 or
19% from $6,545,000 in 20001 from $8,078,000 in 2000 due to the shut down on the
San Joaquin and Byron Projects for almost six months in 2001 and lower
depreciation caused by the writedown of the Globe Project. The decrease in cost
of sales was less than the decrease in total revenues because the price of
natural gas was substantially higher in 2001 compared to 2000.

General and administrative expenses increased $34,000, or 4%, to $835,000 in
2001 from $801,000 in 2000. The increase reflects higher legal expenses in 2001
partially offset by lower expenses associated with the sale of PG&E receivables
to Amroc (which decreased $117,000 from $512,000 in 2000 to $229,000 in 2001
reflecting the greater amount of 2000 receivables sold as compared to 2001
receivables). The 2001 legal expenses primarily related to the dispute with PG&E
discussed in Item 3 above.

In 2000, the Trust recorded a writedown of $2,780,000 related to its investment
in the Globe Project which had ceased operations. The Trust did not record any
writedowns of projects in 2001.

The management fee paid to the Managing Shareholder decreased by $100,000, or
17%, to $493,000 in 2001 from $593,000 reflecting the lower net assets of the
Trust.

The loss from operations decreased $1,172,00, or 44%, to $1,490,000 in 2001 from
$2,662,000 in 2000 primarily reflecting the absence of the writedown of the
Globe Project partially offset by the deterioration in results from the Byron
and San Joaquin Projects.

Other income, net, decreased by $133,000 or 94%, to $8,000 in 2001 from $141,000
in 2000. The decrease is primarily due to costs incurred in issuing the "Notice
of Solicitation of Consents" to investors. The Trust's equity income in the
Providence Project decreased slightly in 2001 compared to 2000 due to higher
overhead costs but was partially offset by the absence of interest expense in
2001.

The Trust's net loss decreased $1,039,00, or 41%, to $1,482,000 in 2001 from
$2,521,000 in 2000 primarily reflecting the absence of the writedown of the
Globe Project partially offset by the deterioration in results from the Byron
and San Joaquin Projects.

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

         Total revenues decreased $146,000, or 1%, to $9,590,000 in 2000 from
$9,736,000 in 1999. The decrease in revenues was primarily attributable to a
$2,367,000 drop in revenue from the Globe Project offset by a $2,405,000
increase in revenue from the Byron and San Joaquin Projects. The decrease in the
revenue from the Globe project reflected its shutdown in 1999. The increase in
revenue from the Byron and San Joaquin Projects reflect their 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.

Gross profit, which represents total revenues reduced by cost of sales,
increased $1,412,000 to $1,512,000 in 2000 from $100,000 in 1999. The increase
primarily reflects the higher electricity prices received by the Byron and San
Joaquin Projects.

General and administrative expenses increased $661,000, or 472%, to $801,000 in
2000 from $140,000 in 1999. The increase primarily reflects $512,000 of expenses
recorded in 2000 associated with the sale of PG&E receivables generated by the
Byron and San Joaquin projects. The remaining increase was primarily due to
legal expenses associated with the Globe Project.

In 2000, the Trust recorded a writedown of $2,780,000 related to its investment
in the Globe Project. The Trust recorded $17,000 of writedowns of projects in
1999.

The management fee paid to the Managing Shareholder was relatively unchanged at
$593,000 in 2000, down $2,000 from the $595,000 recorded in 1999.

The loss from operations increased $2,010,000 to $2,662,000 in 2000 from
$652,000 in 1999, primarily reflecting the 2000 writedown of $2,780,000
partially offset by the improved results of the Byron and San Joaquin Projects.

Other income, net, decreased by $1,603,000 or 92%, to $141,000 in 2000 from
$1,744,000 in 1999. The decrease is primarily due to the absence in 2000 of
income of $1,581,000 resulting from arbitration proceedings related to the
acquisition of the on-site cogeneration projects. The Trust's equity income in
the Providence Project increased slightly in 2000 compared to 1999 due to lower
maintenance costs but was partially offset by interest expense in 2000.

The Trust recorded a net loss of $2,521,000 in 2000 compared to net income of
$1,092,000 in 1999, a change of $3,613,000. This deterioration primarily
reflects the 2000 writedown of $2,780,000 and the absence of the 1999
arbitration income of $1,581,000, partially offset by the improved results of
the Byron and San Joaquin Projects.

Liquidity and Capital Resources

In 2001, the Trust's operating activities used 362,000 of cash and in 2000 they
generated $1,492,000 of cash.

Cash generated from investing activities in 2001 and 2000 was $323,000 and
$108,000, relating to distributions from the Providence Project partially offset
by capital expenditures.

Cash used by financing activities of $1,781,000 in 2000 represents distributions
to shareholders. The Trust ceased making distributions to shareholders in the
first quarter of 2001.

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 $757,000. The credit line was extended
until July 31, 2002. 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. In the second quarter of 2000, the Trust borrowed
$725,000 under the line of credit which it repaid in the fourth quarter. There
were no borrowings under the line of credit in 2001. The Trust has issued
through its bank two standby letters of credit totaling $740,000 to secure gas
purchases for the Byron and San Joaquin Projects. These standby letters of
credit are collateralized by the line of credit and reduce the amount that may
be borrowed under the line of credit from $757,000 to $17,000.

Obligations of the Trust are generally limited to payment of a management fee to
the Managing Shareholder and payments for certain administrative, accounting and
legal services to third persons. Accordingly, the Trust has not found it
necessary to retain a material amount of working capital. The Trust's
significant long-term obligation is limited to two letters of credit, each in
the amount of $370,000, issued by the Byron and San Joaquin Projects which are
collateralized by the Trust's line of credit facility. The letters of credit
expire in August 2002 and the Byron and San Joaquin Projects and the Trust
anticipate renewing them annually through 2006. The letters of credit secure the
gas purchases of the Byron and San Joaquin Projects.

The Providence Project has secured long-term debt, without recourse to the
Trust, with scheduled principal payments as follows:
2002      $ 868,098
2003        955,202
2004        867,223
2005              -
2006              -

The Byron and San Joaquin Projects have certain long-term obligations relating
to their Power Contracts with PG&E and their Gas Agreements with Coral. The
Providence Project has certain long-term obligations relating to its Power
Contract with NEP, its property lease and its arrangements with its gas
supplier. The On-site Cogeneration Project, Ridgewood AES and the El Segundo
Project also have certain long-term obligations with the companies owning the
facilities where they are sited. None of these long-term obligations are
guaranteed by the Trust. The Trust and its subsidiaries anticipate that during
2002 their cash flow from operations will be sufficient to meet their
obligations.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

   Qualitative Information About Market Risk.

   The Trust's investments in financial instruments are short-term investments
of working capital or excess cash. Those short-term investments are limited by
its Declaration of Trust to investments in United States government and agency
securities or to obligations of banks having at least $5 billion in assets.
Because the Trust invests only in short-term instruments for cash management,
its exposure to interest rate changes is low. The Trust has limited exposure to
trade accounts receivable and believes that their carrying amounts approximate
fair value.

   The Trust's primary market risk exposure is limited interest rate risk caused
by fluctuations in short-term interest rates. The Trust does not anticipate any
changes in its primary market risk exposure or how it intends to manage it. The
Trust does not trade in market risk sensitive instruments.

