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, 2002

                         Commission file number 0-23432

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

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

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

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

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

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

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

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

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

     There is no market for the Shares. The aggregate capital contributions made
for the Registrant's  voting Shares held by  non-affiliates of the Registrant at
March 30,  2003 was  $39,034,440  000 and the  number  of  owners of  beneficial
interest outstanding at March 31, 2002 was 788.

Exhibit Index is located on page 30.


<PAGE>



PART I

Item 1.  Business.

Forward-looking statement advisory

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

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

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

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

(a) General Development of Business.

         The Trust was organized as a Delaware business trust on December 6,
1993 to participate in the development, construction and operation of
independent power generating facilities or related projects or facilities
("Independent Power Projects" or "Projects"). 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") necessary as a
result of such withdrawal, including, but not limited to, deleting the section
of the Declaration requiring Independent Trustees. Consents were tabulated at
the close of business on December 18, 2001. Based on such tabulation, a majority
of Investor Shares consented to such withdrawal and amendments. On January 10,
2002, the Trust filed with the Securities and Exchange Commission a notification
to withdraw its election to be treated as a "business development company." As a
result of such withdrawal, the Trust now utilizes generally accepted accounting
principles for operating companies.

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

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

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

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

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

o        Ridgewood Renewable PowerBank, LLC
o        Ridgewood Renewable PowerBank II, LLC

(b) Financial Information about Industry Segments.

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

(c) Narrative Description of Business.

(1) General Description.

     The Trust has invested its funds in seven Projects or groups of Projects:

         (i) a 5.7 megawatt cogeneration facility located in Byron, California
         (the "Byron Project"); (ii) an 8.5 megawatt cogeneration facility
         located in Atwater, California (the "San Joaquin Project"); (iii) a
         portfolio of 4 small cogeneration facilities located in California, New
         York and Massachusetts purchased from Eastern Utilities Associates,
         Inc. (the "On-site Cogeneration Projects"); (iv) an additional
         cogeneration project located at an airline food preparation facility in
         Los Angeles, California (the "El Segundo Project"); (v) Ridgewood/AES
         Power Partners, L.P., a joint venture that operates 5 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 a long term contract
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. 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.

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

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

 (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 $10.8 million relating to On-site Cogeneration Projects
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. As part of the
bankruptcy proceeding, Globe sold substantially all of its assets, including the
Fall River facility. The Bankruptcy Court approved the sale. The Power Contract
that the Trust has with Globe has been rejected by Globe in the Bankruptcy Court
proceedings. Effectively the Power Contract has been terminated and the Trust
has "rejection" damages claims against Globe, but given Globe's financial
condition it is not likely that significant amounts of money will be available
to pay such rejection damages. Recently, the Trust entered into an Asset Sale
Agreement and sold the Globe Project equipment for $250,000. The purchaser is
responsible for, and has assumed all of the risk of, the equipment removal and
transportation. The Trust has received full payment for the Globe Equipment.

         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 five of the
smallest On-Site Cogeneration Projects. In September 1997 the Trust and AES
created a joint venture, Ridgewood/AES Power Partners, L.P. ("Ridgewood AES") to
develop additional small cogeneration projects in the New York metropolitan
area. The Trust supplies capital and AES supplies development services. At
December 31, 2002 Ridgewood AES owned five cogeneration projects at hotels and
hospitals in New York and New Jersey.

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

(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. In April 2002, the Project began operations and operated
continually throughout the year.

(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.

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

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

         Throughout the Trusts' ownership of the Providence Project, certain
situations have occurred at the landfill regarding Gasco's operation and
maintenance of the gas collection system, which 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
has concluded negotiations 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, owned by the Trust's
affiliate, Ridgewood Power B Fund/Providence Expansion, will obtain rights to
landfill gas from RIRRC and develop and additional 7.5 MW landfill gas-fired
electric generation facility.

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

         Now that the Providence Project has been qualified, it may sell to
retail electric suppliers the RPS Attributes associated with its electrical
energy. Retail electric suppliers need to purchase RPS Attributes associated
with renewable energy and not necessarily the energy itself. Thus, electrical
energy and RPS Attributes are separable products and need not be sold or
purchased as a bundled product. Retail electric suppliers in Massachusetts will
then use the purchase of such RPS Attributes to demonstrate compliance with the
Restructuring Act and RPS Regulations. The Trust, along with Power IV and the B
Fund, are currently negotiating a transaction with a power marketer that does
business in Massachusetts for the sale of the RPS Attributes generated by the
Providence Project, as well the RPS Attributes generated by Projects owned by
Power V and the B Fund, in the calendar year 2003. In addition, the transaction
provides such power marketer with six separate annual options to purchase such
output in each year from 2004 through 2009. If not purchased by such power
marketers, the Providence Project is free to sell to other parties. Under the
terms of the transaction, the prices to be received by the Providence Project
are very favorable.

(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. Due to the increase in
competition and production of newer efficient mobile models, the Trust
experienced a decrease in rental revenue for the current year. As a result of
the change in these market conditions, the forecasted revenues for the units are
not expected to be enough to recover the units book value. In 2002, the Trust
recorded a writedown of $461,000 to reflect the units' fair market value.