   Quantitative Information About Market Risk

     This table provides information about the Trust's financial instruments
that are defined by the Securities and Exchange Commission as market risk
sensitive instruments. These include only short-term U.S. government and agency
securities and bank obligations. The table includes principal cash flows and
related weighted average interest rates by contractual maturity dates.

                        December 31, 2001
                       Expected Maturity Date
                            2001
                           (U.S. $)

Bank Deposits and Certificates of Deposit     $ 388,000
Average interest rate                              1.77%

Item 8.  Financial Statements and Supplementary Data.

Index to Consolidated Financial Statements

Report of Independent Accountants                      F-2
Consolidated Balance Sheet at December 31,
  2001 and 2000                                        F-3
Consolidated Statement of Operations for the
  three years ended December 31, 2001                  F-4
Consolidated Statement of Changes in Shareholders' Equity for the three years
  ended December 31, 2001                              F-5
Consolidated Statement of Cash Flows for the three
  years ended December 31, 2001                        F-6
Notes to Consolidated Financial Statements             F-7 to F-10

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

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.

(b) Managing Shareholder.

         Ridgewood Power Corporation was incorporated in February 1991 as a
Delaware corporation for the primary purpose of acting as a managing shareholder
of business trusts and as a managing general partner of limited partnerships
which are organized to participate in the development, construction and
ownership of Independent Power Projects. It organized the Trust and 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 the Other Power Trusts 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 funds 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 55, has also served as President of the Trust
since its inception in 1991 and as President of RPM, the Other Power Trusts,
since their respective inceptions. Mr. Swanson has been President and registered
principal of Ridgewood Securities and became the Chairman of the Board of
Ridgewood Capital on its organization in 1998. He also is Chairman of the Board
of the Ridgewood Capital Venture Partners I, II, III and IV venture capital
funds (collectively "Ridgewood Venture Funds"). In addition, he has been
President and sole stockholder of Ridgewood Energy since its inception in
October 1982. Prior to forming Ridgewood Energy in 1982, Mr. Swanson was a tax
partner at the former New York and Los Angeles law firm of Fulop & Hardee and an
officer in the Trust and Investment Division of Morgan Guaranty Trust Company.
His specialty is in personal tax and financial planning, including income,
estate and gift tax. Mr. Swanson is a member of the New York State and New
Jersey bars, the Association of the Bar of the City of New York and the New York
State Bar Association. He is a graduate of Amherst College and Fordham
University Law School.

         Robert L. Gold, age 43, has served as Executive Vice President of the
Managing Shareholder, RPM, the Trust, the Other Power Trusts since their
respective inceptions, with primary responsibility for marketing and
acquisitions. He has been President of Ridgewood Capital since its organization
in 1998. As such, he is President of the Ridgewood Venture Funds. He has served
as Vice President and General Counsel of Ridgewood Securities Corporation since
he joined the firm in December 1987. Mr. Gold has also served as Executive Vice
President of Ridgewood Energy since October 1990. He served as Vice President of
Ridgewood Energy from December 1987 through September 1990. For the two years
prior to joining Ridgewood Energy and Ridgewood Securities Corporation, Mr. Gold
was a corporate attorney in the law firm of Cleary, Gottlieb, Steen & Hamilton
in New York City where his experience included mortgage finance, mergers and
acquisitions, public offerings, tender offers, and other business legal matters.
Mr. Gold is a member of the New York State bar. He is a graduate of Colgate
University and New York University School of Law.

         Martin V. Quinn, age 54, has been the Executive Vice President and
Chief Operating Officer of the Managing Shareholder, RPM, the Trusts and Other
Power Trusts since April 2000. Before that, he had assumed the duties of Chief
Financial Officer of these entities 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 41, has been Senior Vice President and General
Counsel of the Managing Shareholder, RPM, the Trust and Other Power Trusts 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, 37, has been the Vice President and Chief
Financial Officer of the Managing Shareholder, RPM, the Trust and Other Power
Trusts 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 the Pennsylvania Institute of
Certified Public Accountants. He holds a Bachelor of Science degree in Business
Administration from Bucknell University (1986).

         Mary Lou Olin, age 49, has served as Vice President of the Managing
Shareholder, RPM, Ridgewood Capital, the Trust, the Other Power Trusts since
their respective inceptions. She has also served as Vice President of Ridgewood
Energy since October 1984, when she joined the firm. Her primary areas of
responsibility are investor relations, communications and administration. Prior
to her employment at Ridgewood Energy, Ms. Olin was a Regional Administrator at
McGraw-Hill Training Systems where she was employed for two years. Prior to
that, she was employed by RCA Corporation. Ms. Olin has a Bachelor of Arts
degree from Queens College.

(c)  Management Agreement.

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

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

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

         Each Investor consented to the terms and conditions of the initial
Management Agreement by subscribing to acquire Investor Shares in the Trust. The
Management Agreement is subject to termination at any time on 60 days' prior
notice by a majority in interest of the Investors or the Managing Shareholder.
The Management Agreement is subject to amendment by the parties with the
approval of a majority in interest of the Investors.

(d) Executive Officers of the Trust.

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

(e) Corporate Trustee

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

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

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

(g)  RPM.

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

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

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

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

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

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

Item 11.  Executive Compensation.

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

         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 of $84,000 in the offering
one full Investor Share. By virtue of its purchase of an Investor Share, the
Managing Shareholder is entitled to the same ratable interest in the Trust as
all other purchasers of Investor Shares. No other executive officers of the
Trust acquired Investor Shares in the Trust's offering.

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

Item 13.  Certain Relationships and Related Transactions.

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

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

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

         The Trust made distributions in 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:

                2001         2000         1999        1998          1997
Managing      $492,430     $592,664     $594,576    $673,933      $766,866
Shareholder
Cost
Reimburse-  $11,946,145   $12,143,034  $15,813,187   15,617,631   14,308,444
ments
RPM

         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 Consolidated Financial Statements in Item 8 hereof.

(b) Reports on Form 8-K.

     The Trust filed a report on Form 8-K on December 20, 2001 in which the
Trust reported upon the results of its consent solicitation to withdraw its
election as a business development company under the Investment Company Act of
1940 and make certain conforming amendments to the Declaration of Trust.

(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 __

<PAGE>


SIGNATURES

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


RIDGEWOOD ELECTRIC POWER TRUST III (Registrant)

By:/s/ Robert E. Swanson    President               April 15, 2002

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                April 15, 2002
Robert E. Swanson

By:/s/ Christopher Naunton  Vice President and       April 15, 2002
Christopher Naunton       Chief Financial Officer

RIDGEWOOD POWER LLC  Managing Shareholder            April 15, 2002
By:/s/ Robert E. Swanson    President
Robert E. Swanson

           Ridgewood Electric Power Trust III

           Consolidated Financial Statements

            December 31, 2001, 2000 and 1999


<PAGE>



Report of Independent Accountants


To the Shareholders of
Ridgewood Electric Power Trust III:

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in shareholders' equity and cash
flows present fairly, in all material respects, the financial position of
Ridgewood Electric Power Trust III and its subsidiaries (the "Trust") at
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, 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 discussed in Notes 1 and 2, effective on December 18, 2001, the shareholders
of the Trust consented to end its election to be treated as a Business
Development Corporation under the Investment Company Act of 1940. As a result,
accounting principles generally accepted in the United States of America for
investment companies no longer applied to the Trust and the Trust adopted
accounting principles generally accepted in the United States of America
applicable to operating companies. The financial statements of the Trust for
December 31, 2000 and 1999 have been restated to reflect the application of
accounting principles generally accepted in the United States of America for
operating companies.