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

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

         Electricity produced by a Project is typically delivered to the
purchaser through transmission lines 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
                                   2002           2001          2000
Pacific Gas & Electric Co.
 (San Joaquin & Byron Projects)    76.5%           53.1%        68.3%
Coca Cola Bottling Plant of New
  York (Coca Cola Project)         12.5%           17.4%        11.4%

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

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

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

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

         As a result of the energy crises experience by California during the
years 2000 and 2001, both the state legislature and the CPUC have taken
significant action by enacting legislation and implementing regulations,
respectively, intended primarily to avoid a repeat of the energy crises by
creating a more stable, efficient and economic energy market. While it will take
a while before it can be determined whether the results hoped for by the state
legislature and CPUC occur, the impact on the energy market from such actions
will be rather significant. For example, the legislature enacted legislation
designed to enhance, promote and encourage renewable generation in the state by
implementing a renewable portfolio standard ("RPS"), which will require all
California investor owned utilities ("IOUs"), as well as retail electric
suppliers to have in their energy supply portfolio a certain percentage of
renewable generation. This percentage increases overtime until the requirement
equals 20%. In addition to the RPS, California enacted legislation that will
streamline the time required for and the costs of new electric power plant
permitting and construction. Finally, legislation has been enacted that will
fundamentally change the manner in which California IOUs procure electric energy
for their customers.

         The deregulation legislation enacted by California in 1994 required,
among other things, that the California IOUs satisfy their energy needs by
procuring the electric energy from the wholesale power market. The energy prices
obtained from such market fluctuated and the IOUs could either make money, if
they purchased at prices less than the prices at which they sold, or lose money
if the wholesale prices was significantly higher than the retail price. The
California energy crises occurred in some measure because the wholesale price
actually became significantly higher than the retail rate, causing severe losses
to the IOUs and, in the case of PG&E, bankruptcy.

         The process through which California IOUs will now procure electricity
for their customers, although subject to CPUC implementation and regulation,
will be akin to the methods used prior to deregulations. The IOUs will be
required to submit to the CPUC a procurement plan that details how the IOU
intends to procure energy from a diversified portfolio of generating resources,
including renewable generators, and using contracts terms of varying lengths,
including short-term and long-term contracts. The IOUs procurement plans are
subject to CPUC approval. The CPUC, among other things, is required to develop a
process for evaluating the IOUs procurement plans as well as criteria for
evaluating individual energy contracts. The CPUC is currently engaged in the
rule-making process that will implement these and many other requirements of the
legislation.

         As this legislation described above indicates, the trend in the
industry, appears to a reversion to a more regulated electric industry, with
reporting requirements and regulatory oversight and review. In any event, these
market changes do not significantly impact upon the Byron and San Joaquin
Projects, which currently have a Power Contract with PG&E, although market
changes which strengthen PG&E benefit the Byron and San Joaquin Projects over
the long term by ensuring PG&E's ability to pay under such Power Contract.

         The remaining On-site Cogeneration Projects and the 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.

(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. There is significant competition among non-utility
producers, subsidiaries of utilities and utilities themselves in developing and
operating energy-producing projects and in marketing the power produced by such
projects. The Trust is unable to accurately estimate the number of competitors
but believes that there are many competitors at all levels and in all sectors of
the industry. Many of those competitors, especially affiliates of utilities and
equipment manufacturers, may be far better capitalized than the Trust.

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

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

(iv) Potential Legislation and Regulation.

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

(6) Regulatory Matters.

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

(i) Energy Regulation.

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

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

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

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

         (C) The Federal Power Act. The FPA grants FERC exclusive rate-making
jurisdiction over wholesale sales of electricity in interstate commerce. The FPA
provides FERC with ongoing as well as initial jurisdiction, enabling FERC to
revoke or modify previously approved rates. Such rates may be based on a
cost-of- service approach or determined through competitive bidding or
negotiation. While 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 Providence Project operates filtration and condensation equipment
for the purpose of removing contaminants from the landfill gas supply. The
condensate is further treated and then discharged to a local treatment plant
under an NPDES permit. The contaminants removed from the condensate are
incinerated at an approved facility. The Trust believes that these discharges
and contaminants are being disposed of in compliance with NPDES and other
requirements.

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

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

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

         The Trust has 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                                                   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.

         None.

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

         None.

PART II

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

(a) Market Information.

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

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

            The Managing Shareholder has investigated the possibility and
feasibility of a combination of the Other Power Trusts and the Ridgewood LLCs
into a publicly traded entity. This would require the approval of the Investors
in the Trust, the Other Power Trusts, and the Ridgewood LLCs 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, Other Power Trusts or Ridgewood LLCs. After
conducting investigations during 2001 and 2002, 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,
2002 and 2001:

                             Year ended            Year ended
                         December 31, 2002      December 31, 2001
Total distributions
 to Investors               $--                     $ --
Distributions per
 Investor Share             $--                     $ --
Distributions to
 Managing Shareholder       $--                     $ --

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

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

Item 6.  Selected Financial Data.

     The following data is qualified in its entirety by the financial statements
presented elsewhere in this Annual Report on Form 10-K. The selected financial
data for 1998 was derived from unaudited data.