PricewaterhouseCoopers
Florham Park, NJ

April 2, 2002



<PAGE>



Ridgewood Electric Power Trust III
Consolidated Balance Sheets

-------------------------------------------------------------------------------

                                                           December 31,
                                                   ----------------------------
                                                       2001             2000
                                                                      Restated
                                                   ------------    ------------
Assets:
Cash and cash equivalents ......................   $    387,672    $    426,127
Restricted cash ................................        297,430            --
Trade receivables, net of allowance
 of $512,105 in 2000 ...........................        762,394       2,018,543
Due from affiliates ............................        767,529         755,800
Other current assets ...........................         77,503         199,400
                                                   ------------    ------------

      Total current assets .....................      2,292,528       3,399,870

Investment in Ridgewood Providence
 Power Partners, L.P. ..........................      5,477,894       5,688,136

Plant and equipment ............................     11,676,568      11,643,321
Accumulated depreciation .......................     (3,813,515)     (3,175,051)
                                                   ------------    ------------
                                                      7,863,053       8,468,270
                                                   ------------    ------------

Electric power sales contracts .................      1,793,500       1,793,500
Accumulated amortization .......................       (502,180)       (430,440)
                                                   ------------    ------------
                                                      1,291,320       1,363,060
                                                   ------------    ------------

Other non-current assets .......................        556,000            --
                                                   ------------    ------------


      Total assets .............................   $ 17,480,795    $ 18,919,336
                                                   ------------    ------------

Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ..........   $  1,360,026    $    966,834
Due to affiliates ..............................        241,095         840,341
                                                   ------------    ------------
      Total current liabilities ................      1,601,121       1,807,175

Non-current liabilities ........................        250,000            --

Commitments and contingencies

Shareholders' Equity:
Shareholders' equity (391.8444 investor
 shares issued and outstanding) ................     15,804,411      17,272,073
Managing shareholder's accumulated deficit
 (1 management share issued and outstanding) ...       (174,737)       (159,912)
                                                   ------------    ------------
      Total shareholders' equity ...............     15,629,674      17,112,161
                                                   ------------    ------------

      Total liabilities and shareholders' equity   $ 17,480,795    $ 18,919,336
                                                   ------------    ------------




   See accompanying notes to the consolidated financial statements.


<PAGE>



Ridgewood Electric Power Trust III
Consolidated Statements of Operations

-------------------------------------------------------------------------------

                                                 Year Ended December 31,
                                      -----------------------------------------
                                         2001           2000            1999
                                                      Restated        Restated
                                      -----------    -----------    -----------

 Power generation revenue .........   $ 5,978,365    $ 9,272,661    $ 9,646,782
 Rental revenue ...................       404,702        317,452         88,732
                                      -----------    -----------    -----------

    Total revenue .................     6,383,067      9,590,113      9,735,514

Cost of sales, including
 depreciation and amortization
  of $710,204, $1,035,297 and
   $925,854 in 2001, 2000 and
    1999 ..........................     6,545,145      8,078,257      9,635,398
                                      -----------    -----------    -----------

Gross profit (loss) ...............      (162,078)     1,511,856        100,116

General and administrative expenses       835,410        801,464        139,946
Write down of investments in power
 generation projects ..............          --        2,780,085         17,560
Management fee paid to managing
 shareholder
                                          492,430        592,644        594,576
                                      -----------    -----------    -----------
     Total other operating expenses     1,327,840      4,174,193        752,082
                                      -----------    -----------    -----------

Loss from operations ..............    (1,489,918)    (2,662,337)      (651,966)
                                      -----------    -----------    -----------

Other income (expense):
   Interest income ................        32,337         26,657         61,873
   Interest expense ...............          --          (36,199)          --
   Equity income from Ridgewood
    Providence Power Partners, L.P.       168,919        222,528        171,984
    Income from arbitration award .          --             --        1,581,308
    Other expense .................      (193,825)       (71,779)       (71,440)
                                      -----------    -----------    -----------

     Other income (expense), net ..         7,431        141,207      1,743,725
                                      -----------    -----------    -----------

Net income (loss) .................   $(1,482,487)   $(2,521,130)   $ 1,091,759
                                      -----------    -----------    -----------














  See accompanying notes to the consolidated financial statements.


<PAGE>







Ridgewood Electric Power Trust III

Consolidated Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 2001, 2000 and 1999
-------------------------------------------------------------------------------





                                               Managing
                            Shareholders      Shareholder      Total


Shareholders' equity,
 December 31, 1998 .....   $ 22,803,902    $   (104,036)   $ 22,699,866

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

Net income for the year       1,080,841          10,918       1,091,759

Shareholders' equity,
 December 31, 1999 .....     21,531,296        (116,890)     21,414,406

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

Net loss for the year ..     (2,495,919)        (25,211)     (2,521,130)

Shareholders' equity,
 December 31, 2000 .....     17,272,073        (159,912)     17,112,161

Net loss for the year ..     (1,467,662)        (14,825)     (1,482,487)

Shareholders' equity,
 December 31, 2001 .....   $ 15,804,411    $   (174,737)   $ 15,629,674
                           ------------    ------------    ------------
















  See accompanying notes to the consolidated financial statements.


<PAGE>



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

                                              Year Ended December 31,
                                      -----------------------------------------
                                          2001          2000            1999
                                                       Restated       Restated
                                      -----------    -----------    -----------

Cash flows from operating
 activities:
     Net income (loss) ............   $(1,482,487)   $(2,521,130)   $ 1,091,759
                                      -----------    -----------    -----------

     Adjustments to reconcile net
      income (loss) to net cash
       flows from operating
         activities:
     Depreciation and
      amortization ................       710,204      1,035,297        925,854
     Provision for doubtful
      accounts ....................          --          512,105           --
     Writedown of investment in
      power generation project ....          --        2,780,085           --
     Equity in earnings from
      unconsolidated Ridgewood
       Providence Power Partners
        L.P .......................      (168,919)      (222,528)      (171,984)
     Changes in assets and
      liabilities:
        Restricted cash ...........      (297,430)          --             --
       Decrease (increase) in
        trade receivables .........     1,217,945     (1,502,692)        35,492

       Decrease in other current
        assets ....................       121,897         58,026        398,039
       (Increase) decrease in other
         non-current assets .......      (556,000)          --            1,500
       Increase (decrease) in
        accounts payable and
         accrued expenses .........       393,192        423,822       (129,983)
       (Decrease) increase in due
         to affiliates, net .......      (550,342)       929,290       (211,051)
       Increase in non-current
        liabilities ...............       250,000           --             --
                                      -----------    -----------    -----------
         Total adjustments ........     1,120,547      4,013,405        847,867
                                      -----------    -----------    -----------

       Net cash (used in) provided
        by operating activities ...      (361,940)     1,492,275      1,939,626
                                      -----------    -----------    -----------

Cash flows from investing
 activities:
     Cash distribution from
      Ridgewood Providence
       Power Partners L.P. ........       356,732        414,734        232,050
     Capital expenditures .........       (33,247)      (307,689)    (1,605,451)
                                      -----------    -----------    -----------
      Net cash provided by
      (used in)investing activities       323,485        107,045     (1,373,401)
                                      -----------    -----------    -----------

Cash flows from financing
  activities:
      Borrowings under line of
       credit facility ............          --          725,000           --
      Repayments under line of
       credit facility ............          --         (725,000)          --
     Cash distributions to
      shareholders ................          --       (1,781,115)    (2,377,219)
                                      -----------    -----------    -----------
       Net cash used in financing
        activities ................          --       (1,781,115)    (2,377,219)
                                      -----------    -----------    -----------

Net decrease in cash
 and cash equivalents .............       (38,455)      (181,795)    (1,810,994)
Cash and cash equivalents,
 beginning of year ................       426,127        607,922      2,418,916
                                      -----------    -----------    -----------

Cash and cash equivalents,
 end of year ......................   $   387,672    $   426,127    $   607,922
                                      -----------    -----------    -----------










  See accompanying notes to the consolidated financial statements.


<PAGE>


Ridgewood Electric Power Trust III
Notes to Consolidated 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.

Ridgewood Energy Holding Corporation, a Delaware corporation, is the Corporate
Trustee of the Trust. The Corporate Trustee acts on the instructions of the
Managing Shareholder and is not authorized to take independent discretionary
action on behalf of the Trust.

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

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

2.       Summary of Significant Accounting Policies

Accounting Changes
As a BDC under the 1940 Act, the Trust utilized generally accepted accounting
principles for investment companies. As a result of the elimination of the BDC
status, the Trust now utilizes generally accepted accounting principles for
operating companies. In accordance with the generally accepted accounting
principles for BDCs, investments in power generation projects were stated at
fair value in previously issued financial statements. As a result of the
elimination of the BDC status, consolidation and equity method accounting
principles now apply to the accounting for investments. Accordingly, the
financial data for all prior periods presented have been restated to reflect the
use of consolidation and equity method accounting principles.

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

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

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

New Accounting Standards and Disclosures
SFAS 141
In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") 141, Business Combinations, which
eliminates the pooling-of-interest method of accounting for business
combinations and requires the use of the purchase method. In addition, SFAS 141
requires the reassessment of intangible assets to determine if they are
appropriately classified either separately or within goodwill. SFAS 141 is
effective for business combinations initiated after June 30, 2001. The Trust
adopted SFAS 141 on July 1, 2001, with no material impact on the consolidated
financial statements.

SFAS 142
In June 2001, the FASB issued SFAS 142, Goodwill and Other Intangible Assets,
which eliminates the amortization of goodwill and other acquired intangible
assets with indefinite economic useful lives. SFAS 142 requires an annual
impairment test of goodwill and other intangible assets that are not subject to
amortization. Other intangible assets with definite economic lives will continue
to be amortized over their useful lives. The Trust will adopt SFAS 142 effective
January 1, 2002 and is currently assessing the impact that this standard may
have on the Trust.

SFAS 143
In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations, on the accounting for obligations associated with the retirement of
long-lived assets. SFAS 143 requires a liability to be recognized in the
consolidated financial statements for retirement obligations meeting specific
criteria. Measurement of the initial obligation is to approximate fair value,
with an equivalent amount recorded as an increase in the value of the
capitalized asset. The asset will be depreciated in accordance with normal
depreciation policy and the liability will be increased for the time value of
money, with a charge to the income statement, until the obligation is settled.
SFAS 143 is effective for fiscal years beginning after June 15, 2002. The Trust
will adopt SFAS 143 effective January 1, 2003 and is currently assessing the
impact that this standard may have on the Trust.

SFAS 144
In August 2001, the FASB issued SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, which replaces SFAS 121, Accounting for the
Impairment of Long-lived Assets and for Long-Lived Assets to Be Disposed Of. For
long-lived assets to be held and used, SFAS 144 retains the requirements of SFAS
121 to (a) recognize an impairment loss only if the carrying amount is not
recoverable from undiscounted cash flows and (b) measure an impairment loss as
the difference between the carrying amount and fair value of the asset. For
long-lived assets to be disposed of, SFAS 144 establishes a single accounting
model based on the framework established in SFAS 121. The accounting model for
long-lived assets to be disposed of by sale applies to all long-lived assets,
including discontinued operations and replaces the provisions of APB Opinion No.
30, Reporting the Results of Operations - Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions, for the disposal of segments of a business. SFAS 144
also broadens the reporting of discontinued operations. The Trust will adopt
SFAS 144 effective January 1, 2002 and is currently assessing the impact that
this standard may have on the Trust.

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

Impairment of Long-Lived Assets and Intangibles
In accordance with the provisions of SFAS No. 121, Accounting for the Impairment
of Long-Lived Assets to be Disposed Of, the Trust evaluates long-lived assets,
such as fixed assets and specifically identifiable intangibles, when events or
changes in circumstances indicate that the carrying value of such assets may not
be recoverable. The determination of whether an impairment has occurred is made
by comparing the carrying value of an asset to the estimated undiscounted cash
flows attributable to that asset. If an impairment has occurred, the impairment
loss recognized is the amount by which the carrying value exceeds the discounted
cash flows attributable to the asset or the estimated fair value of the asset.

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

Depreciation is recorded using the straight-line method over the useful lives of
the assets, which are 10 to 20 years with a weighted average of 18 and 14 years
at December 31, 2001 and 2000, respectively. During 2001, 2000 and 1999, the
Trust recorded depreciation expense of $638,464, $978,721, and $869,278,
respectively.

Electrical power sales contracts
A portion of the purchase price of the JRW Associates L.P. and Byron Power
Partners, L.P. were assigned to electric power sales contracts and are being
amortized over the lives of the contracts (25 years) on a straight-line basis.
The electric power sales contracts are reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount of the assets may
not be recoverable. During 2001, 2000, and 1999, the Trust recorded amortization
expense of $71,740.

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

Significant Customers
During 2001, 2000 and 1999, the Trust's largest customer, Pacific Gas and
Electric Company ("PG&E"), accounted for 53%, 68% and 43%, respectively of total
revenues. During 2001, 2000 and 1999, the Trust's second largest customer
accounted for 17%, 11% and 8%, respectively of total revenues. During 1999, the
Trust's third largest customer accounted for 24% of total revenues and did not
account for any revenues in 2000 or 2001.

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

Supplemental cash flow information
Total interest paid during the year ended December 31, 2000 was $36,199.

3. Projects

   JRW Associates, L.P. (known as the San Joaquin Power Project)
   On January 17, 1995, the Trust acquired 100% of the existing partnership
   interests of JRW Associates, L.P., which owns and operates an 8.5 megawatt
   electric cogeneration facility, located in Atwater, California. The aggregate
   purchase price was $4,898,987 including transaction costs.

   The acquisition of the San Joaquin Project was accounted for as a purchase
   and the results of operations of the San Joaquin Project have been included
   in the Trust's consolidated financial statements since the acquisition date.
   The purchase price was allocated to the net assets acquired, based on their
   respective fair values. Of the purchase price, $1,374,000 was allocated to
   the Electric Power Sales Contract and is being amortized over the life of the
   contract (25 years). See Note 10 - Pacific Gas and Electric Company Financial
   Crisis, for developments affecting the Byron and San Joaquin Projects.