Selected Financial Data
                        As of and for the year ended December 31,
                    2002      2001       2000        1999        1998

Total Fund Information:

Revenues         $7,848,594 $6,383,067 $9,590,113  $9,735,514 $11,364,992
Net income (loss)(1,356,396)(1,482,487)(2,521,130)  1,091,759  (2,049,175)
                      (A)                    (B)        (C)        (D)
Net assets
(shareholders'
  equity)        14,273,278 15,629,674 17,112,161  21,414,406  22,699,866
Investments in
 Plant and
 Equipment (net
 of depreciation) 6,632,404  7,863,053  8,468,270  11,904,223  11,152,886
Investment
 in Power
 Contract(net
 of amortization) 1,219,580  1,291,320  1,363,060   1,434,800   1,506,540
Total assets     15,589,236 17,480,795 18,919,336  21,255,421  24,405,244
Long-term
obligations              --    250,000         --         --           --
Per Share:
Revenues             20,030     16,290     24,474      24,845      29,004
Net income(loss)     (3,462)    (3,783)    (6,434)      2,786      (5,230)
                        (A)                   (B)         (C)        (D)
Net asset value      36,426     39,887     43,671      54,650      57,931
Distributions
 to Investors            --         --      4,500       6,006       6,003


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


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, 2002 compared to the year ended December 31, 2001.
Power generation revenue increased $1,761,000, or 29%, to $7,739,000 in 2002
compared to $5,978,000 in 2001. The increase is primarily due to the Byron and
San Joaquin projects operating on their normal schedule in 2002 as compared to
2001 when the plants were idle from February to August due to PG&E's failure to
pay the projects for power delivered since December 1, 2000. Rental revenue from
the Trust's mobile power modules decreased by $295,000 or 73%, to $109,000 in
2002. The decrease in rental revenue is due the higher rental volume experienced
in 2001, as a result of the California energy crisis.

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

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

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

In 2002, the Trust recorded a write down to its investments in power generation
projects of $580,000. The projects comprising the write down are the Mobile
Power Units, $461,000, Ridgewood AES, $67,000, and the On-site Cogeneration
Projects, $52,000. The Trust did not record any writedowns of projects in 2001.

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

The loss from operations in 2002 remained comparable to 2001.

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

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

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 $229,000, or 79%, to $606,000 in
2001 from $289,000 in 2000. The increase reflects higher legal expenses related
to the dispute with PG&E.

Provision for bad debt expense decreased $283,000 to $229,000 in 2001 from
$512,000 in 2000. The bad debt expense for both periods reflects the loss
recognized on the sale of the Monterey Project's PG&E receivables to AMROC.

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.

Liquidity and Capital Resources

In 2002, the Trust's operating activities used $18,000 of cash compared to
$362,000 in 2001.

Cash generated from investing activities in 2002 and 2001 was $10,000 and
$323,000. The decrease is reflective of the distributions received from the
Providence Project in 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 facility was extended
until July 31, 2002. During the third quarter of 2002, the Trust extended its
revolving line of credit agreement with its bank through August 31, 2002 and
subsequently finalized a further extension until July 31, 2003. The extension
provides the Trust with a committed line of credit of $757,000. Outstanding
borrowings bear interest at LIBOR plus 2.5% (3.882% and 4.376% at December 31,
2002 and 2001, respectively). The credit agreement requires the Trust to provide
100% cash collateral for any borrowings after December 31, 2002. There were no
outstanding borrowings at December 31, 2002 and 2001.

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
at December 31, 2001. In 2002, the Trust decreased the amount of the certificate
of deposit to $100,000. The letters of credit expired in August 2002.

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

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

2003       $955,202
2004        867,223

The Byron and San Joaquin Projects have certain long-term obligations relating
to their Power Contracts with PG&E and their Gas Agreements with Coral (See Note
6 of the Consolidated Financial Statements). The Providence Project has certain
long-term obligations relating to its Power Contract with NEP, its property
lease and its arrangements with its gas supplier. The On-site Cogeneration
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 2003 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, 2002
                       Expected Maturity Date
                              2003
                            (U.S. $)

Bank Deposits and Certificates of Deposit     $ 380,000
Average interest rate                              1.04%

Item 8.  Financial Statements and Supplementary Data.

A. Index to Consolidated Financial Statements

Report of Independent Accountants                      F-2
Consolidated Balance Sheet at December 31,
  2002 and 2001                                        F-3
Consolidated Statement of Operations for the
  three years ended December 31, 2002                  F-4
Consolidated Statement of Changes in
 Shareholders' Equity for the three years
  ended December 31, 2002                              F-5
Consolidated Statement of Cash Flows for the three
  years ended December 31, 2002                        F-6
Notes to Consolidated Financial Statements             F-7 to F-18

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

B. Supplementary Financial Information

Selected Quarterly Financial Data for the years ended December 31, 2002 and 2001
  (Unaudited)

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



                                             2001
--------------------------------------------------------------------------------
                           First         Second          Third          Fourth
                          Quarter        Quarter        Quarter        Quarter
---------------------- ------------   ------------   ------------   ------------
Revenue ............   $ 1,479,000    $   877,000    $ 1,805,000    $ 2,222,000
Loss from operations      (587,000)      (429,000)      (296,000)      (178,000)
Net loss ...........      (464,000)      (379,000)      (361,000)      (278,000)

 Report of Independent Accountants


To the Shareholders of
Ridgewood Electric Power Trust III:

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in shareholders' equity and cash
flows present fairly, in all material respects, the financial position of
Ridgewood Electric Power Trust III and its subsidiaries (the "Trust") at
December 31, 2002 and 2001, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2002, in
conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Trust's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.



PricewaterhouseCoopers LLP
Florham Park, NJ
April 3, 2003



<PAGE>



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

                                                          December 31,
                                               -----------------------------
                                                    2002             2001
                                               ------------    -------------
Assets:
Cash and cash equivalents ..................   $    379,894    $    387,672
Restricted cash ............................        100,000         297,430
Trade receivables ..........................        554,722         762,394
Due from affiliates ........................        277,083         767,529
Other current assets .......................        138,369          77,503
                                               ------------    ------------

       Total current assets ................      1,450,068       2,292,528

Investment in Ridgewood Providence
 Power Partners, L.P. ......................      5,717,184       5,477,894

Plant and equipment ........................     11,086,565      11,676,568
Accumulated depreciation ...................     (4,454,161)     (3,813,515)
                                               ------------    ------------
                                                  6,632,404       7,863,053
                                               ------------    ------------

Electric power sales contracts .............      1,793,500       1,793,500
Accumulated amortization ...................       (573,920)       (502,180)
                                               ------------    ------------
                                                  1,219,580       1,291,320
                                               ------------    ------------

Other assets ...............................        570,000         556,000
                                               ------------    ------------

        Total assets .......................   $ 15,589,236    $ 17,480,795
                                               ------------    ------------

Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ......   $    691,714    $    905,526
Accrued fuel expense .......................        299,627         454,500
Due to affiliates ..........................        324,617         241,095
                                               ------------    ------------
         Total current liabilities .........      1,315,958       1,601,121

Other liabilities ..........................           --           250,000

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

Shareholders' Equity:
Shareholders' equity (391.8444 investor
 shares issued and outstanding) ............     14,461,579      15,804,411
Managing shareholder's accumulated deficit
 (1 management share issued and outstanding)       (188,301)       (174,737)
                                               ------------    ------------
         Total shareholders' equity ........     14,273,278      15,629,674
                                               ------------    ------------

         Total liabilities and
          shareholders' equity .............   $ 15,589,236    $ 17,480,795
                                               ------------    ------------



   See accompanying notes to the consolidated financial statements.


<PAGE>



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

                                               Year Ended December 31,
                                      -----------------------------------------
                                         2002           2001           2000
                                      -----------    -----------    -----------

 Power generation revenue .........   $ 7,739,234    $ 5,978,365    $ 9,272,661
 Rental revenue ...................       109,360        404,702        317,452
                                      -----------    -----------    -----------

    Total revenue .................     7,848,594      6,383,067      9,590,113

Cost of sales, including
 depreciation and
 amortization of $712,386,
 $710,204 and $1,035,297 in 2002,
 2001 and 2000 ....................     8,329,348      6,545,145      8,078,257
                                      -----------    -----------    -----------

Gross (loss) profit ...............      (480,754)      (162,078)     1,511,856

General and administrative expenses       192,936        605,967        289,359
Provision for bad debt
 (recoveries) expense .............      (107,045)       229,443        512,105
Write down of investments in
 power generation projects ........       579,550           --        2,780,085
Management fee paid to
  managing shareholder ............       390,743        492,430        592,644
                                      -----------    -----------    -----------
     Total other operating expenses     1,056,184      1,327,840      4,174,193
                                      -----------    -----------    -----------

Loss from operations ..............    (1,536,938)    (1,489,918)    (2,662,337)
                                      -----------    -----------    -----------

Other income (expense):
   Interest income ................        25,306         32,337         26,657
   Interest expense ...............       (59,844)          --          (36,199)
   Equity income from Ridgewood
    Providence Power Partners, L.P.       239,290        168,919        222,528
    Other expense .................       (24,210)      (193,825)       (71,779)
                                      -----------    -----------    -----------
     Total other income
      (expense), net ..............       180,542          7,431        141,207
                                      -----------    -----------    -----------

Net loss ..........................   $(1,356,396)   $(1,482,487)   $(2,521,130)
                                      -----------    -----------    -----------








          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, 2002, 2001 and 2000
------------------------------------------------------------------------------


                                          Managing
                        Shareholders     Shareholder        Total
                        ------------    -------------   ------------
Shareholders' equity,
  January 1, 2000 ...   $ 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


Net loss for the year     (1,342,832)        (13,564)     (1,356,396)
                        ------------    ------------    ------------

Shareholders' equity,
  December 31, 2002 .   $ 14,461,579    $   (188,301)   $ 14,273,278
                        ------------    ------------    ------------
















    See accompanying notes to the consolidated financial statements.