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

   The acquisition of the Byron Project was accounted for as a purchase and the
   results of operations of the Byron Project have been included in the Trust's
   consolidated financial statements since the acquisition date. The purchase
   price was allocated to the net assets acquired, based on their respective
   fair values. Of the purchase price, $419,500 was allocated to the Electric
   Power Sales Contract and is being amortized over the life of the contract (25
   years). See Note 10 - Pacific Gas and Electric Company Financial Crisis, for
   developments affecting the Byron and San Joaquin Projects.

   Ridgewood Providence Power Partners, L.P. (known as the Providence Project)
   In 1996, Ridgewood Providence Power Partners, L.P. was formed as a Delaware
   limited partnership ("Providence Power") which acquired a 12.3 megawatt
   capacity electrical generating station, located at the Central Landfill in
   Johnston, Rhode Island (the "Providence Project"). In 1997, the capacity was
   increased to 13.8 megawatts. The Trust invested $7,132,860 in return for a
   35.7% limited partnership interest in Providence Power and its general
   partner.

   The Providence Project is fueled by methane gas produced and collected from
   the landfill. The electricity generated is sold to New England Power
   Corporation under a long-term contract.. The remaining 64.3% of Ridgewood
   Power is owned by Ridgewood Electric Power Trust IV ("Trust IV"), whose
   managing partner is Ridgewood Power LLC. In 2001, 2000 and 1999, the Trust
   recorded distributions of $356,732, $459,205 and $232,050, respectively, from
   the Providence Project, of which $44,471 was included in due from affiliates
   at December 31, 2000.

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

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

  Balance Sheet
                               For the Year Ended December 31,
                                   2001            2000
                                -----------     -----------
 Current assets .............   $ 1,458,891     $ 1,576,507
 Other non-current assets ....   18,327,504      19,621,905
                                -----------     -----------
 Total assets ...............   $19,786,395     $21,198,412
                                -----------     -----------

 Current liabilities ........   $ 2,619,729     $ 2,573,759
 Long-term debt .............     1,822,425       2,690,523
                                -----------     -----------
 Total liabilities and equity   $19,786,395     $21,198,412
                                -----------     -----------


  Statements of Operations

                      For the Year Ended December 31,
                 -------------------------------------
                    2001         2000         1999
                 ----------   ----------   ----------

Revenue ......   $7,472,308   $7,294,717   $7,120,802
Cost of sales     5,632,625    5,765,426    5,840,911
Other expenses    1,038,764      873,627    1,221,061
                 ----------   ----------   ----------

Net income ...     $410,336   $  623,328   $  481,749
                 ----------   ----------   ----------


   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.
   As per an agreement with Hawthorne Power Systems ("Hawthorne"), the Trust
   pays Hawthorne, a California company that maintains a large fleet of similar
   rental modules, a fee of 20% of gross rental revenues to arrange and
   administer the rental of the units. The revenue from these modules is
   included as rental revenue and Hawthorne's fee is included in cost of sales
   in the Consolidated Statement of Operations.

   Ridgewood AES Power Partners, LLC (known as  Ridgewood AES)
   In 1997, the Trust formed Ridgewood AES Power Partners, LLC and entered into
   an agreement with AES-NJ Cogen, Inc. (AES-NJ) to invest in five co-generation
   facilities operated by AES-NJ. The facilities are all located in New York. In
   January 1999, the Trust transferred five of its On-site Cogeneration Projects
   with a net book value of $283,966 to Ridgewood AES. The acquisition of the
   AES Project was accounted for as a purchase and the results of operations of
   the AES Project have been included in the Trust's consolidated financial
   statements since the acquisition date. During 2000, two of the facilities
   were shut down due to financial difficulties of the host companies. As a
   result, the Trust recorded an asset impairment loss of $307,794 in 2000
   related to the two projects. These write-offs have been presented as a
   separate line item under other operating expenses in the Consolidated
   Statements of Operations.

   Ridgewood El Segundo, LLC (known as the El Segundo Project)
   In April 1998, the Trust purchased an on-site cogeneration facility located
   near one of its existing on-site cogeneration facilities in Los Angeles,
   California. The total purchase price was approximately $590,733, including
   the payment of liabilities that encumbered the project. During 2000, the
   Trust analyzed the carrying value of the El Segundo Project assets using an
   estimated undiscounted cash flow analysis. Using this analysis, an impairment
   loss was recorded during 2000 in the amount of $524,054. This impairment has
   been presented as a separate line item under other operating expenses in the
   Consolidated Statement of Operations.

   On-site Cogeneration Projects
   In 1995, the Trust acquired a portfolio of 35 projects from affiliates of
   Eastern Utilities Associates ("EUA"), which sell electricity and thermal
   energy to industrial and commercial customers. The projects were held in
   eight limited partnerships of which the Trust is the sole limited partner and
   is the sole owner of each of the general partners. In the aggregate, the
   projects had 13.7 megawatts of base load and 5.7 megawatts of backup and
   standby capacity. The Trust paid a total of $11,300,000 for the projects and
   invested additional amounts for capital repairs and improvements and for
   working capital. All the projects were gas-fired cogeneration projects,
   located in California, Connecticut, Massachusetts, Rhode Island or New York.
   Their energy service agreements had terms expiring between September 1996 and
   2011. The acquisition of the projects was accounted for as a purchase and the
   results of operations of the projects have been included in the Trust's
   consolidated financial statements since the acquisition date. See Note 8 -
   Arbitration Proceeding with EUA.

   The Trust has shut down several of the projects and as a result recorded
   writedowns of $1,948,237 and $17,560 in 2000 and 1999, respectively, and
   $8,798,845 in the years prior to 1999. In January 1999, the Trust transferred
   five of the projects with a net book value of $283,966 to Ridgewood AES.
   Currently, excluding the five projects transferred to Ridgewood AES, six of
   the projects are still operated by the Trust with a total base load of 4.3
   megawatts.

   4.    Transactions With Managing Shareholder And Affiliates

   The Trust entered into a management agreement with the managing shareholder,
   under which the managing shareholder renders certain management,
   administrative and advisory services and provides office space and other
   facilities to the Trust. As compensation to the managing shareholder, the
   Trust pays the managing shareholder an annual management fee equal to 2.5% of
   the net asset value of the Trust payable monthly upon the closing of the
   Trust. For the years ended December 31, 2001, 2000 and 1999, the Trust paid
   management fees to the managing shareholder of $492,430, $592,644 and
   $594,576, 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, 2001.

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

   Effective from January 1, 1996, under an operating agreement with the Trust,
   Ridgewood Power Management LLC (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, 2001, 2000 and 1999,
   Ridgewood Management charged the following to the projects based on
   proportionate amounts invested:

                                                 For the Year Ended December 31,
                                                  ------------------------------
                                                    2001       2000       1999
                                                  --------   --------   --------
JRW Associates, L.P. ..........................   $152,098   $108,859   $150,621
Byron Power Partners, L.P. ....................     89,966     64,396     89,092
Ridgewood Providence Power Partners, L.P. .....    538,262    344,041    404,055
Ridgewood El Segundo LLC ......................     17,223     12,452     17,055
On-site Cogeneration Projects:
Ridgewood/Mass PPLP ...........................      6,658     57,590     91,296
Ridgewood/Elmsford PPLP .......................     40,771     25,660     40,374
Other On-site Cogeneration Project Partnerships     55,354     40,862     56,532

At December 31, 2001 and 2000, the Trust had outstanding payables and
receivables, with the following affiliates:

                                   As of December 31,
                              Due To                Due From
                        -------------------   -------------------
                           2001       2000       2001       2000
                        --------   --------   --------   --------

Ridgewood Management    $231,397   $678,357   $   --     $   --
Ridgewood Providence
 Power Partners, L.P.       --         --      384,715    366,489
Other affiliates ....      9,698    161,984    382,814    389,311

From time to time, the Trust records short-term payables and receivables from
other affiliates in the ordinary course of business. The amounts payable and
receivable with the other affiliates do not bear interest.