<PAGE>




Ridgewood Electric Power Trust III
Consolidated Statements of CashFlows
--------------------------------------------------------------------------------

                                                 Year Ended December 31,
                                      -----------------------------------------
                                         2002           2001           2000
                                      -----------    -----------    -----------

Cash flows from operating
  activities:
     Net loss .....................   $(1,356,396)   $(1,482,487)   $(2,521,130)
                                      -----------    -----------    -----------

    Adjustments to reconcile net
     loss to net cash flows from
      operating activities:
     Depreciation and amortization .      712,386        710,204      1,035,297
     Provision for doubtful
      accounts .....................         --             --          512,105
     Writedown of investments in
       power generation projects ...      579,550           --        2,780,085
     Equity in earnings from
      unconsolidated Ridgewood
      Providence Power Partners LP .     (239,290)      (168,919)      (222,528)
     Changes in assets and
      liabilities:
       Decrease (increase)
         restricted cash ...........      197,430       (297,430)          --
       Decrease (increase) in
         trade receivables .........      207,672      1,217,945     (1,502,692)
       (Increase) decrease in
         other current assets ......      (60,866)       121,897         58,026
       Increase in other other
         assets ....................      (14,000)      (556,000)          --
       (Decrease) increase in
         accounts payable and
         accrued expenses ..........     (213,812)        88,100        423,822
       Decrease in accrued
         fuel expense ..............     (154,873)      (305,092)          --
       Increase (decrease) in
         due to affiliates, net ....      573,968       (550,342)       929,290
       (Decrease) increase in
         other liabilities .........     (250,000)       250,000           --
                                       -----------    -----------    -----------
         Total adjustments .........    1,338,165      1,120,547      4,013,405
                                       -----------    -----------    -----------

         Net cash (used in)
          provided by
          operating activities .....      (18,231)      (361,940)     1,492,275
                                       -----------    -----------    -----------

Cash flows from investing
  activities:
     Cash distribution from
      Ridgewood Providence Power
      Partners L.P. ................         --          356,732        414,734
     Reimbursement (payment) of
      capital expenditures .........       10,453        (33,247)      (307,689)
                                       -----------    -----------    -----------
         Net cash provided by
          investing activities .....       10,453        323,485        107,045
                                       -----------    -----------    -----------

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)
                                       -----------    -----------    -----------
         Net cash used in
          financing activities .....         --             --       (1,781,115)
                                       -----------    -----------    -----------

Net decrease in cash and
 cash equivalents ..................       (7,778)       (38,455)      (181,795)
Cash and cash equivalents,
  beginning of year ................      387,672        426,127        607,922
                                       -----------    -----------    -----------
Cash and cash equivalents,
  end of year ......................  $   379,894    $   387,672    $   426,127
                                       -----------    -----------    -----------



      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

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

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

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 adopted SFAS 142 effective
January 1, 2002, with no material impact on the consolidated financial
statements.

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 has assessed that this
standard will not have a material impact 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 adopted SFAS
144 effective January 1, 2002. The Trust recognized an impairment of certain
generating assets, totaling $579,550 in the 2002 consolidated financial
statements. Such a loss would have been recognized under SFAS 121, the
predecessor standard to SFAS 144.

SFAS 145
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Correction.
SFAS No. 145 eliminates extraordinary accounting treatment for reporting gain or
loss on debt extinguishment, and amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings, or
describe their applicability under changed conditions. The Trust will adopt SFAS
145 effective January 1, 2003 and has determined that this standard will not
have a material impact on the Trust.

SFAS 146
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. SFAS No. 146 requires recording costs associated
with exit or disposal activities at their fair values when a liability has been
incurred. The Trust will adopt SFAS 146 effective January 1, 2003 and has
determined that this standard will not have a material impact on the Trust.

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

FIN 46
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities" ("FIN 46") which changes the criteria by which one
company includes another entity in its consolidated financial statements. FIN 46
requires a variable interest entity to be consolidated by a company if that
company is subject to a majority of the risk of loss from the variable interest
entity's activities or entitled to receive a majority of the entity's residual
returns or both. The consolidation requirements of FIN 46 apply immediately to
variable interest entities created after January 31, 2003, and apply in the
first fiscal period beginning after June 15, 2003, for variable interest
entities created prior to February 1, 2003. The Trust will adopt the disclosure
provisions of FIN 46 effective June 15, 2003 and has determined that the
adoption will not have a material impact on the Trust's consolidated financial
statements.

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. 144, Accounting for the Impairment
of Long-Lived Assets to be Disposed Of, the Trust evaluates long-lived assets,
such as fixed assets and specifically identifiable intangibles, when events or
changes in circumstances indicate that the carrying value of such assets may not
be recoverable. The determination of whether an impairment has occurred is made
by comparing the carrying value of an asset to the estimated undiscounted cash
flows attributable to that asset. If an impairment has occurred, the impairment
loss recognized is the amount by which the carrying value exceeds the discounted
cash flows attributable to the asset or the estimated fair value of the asset.

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

Depreciation is recorded using the straight-line method over the useful lives of
the assets, which are 10 to 20 years with a weighted average of 18 years at
December 31, 2002 and 2001. During 2002, 2001 and 2000, the Trust recorded
depreciation expense of $640,646, $638,464 and $978,721, 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 2002, 2001 and 2000, 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 2002, 2001 and 2000, the Trust's largest customer, Pacific Gas and
Electric Company ("PG&E"), accounted for 75%, 53% and 68%, respectively of total
revenues. During 2002, 2001 and 2000, the Trust's second largest customer
accounted for 12%, 17% and 11%, respectively of total revenues. PG&E is
experiencing severe financial difficulty, see Note 8 for additional discussion.

Income taxes
No provision is made for income taxes in the accompanying consolidated financial
statements as the income or losses of the Trust are passed through and included
in the tax returns of the individual shareholders of the Trust. At December 31,
2002 and 2001, the Trust's net assets had a tax basis of $21,374,328 and
$22,028,317, respectively.

Supplemental cash flow information
Total interest paid during the years ended December 31, 2002, 2001 and 2000 was
$59,844, $0 and $36,199, respectively.

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

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 8 - Pacific Gas and Electric Company Financial
Crisis, for developments affecting the Byron and San Joaquin Projects.

Byron Power Partners, L.P. (known as the Byron 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 8 - Pacific Gas and Electric Company Financial Crisis, for developments
affecting the Byron and San Joaquin Projects.

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

The Providence Project is fueled by methane gas produced and collected from the
landfill. The electricity generated is sold to New England Power Corporation
under a long-term contract. The remaining 64.3% of Ridgewood Power is owned by
Ridgewood Electric Power Trust IV ("Trust IV"), whose managing partner is also
Ridgewood Power LLC.

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

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

  Balance Sheet
                             For the Year Ended December 31,
                                   2002          2001
                               -----------   -----------

Current assets .............   $ 1,827,155   $ 1,458,891
Other non-current assets ...    17,088,980    18,327,504
                               -----------   -----------
Total assets ...............   $18,916,135   $19,786,395

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

Current liabilities ........   $ 2,034,392     2,619,729
Long-term debt .............       867,223     1,822,425
                               -----------   -----------
Total liabilities and equity   $18,916,135   $19,786,395

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

Trust share ................   $ 5,717,184   $ 5,488,894
                               -----------   -----------


  Statements of Operations

                    For the Year Ended December 31,
                 ------------------------------------
                    2002         2001         2000
                 ----------   ----------   ----------

Revenue ......   $7,344,120   $7,472,308   $7,294,717
Cost of sales     5,885,503    5,840,911    5,632,625
Other expenses      788,338    1,221,061    1,038,764
                 ----------   ----------   ----------
Net income ...   $  670,279   $  410,336   $  623,328
                 ----------   ----------   ----------

Trust share ..   $  239,290   $  168,919   $  222,528
                 ----------   ----------   ----------


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.

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

The Trust has shut down several of the projects and as a result recorded
writedowns of $1,948,237 in 2000, and $8,816,405 in the years prior to 2000.
During 2002, the Trust recorded an additional writedown of $52,070 to adjust the
carrying value of the projects to reflect their current fair market value. The
writedown has been presented as a separate line item under other operating
expenses in the Consolidated Statements of Operations. Four of the projects are
still operated by the Trust with a total base load of 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, 2002, 2001 and 2000, the Trust paid management fees to the managing
shareholder of $390,743, $492,430 and $592,644, 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, 2002.

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

Effective from January 1, 1996, under an operating agreement with the Trust,
Ridgewood Power Management LLC ("Ridgewood Management"), an entity related to
the managing shareholder through common ownership, provides management,
purchasing, engineering, planning and administrative services to the power
generation projects operated by the Trust. Ridgewood Management charges the
projects at its cost for these services and for the allocable amount of certain
overhead items. Allocations of costs are on the basis of identifiable direct
costs, time records or in proportion to amounts invested in projects managed by
Ridgewood Management. During the year ended December 31, 2002, 2001 and 2000,
Ridgewood Management charged the following to the projects based on
proportionate amounts invested:



                                            For the Year Ended December 31,
                                            ------------------------------
                                              2002       2001       2000
                                            --------   --------   --------
JRW Associates, L.P. ....................   $132,732   $152,098   $108,859
Byron Power Partners, L.P. ..............     78,510     89,966     64,396
Ridgewood Providence Power Partners, L.P.    570,159    538,262    344,041
Ridgewood El Segundo LLC ................     15,029     17,223     12,452
On-site Cogeneration Projects:
  Ridgewood/Mass PPLP ...................      4,367      6,658     57,590
  Ridgewood/Elmsford PPLP ...............     35,579     40,771     25,660
  Other On-site Cogeneration
   Project Partnerships .................     33,693     55,354     40,862


At December 31, 2002 and 2001, the Trust had outstanding payables and
receivables, with the following affiliates:

                                        As of December 31,
                                 Due To                 Due From
                             -------------------   --------------------
                               2002       2001       2002       2001
                             ---------  --------   --------   ---------
Ridgewood Management .....   $   --     $231,397   $226,753   $   --
Ridgewood Providence Power
 Partners, L.P. ..........    266,285       --         --      384,715
Other affiliates .........     58,332      9,698     50,330    382,814

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 its principal bank executed a
revolving line of credit agreement, whereby the bank provided a three year
committed line of credit facility of $757,000. The credit facility was extended
until July 31, 2002. During the third quarter of 2002, the Trust extended its
revolving line of credit agreement with its principal bank through August 31,
2002 and subsequently finalized a further extension until July 31, 2003. The
extension provides the Trust with a committed line of credit of $757,000.
Outstanding borrowings bear interest at LIBOR plus 2.5% (3.882% and 4.376% at
December 31, 2002 and 2001, respectively). The credit agreement requires the
Trust to provide 100% cash collateral for any borrowings after December 31,
2002. There were no outstanding borrowings at December 31, 2002 and 2001.