5. Line of Credit Facility, Letters of Credit and Restricted Cash

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. The credit facility
was extended until July 31, 2002. Outstanding borrowings bear interest at the
bank's prime rate or, at the Trust's choice, at LIBOR plus 2.5% (4.376% and
9.07% at December 31, 2001 and 2000, 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, 2001 and 2000, there were no borrowings
outstanding under the credit facility.

In August 2001, the Trust issued through its bank two standby letters of credit,
each in the amount of $370,000 to secure the gas purchases for the Byron and San
Joaquin projects. The Trust used its credit facility and a restricted
certificate of deposit in the amount of $297,430 to collateralize the letters of
credit which is presented as restricted cash on the Consolidated Balance Sheets.

6. Commitments

The Trust, through certain of its subsidiaries, has two long-term operating
ground leases. Both leases are for a term of thirty years.

 Future minimum lease payments as of December 31, 2001 are as follows:

                         Year Ended
                         December 31,            Repayment
                             2002                $172,932
                             2003                $172,932
                             2004                $172,932
                             2005                $172,932
                          Thereafter           $2,560,596

Rent expense for the years ended December 31, 2001, 2000 and 1999 was $172,332,
$171,600 and $168,756, respectively.

7.  Fair Value of Financial Instruments

At December 31, 2001 and 2000, the carrying value of the Trust's cash and cash
equivalents, trade receivables, accounts payable and accrued expenses and the
interest bearing amount due to the previous natural gas supplier approximates
their fair value. The fair value of the letter of credit does not differ
materially from its carrying value.

8.  Arbitration Proceeding with EUA

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 recorded income of $1,265,122 in 1998. 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 Consolidated Statement of Operations.

9.   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.

10. Pacific Gas and Electric Company Financial Crisis

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

In April 2001, the San Joaquin and Byron Projects entered into an agreement with
a financial institution whereby they sold, irrevocably and without recourse,
their undivided interest in all eligible trade accounts receivables for December
2000 and January 2001. Costs associated with the sale of receivables of $229,443
and $512,105 for 2001 and 2000, respectively, primarily related to the discount
and loss on sale, are included in general and administrative expenses in the
Consolidated Statements of Operations.

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

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

                         Ridgewood Providence Power Partners, L.P.

                                    Financial Statements

                              December 31, 2001, 2000 and 1999


<PAGE>
eport of Independent Accountants


To the Partners of
Ridgewood Providence Power Partners, L.P.:


In our opinion, the accompanying balance sheets and the related statements of
operations, changes in partners' equity and cash flows present fairly, in all
material respects, the financial position of Ridgewood Providence Power
Partners, L.P. (the "Partnership") at December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Partnership'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.




PricewaterhouseCoopers LLP
Florham Park, NJ
March 28, 2002

<PAGE>



Ridgewood Providence Power Partners, L.P.
Balance Sheets
--------------------------------------------------------------------------------

                                                            December 31,
                                                   -----------------------------
                                                        2001            2000
                                                   ------------    -------------
Assets:
Cash and cash equivalents ......................   $    815,598    $    942,399
Accounts receivable, trade .....................        593,169         584,517
Other current assets ...........................         50,124          49,591
                                                   ------------    ------------
     Total current assets ......................      1,458,891       1,576,507
                                                   ------------    ------------

Plant and equipment ............................     15,883,761      15,838,657
Accumulated depreciation .......................     (4,127,332)     (3,334,198)
                                                   ------------    ------------
      Plant and equipment, net .................     11,756,429      12,504,459
                                                   ------------    ------------

Electric power sales contract ..................      8,338,040       8,338,040
Accumulated amortization .......................     (3,169,688)     (2,613,819)
                                                   ------------    ------------
       Electric power sales contract, net ......      5,168,352       5,724,221
                                                   ------------    ------------

Spare parts ....................................        664,497         682,712
Debt reserve fund ..............................        738,226         710,513
                                                   ------------    ------------

     Total assets ..............................   $ 19,786,395    $ 21,198,412
                                                   ------------    ------------
Liabilities and Partners' Equity:

Liabilities:
Current maturities of long-term debt ...........   $    868,098    $    788,937
Accounts payable and accrued expenses ..........        335,493         343,585
Due to affiliates ..............................      1,416,138       1,441,237
                                                   ------------    ------------
     Total current liabilities .................      2,619,729       2,573,759

Long-term debt, less current portion ...........      1,822,425       2,690,523
                                                   ------------    ------------
Commitments and contingencies

Partners' equity:
General partner ................................        153,441         159,340
Limited partners ...............................     15,190,800      15,774,790
                                                   ------------    ------------
     Total partners' equity ....................     15,344,241      15,934,130
                                                   ------------    ------------

     Total liabilities and partners' equity ....   $ 19,786,395    $ 21,198,412
                                                   ------------    ------------


               See accompanying notes to the financial statements.

<PAGE>



Ridgewood Providence Power Partners, L.P.
Statements of Operations
--------------------------------------------------------------------------------

                                     For the Year Ended December 31,
                                -----------------------------------------
                                   2001           2000           1999
                                -----------    -----------    -----------

Power generation revenue ....   $ 6,925,308    $ 6,925,717    $ 6,751,802
Sublease income .............       547,000        369,000        369,000
                                -----------    -----------    -----------
     Total revenue ..........     7,472,308      7,294,717      7,120,802

Cost of sales, including
 depreciation and
 amortization of $1,349,003,
 $1,347,912 and $1,339,352 in
 2001, 2000 and 1999 ........     5,840,911      5,632,625      5,765,426
                                -----------    -----------    -----------

Gross profit ................     1,631,397      1,662,092      1,355,376

General and administrative
 expenses ...................       797,283        540,576        565,902
                                -----------    -----------    -----------

Income from operations ......       834,114      1,121,516        789,474
                                -----------    -----------    -----------

Other income (expense):
     Interest income ........        48,701         77,099         57,673
     Interest expense .......      (472,479)      (575,287)      (437,238)
     Other income ...........          --             --           71,840
                                -----------    -----------    -----------
    Other income(expense),net      (423,778)      (498,188)      (307,725)
                                -----------    -----------    -----------

Net income ..................   $   410,336    $   623,328    $   481,749
                                -----------    -----------    -----------










               See accompanying notes to the financial statements.

<PAGE>

Ridgewood Providence Power Partners, L.P.
Statements of Changes In Partners' Equity
For the Years Ended December 31, 2001, 2000 and 1999
--------------------------------------------------------------------------------

                            Limited         General
                            Partners        Partner         Total
                          ------------     -----------     ----------
Partners' equity,
 January 1, 1999 ......   $ 17,201,302    $    173,750    $ 17,375,052

Distributions .........     (1,248,080)        (12,607)     (1,260,687)

Net income for the year        476,932           4,817         481,749
                          ------------    ------------    ------------

Partners' equity,
 December 31, 1999 ....     16,430,154         165,960      16,596,114

Distributions .........     (1,272,459)        (12,853)     (1,285,312)

Net income for the year        617,095           6,233         623,328
                          ------------    ------------    ------------

Partners' equity,
 December 31, 2000 ....     15,774,790         159,340      15,934,130

Distributions .........       (990,223)        (10,002)     (1,000,225)

Net income for the year        406,233           4,103         410,336
                          ------------    ------------    ------------

Partners' equity,
 December 31, 2001 ....   $ 15,190,800    $    153,441    $ 15,344,241
                          ------------    ------------    ------------




               See accompanying notes to the financial statements.

<PAGE>



Ridgewood Providence Power Partners, L.P.
Statements of Cash Flows
--------------------------------------------------------------------------------

                                   For the Year Ended December 31,
                                 ----------------------------------------
                                   2001            2000          1999
                                 -----------    -----------    -----------
Cash flows from operating
 activities:
Net income ...................   $   410,336    $   623,328    $   481,749
                                 -----------    -----------    -----------
Adjustments to reconcile net
 income to cash flows from
 operating activities:
 Depreciation and amortization     1,349,003      1,347,912      1,339,352
 Changes in assets and
  liabilities:
 Increase in accounts
  receivable, trade ..........        (8,652)        (1,724)       (12,273)
 Decrease (increase) in
  spare parts ................        18,215        149,158        (91,964)
 (Increase) decrease in other
  current assets .............          (533)         1,571         (2,033)
 Decrease in accounts
  payable and accrued expenses        (8,092)      (117,212)       (47,101)
 (Decrease) increase in
  due to affiliates ..........       (25,099)       260,306       (112,115)
                                 -----------    -----------    -----------

Total adjustments ............     1,324,842      1,640,011      1,073,866
                                 -----------    -----------    -----------

Net cash provided by operating
 activities ..................     1,735,178      2,263,339      1,555,615
                                 -----------    -----------    -----------

Cash flows from investing
 activities:
Capital expenditures .........       (45,104)        (1,838)      (375,458)
                                 -----------    -----------    -----------

Net cash used in
 investing activities ........       (45,104)        (1,838)      (375,458)
                                 -----------    -----------    -----------

Cash flows from financing
 activities:
Cash distributions to partners    (1,000,225)    (1,161,719)      (650,000)
Payments of long-term debt ...      (788,937)      (716,995)      (651,613)
Increase in debt reserve fund        (27,713)       (44,167)       (29,238)
                                 -----------    -----------    -----------

Net cash used in financing
 activities ..................    (1,816,875)    (1,922,881)    (1,330,851)
                                 -----------    -----------    -----------

Net (decrease) increase
 in cash and cash equivalents       (126,801)       338,620       (150,694)

Cash and cash equivalents,
 beginning of year ...........       942,399        603,779        754,473
                                 -----------    -----------    -----------

Cash and cash equivalents,
 end of year .................   $   815,598    $   942,399    $   603,779
                                 -----------    -----------    -----------








               See accompanying notes to the financial statements.

<PAGE>

Ridgewood Providence Power Partners, L.P.
Notes to Financial Statements
--------------------------------------------------------------------------------

1.       Organization and Business Activity

In February 1996, Ridgewood Providence Power Partners, L.P. was formed as a
Delaware limited partnership (the "Partnership"). Ridgewood Providence Power
Corporation, a Delaware corporation, is the sole general partner of the
Partnership and is owned by Ridgewood Electric Power Trust III ("Trust III") and
Ridgewood Electric Power Trust IV ("Trust IV"), both Delaware business trusts,
(collectively, the "Trusts"). The Trusts are the limited partners in the
Partnership.

In April 1996, the Partnership purchased substantially all of the net assets of
Northeastern Landfill Power Joint Venture. The assets acquired include a 13.8
megawatt capacity electrical generating station, located at the Central Landfill
in Johnston, Rhode Island (the "Providence Project"). The Providence Project
includes nine reciprocating electric generator engines, which are fueled by
methane gas produced by and collected from the landfill. The electricity
generated is sold to New England Power Service Company under a long-term
contract.

The profits and losses of the Partnership are allocated 1% to the general
partner and 99% to the limited partners in accordance with their capital
contribution (63.7% to Trust IV and 35.3% to Trust III).

2.       Summary of Significant Accounting Policies

Critical accounting policies and estimates
The preparation of financial statements requires the Partnership to make
estimates and judgements that affect the reported amounts of assets,
liabilities, sales and expenses, and related disclosure of contingent assets and
liabilities. On an on-going basis, the Partnership evaluates its estimates,
including bad debts, intangible assets and recordable liabilities for litigation
and other contingencies. The Partnership bases its estimates on historical
experience, current and expected conditions and various other assumptions that
are believed to be reasonable under the circumstances, the results of which form
the basis for making judgements about the carrying values of assets and
liabilities that are not readily apparent from other sources. Actual results may
differ from these estimates under different assumptions or conditions.

New Accounting Standards and Disclosures
SFAS 141
In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") 141, Business Combinations, which
eliminates the pooling-of-interest method of accounting for business
combinations and requires the use of the purchase method. In addition, SFAS 141
requires the reassessment of intangible assets to determine if they are
appropriately classified either separately or within goodwill. SFAS 141 is
effective for business combinations initiated after June 30, 2001. The
Partnership adopted SFAS 141 on July 1, 2001, with no material impact on the
financial statements.

SFAS 142
In June 2001, the FASB issued SFAS 142, Goodwill and Other Intangible Assets,
which eliminates the amortization of goodwill and other acquired intangible
assets with indefinite economic useful lives. SFAS 142 requires an annual
impairment test of goodwill and other intangible assets that are not subject to
amortization. The Partnership will adopt SFAS 142 effective January 1, 2002 and
is assessing the impact.

SFAS 143
In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations, on the accounting for obligations associated with the retirement of
long-lived assets. SFAS 143 requires a liability to be recognized in the
financial statements for retirement obligations meeting specific criteria.
Measurement of the initial obligation is to approximate fair value, with an
equivalent amount recorded as an increase in the value of the capitalized asset.
The asset will be depreciated in accordance with normal depreciation policy and
the liability will be increased for the time value of money, with a charge to
the income statement, until the obligation is settled. SFAS 143 is effective for
fiscal years beginning after June 15, 2002. The Partnership will adopt SFAS 143
effective January 1, 2003 and is assessing the impact.

SFAS 144
In August 2001, the FASB issued SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, which replaces SFAS 121, Accounting for the
Impairment of Long-lived Assets and for Long-Lived Assets to Be Disposed Of. For
long-lived assets to be held and used, SFAS 144 retains the requirements of SFAS
121 to (a) recognize an impairment loss only if the carrying amount is not
recoverable from undiscounted cash flows and (b) measure an impairment loss as
the difference between the carrying amount and fair value of the asset. For
long-lived assets to be disposed of, SFAS 144 establishes a single accounting
model based on the framework established in SFAS 121. The accounting model for
long-lived assets to be disposed of by sale applies to all long-lived assets,
including discontinued operations and replaces the provisions of APB Opinion No.
30, Reporting the Results of Operations - Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions, for the disposal of segments of a business. SFAS 144
also broadens the reporting of discontinued operations. The Partnership will
adopt SFAS 144 effective January 1, 2002 and is assessing the impact.