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
at December 31, 2001. In 2002, the Trust decreased the amount of the certificate
of deposit to $100,000. The letters of credit expired in August 2002.

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, 2002 are as follows:

                                                             Year Ended
                                      December 31,            Repayment
                                      ------------            ---------
                                      2003                     $172,932
                                      2004                      172,932
                                      2005                      172,932
                                      2006                      172,932
                                      2007                      172,932
                                      Thereafter             $2,387,664

Rent expense for the years ended December 31, 2002, 2001 and 2000 was $172,932,
$172,332 and $171,600, respectively.

The San Joaquin and Byron projects have a long-term agreement to purchase
natural gas from its supplier. The agreement expires in August 2006.

Future minimum purchases under the agreement as of December 31, 2002 are as
follows:

                                                             Year Ended
                                      December 31,            Purchases
                                      ------------            ---------
                                      2003                   $2,296,766
                                      2004                    2,296,766
                                      2005                    3,512,322
                                      2006                    2,341,548

7.  Fair Value of Financial Instruments

At December 31, 2002 and 2001, 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. Pacific Gas and Electric Company Financial Crisis

Due to financial difficulties, PG&E did not pay in full for electrical energy
and capacity delivered by the San Joaquin and Byron Projects in December 2000
and January 2001. Accordingly, the San Joaquin and Byron Projects were unable to
pay their natural gas supplier for the gas delivered for those months. In late
January of 2001, the gas supplier requested assurance of payment before it would
agree to provide natural gas during February. Due to PG&E's financial crisis and
its inability to pay, the San Joaquin and Byron Projects were unable on their
own to provide an acceptable assurance or to pay the arrears and, as a result,
the supplier refused to provide natural gas beyond February 6, 2001 and the
Trust shut down the San Joaquin and Byron Projects. Many 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 provision for bad debt expense in the
Consolidated Statements of Operations.

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

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 in other liabilities in the December 31, 2001 Consolidated
Balance Sheet and as a current liability in the December 31, 2002 Consolidated
Balance Sheet.

9. Financial Information by Business Segment

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

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

The financial data for business segments are as follows:


                                         Wholesale
                           ----------------------------------------
                              2002           2001           2000
                           ----------     ---------      ----------
Revenue ...............   $ 5,917,877    $ 3,363,789    $ 6,549,527
Depreciation and
  amortization ........       428,036        426,954        427,672
Operating income (loss)      (470,425)    (1,283,347)     1,142,133
Total assets ..........     6,812,337      7,387,797      8,619,907
Capital expenditures ..       (10,453)        33,247        307,689



                                            Retail
                           --------------------------------------
                              2002           2001          2000
                           ----------     ----------    ---------
Revenue ...............   $ 1,930,720    $ 3,019,278   $ 3,040,586
Depreciation and
  amortization ........       284,350        283,250       607,625
Operating income (loss)      (168,694)       512,084    (2,809,255)
Total assets ..........     2,291,340      3,200,827     3,499,289
Capital expenditures ..          --             --            --



                                         Corporate
                        -----------------------------------------
                           2002           2001            2000
                        ----------     ---------      -----------
Revenue ............   $      --      $      --      $      --
Depreciation and
  amortization .....          --             --             --
Operating loss .....      (902,819)      (718,655)      (995,215)
Total assets .......     6,485,559      6,892,171      6,800,140
Capital expenditures          --             --             --


                                          Total
                        -------------------------------------------
                            2002           2001            2000
                        -----------     -----------     -----------
Revenue ............   $  7,848,597    $  6,383,067    $  9,590,113
Depreciation and
  amortization .....        712,386         710,204       1,035,297
Operating loss .....     (1,536,938)     (1,489,918)     (2,662,337)
Total assets .......     15,589,236      17,480,795      18,919,336
Capital expenditures        (10,453)         33,247         307,689


10. Subsequent Event

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

Now that the Providence Project has been qualified, it may sell to retail
electric suppliers the RPS Attributes associated with its electrical energy.
Retail electric suppliers need to purchase RPS Attributes associated with
renewable energy and not necessarily the energy itself. Thus, electrical energy
and RPS Attributes are separable products and need not be sold or purchased as a
bundled product. Retail electric suppliers in Massachusetts will then use the
purchase of such RPS Attributes to demonstrate compliance with the Restructuring
Act and RPS Regulations.

On February 13, 2003, the Providence Project sold the RPS Attributes generated
from the power produced in fourth quarter of 2002 for $336,570. The Trust and
Trust IV are currently negotiating a transaction with a power marketer that does
business in Massachusetts for the sale of the RPS Attributes generated by the
Providence Project, in the calendar year 2003.

In the first quarter of 2003, the Trust entered into negotiations to sell the
co-generation facilities to AES-NJ. In March 2003, the Trust, sold 100% of its
ownership interest in Ridgewood AES to AES-NJ. The acquisition agreement
provides for the sale of 100% of the Trust's ownership in Ridgewood AES in
return for $100,000 cash, a $150,000 interest bearing promissory note
("promissory note") and a $74,394 interest free note ("interest free note"}. The
promissory note bears interest at a rate of 10% per annum, and will be repaid
monthly over a four year term. The interest free note will be repaid over a six
month term. In 2002, the Trust recorded a writedown of $66,783 to reflect the
projects fair market value as determined by the terms of the sale agreement. The
writedown has been presented as a separate line item under other operating
expenses in the Consolidated Statements of Operations.