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

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

Impairment of Long-Lived Assets and Intangibles
In accordance with the provisions of SFAS No. 121, the Partnership evaluates
long-lived assets, such as fixed assets and specifically identifiable
intangibles, when events or changes in circumstances indicate that the carrying
value of such assets may not be recoverable. The determination of whether an
impairment has occurred is made by comparing the carrying value of an asset to
the estimated undiscounted cash flows attributable to that asset. If an
impairment has occurred, the impairment loss recognized is the amount by which
the carrying value exceeds the discounted cash flows attributable to the asset
or the estimated fair value of the asset.

Plant and equipment
Machinery and equipment, consisting principally of electrical generating
equipment, is stated at cost. Renewals and betterments that increase the useful
lives of the assets are capitalized. Repair and maintenance expenditures are
expensed as incurred.

Depreciation is recorded using the straight-line method over the estimated
useful life of the assets, which is 20 years. During the years ended December
31, 2001, 2000 and 1999, the Partnership recorded depreciation expense of
$793,134, $792,043 and $783,483, respectively.

Electric Power Sales Contract
A portion of the purchase price of the Providence Project was assigned to the
Electric Power Sales Contract and is being amortized over 15 years on a
straight-line basis. The electric power sales contract is reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of the asset may not be recoverable. During each of the years
ended December 31, 2001, 2000 and 1999, the Partnership recorded amortization
expense of $555,869.

Supplemental cash flow information
Total interest paid during the years ended December 31, 2001, 2000 and 1999, was
$299,919, $371,861 and $437,243, respectively.

Income taxes
No provision is made for income taxes in the accompanying financial statements
as the income or loss of the Partnership is passed through and included in the
tax returns of the partners.

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


3.       Long-Term Debt

Following is a summary of long-term debt at December 31, 2001 and 2000:

                                        2001            2000
                                     -----------    -----------
Senior collateralized non recourse
 notes payable ...................   $ 2,690,523    $ 3,479,460
Less current maturity ............      (868,098)      (788,937)
                                     -----------    -----------
Total long term debt .............   $ 1,822,425    $ 2,690,523
                                     -----------    -----------

The senior collateralized non-recourse notes are due in monthly installments of
$90,738, including interest at 9.6%. Final payment is due on October 15, 2004.
The notes also provide for additional interest equal to 5% of the annual net
cash flow of the Partnership, as defined. No additional interest was due for the
years ended December 31, 2001, 2000 and 1999. The notes are collateralized by a
leasehold mortgage on the Partnership's landfill lease agreements and
substantially all of the assets of the Partnership. In addition to the required
monthly payments, mandatory prepayments are required if certain events occur.
The loan agreement also provides for a cash funded debt service reserve. At
December 31, 2001 and 2000, the cash balance in the debt service reserve account
was $738,226 and $710,513, respectively. Additions and reductions to the reserve
account are defined in the loan agreement. The loan agreement contains various
covenants, including the maintenance of a specified debt service ratio.

Remaining scheduled principal repayments of long-term debts were as follows:

                                      Year Ended
                                      December 31,            Repayment

                                      2002                   $  868,098
                                      2003                      955,202
                                      2004                      867,223
                                      2005                            -
                                      2006                            -

4.       Fair Value of Financial Instruments

At December 31, 2001 and 2000, the carrying values of the Partnership's cash and
cash equivalents, accounts receivable, debt reserve and accounts payable and
accrued expenses approximate their fair values. The fair value of the long-term
debt, calculated using current rates for loans with similar maturities, does not
differ materially from its carrying value.

5.       Electric Power Sales Contract

The Partnership is committed to sell all of the electricity it produces to New
England Power Service Company ("NEP") for prices as specified in the Power
Purchase Agreement. The prices are adjusted annually for changes in the Consumer
Price Index, as defined. The NEP agreement expires in the year 2020 and can be
terminated by either party under certain conditions in 2010.

6.       Landfill Lease and Sublease

The Partnership leases the Central Landfill, located in Johnston, Rhode Island
from Rhode Island Solid Waste Management Corporation ("RISWMC"). The lease
expires in 2020 and can be extended for an additional 10 years. This operating
lease requires the Partnership to pay a royalty equal to 15% of net revenues, as
defined, until the year 2010. For subsequent years, the royalty is 15% of net
revenues for each month in which the average daily kilowatt hour production is
less than 180,000 and 18% of net revenues for each month in which the average
daily kilowatt hour production exceeds 180,000. For the years ended December 31,
2001, 2000 and 1999, royalty expense relating to the RISWMC lease amounted to
$1,025,448, $1,015,398 and $996,399, respectively. The royalty expense has been
included in the cost of sales in the Statements of Operations.

The Partnership subleases the Central Landfill to the Central Gas Limited
Partnership ("Gasco"). Gasco operates and maintains the landfill gas collection
system and supplies landfill gas to the Providence Project. The sublease
agreement is effective through December 31, 2010 and provides for the following:

Sublease income - Gasco is to pay the Partnership an annual amount equal to the
product of $30,000 times the assumed output capacity of each original engine
generator set in megawatts installed and operating by the joint venture. Income
recorded under the sublease amounted to $547,000 for the year ended December 31,
2001 and $369,000 for each of the years ended December 31, 2000 and 1999.

Fuel expense - The Partnership agreed to purchase all the landfill gas produced
by Gasco and pay on a monthly basis $.01183 per kilowatt hour for the first
4,000,000 kilowatt hours, $.005 per kilowatt hour for kilowatt hours in excess
of 4,000,000 and $.05 per million BTU's of excess landfill gas. The price is
adjusted annually for changes in the Consumer Price Index, as defined. Purchases
from Gasco for the years ended December 31, 2001, 2000 and 1999 amounted to
$937,731, $926,795 and $907,950, respectively.

7.       Transactions with Affiliates

Under an Operating Agreement with the Trusts, Ridgewood Power Management LLC
(formerly Ridgewood Power Management Corporation, "Ridgewood Management"), an
entity related to the managing shareholder of the Trusts through common
ownership, provides management, purchasing, engineering, planning and
administrative services to the Partnership. Ridgewood Management charges the
partnership 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 years ended December 31, 2001, 2000
and 1999, Ridgewood Management charged the Partnership $538,262, $344,041 and
$404,055, respectively, for overhead items allocated in proportion to the amount
invested in projects managed. Ridgewood Management also charged the Partnership
for all of the remaining direct operating and non-operating expenses incurred
during the periods.

At December 31, 2001 and 2000,  the Company had  outstanding  payables  totaling
$1,416,138 and $1,441,237, respectively, to the following affiliates:

                       As of December 31,
                       -------------------
                         2001       2000
                       --------   --------
Trust III ..........   $384,715   $366,489
Trust IV ...........    807,330    955,531
Ridgewood Management    140,112     44,306
Other affiliates ...     83,981     74,911

Included in the December 31, 2000 outstanding payables are distributions due of
$44,471 and $79,122 to Trust III and Trust IV, respectively. The payable is
treated as due to affiliates on the balance sheets. Effective January 1, 2000,
the Trusts began charging interest on the payable at 9.6% per annum, which
resulted in interest expense of $179,503 and $211,431 for the years ended
December 31, 2001 and 2000, respectively.

8.       Administrative Proceeding

In September 1998, the Region I office of the U.S. Environmental Protection
Agency ("EPA") filed an administrative proceeding against the Partnership
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, the Partnership settled the administrative proceeding for
approximately $86,000.