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

         None.

PART III

Item 10.  Directors and Executive Officers of the Registrant.

(a) General.

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

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

         The Managing Shareholder has also organized the Other Power Trusts as
Delaware business trusts or other Delaware limited liability companies.
Ridgewood Renewable Power LLC is the managing shareholder of the Other Power
Trusts and the manager of the Ridgewood LLCs. The business objectives of these
trusts and LLCs are similar to those of the Trust.

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

         The Managing Shareholder is an affiliate of Ridgewood Energy
Corporation ("Ridgewood Energy"), which has organized and operated 48 limited
partnership funds and one business trust over the last 18 years (of which 25
have terminated) and which had total capital contributions in excess of $190
million. The programs operated by Ridgewood Energy have invested in oil and
natural gas drilling and completion and other related activities. Other
affiliates of the Managing Shareholder include Ridgewood Securities LLC
("Ridgewood Securities"), an NASD member which has been the placement agent for
the private placement offerings of the 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 56, has also served as President of the Trust
since its inception in 1991 and as President of RPM, the Other Power Trusts, and
Ridgewood LLCs since their respective inceptions. Mr. Swanson has been President
and registered principal of Ridgewood Securities and became the Chairman of the
Board of Ridgewood Capital on its organization in 1998. He also is Chairman of
the Board of the Ridgewood Capital Venture Partners I, II, III and IV venture
capital funds (collectively "Ridgewood Venture Funds"). In addition, he has been
President and sole stockholder of Ridgewood Energy since its inception in
October 1982. Prior to forming Ridgewood Energy in 1982, Mr. Swanson was a tax
partner at the former New York and Los Angeles law firm of Fulop & Hardee and an
officer in the Trust and Investment Division of Morgan Guaranty Trust Company.
His specialty is in personal tax and financial planning, including income,
estate and gift tax. Mr. Swanson is a member of the New York State and New
Jersey bars, the Association of the Bar of the City of New York and the New York
State Bar Association. He is a graduate of Amherst College and Fordham
University Law School.

         Robert L. Gold, age 44, has served as Executive Vice President of the
Managing Shareholder, RPM, the Trust, the Other Power Trusts, and Ridgewood LLCs
since their respective inceptions, with primary responsibility for marketing and
acquisitions. He has been President of Ridgewood Capital since its organization
in 1998. As such, he is President of the Ridgewood Venture Funds. He has served
as Vice President and General Counsel of Ridgewood Securities Corporation since
he joined the firm in December 1987. Mr. Gold has also served as Executive Vice
President of Ridgewood Energy since October 1990. He served as Vice President of
Ridgewood Energy from December 1987 through September 1990. For the two years
prior to joining Ridgewood Energy and Ridgewood Securities Corporation, Mr. Gold
was a corporate attorney in the law firm of Cleary, Gottlieb, Steen & Hamilton
in New York City where his experience included mortgage finance, mergers and
acquisitions, public offerings, tender offers, and other business legal matters.
Mr. Gold is a member of the New York State bar. He is a graduate of Colgate
University and New York University School of Law.

         Daniel V. Gulino, age 42, has been Senior Vice President and General
Counsel of the Managing Shareholder, RPM, the Trust, Other Power Trusts and
Ridgewood LLCs. He began his legal career as an associate for Pitney, Hardin,
Kipp & Szuch, a large New Jersey law firm, where his experience included
corporate acquisitions and transactions. Prior to joining Ridgewood, Mr. Gulino
was in-house counsel for several large electric utilities, including GPU, Inc.,
Constellation Power Source, and PPL Resources, Inc., where he specialized in
non-utility generation projects, independent power and power marketing
transactions. Mr. Gulino also has experience with the electric and natural gas
purchasing of industrial organizations, having worked as in-house counsel for
Alumax, Inc. (now part of Alcoa) where he was responsible for, among other
things, Alumax's electric and natural gas purchasing program. Mr. Gulino is a
member of the New Jersey State Bar and Pennsylvania State Bar. He is a graduate
of Fairleigh Dickinson University and Rutgers University School of Law - Newark.

         Christopher I. Naunton, 38, has been the Vice President and Chief
Financial Officer of the Managing Shareholder, RPM, the Trust, the Other Power
Trusts, and the Ridgewood LLCs. 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 50, has served as Vice President of the Managing
Shareholder, RPM, Ridgewood Capital, the Trust, the Other Power Trusts and the
Ridgewood LLCs since their respective inceptions. She has also served as Vice
President of Ridgewood Energy since October 1984, when she joined the firm. Her
primary areas of responsibility are investor relations, communications and
administration. Prior to her employment at Ridgewood Energy, Ms. Olin was a
Regional Administrator at McGraw-Hill Training Systems where she was employed
for two years. Prior to that, she was employed by RCA Corporation. Ms. Olin has
a Bachelor of Arts degree from Queens College.

(c) Management Agreement.

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

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

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

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

(d) Executive Officers of the Trust.

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

         The Corporate Trustee of the Trust is 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 no distributions in 2002 or 2001 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:

                2002         2001         2000         1999        1998
Managing      $390,743     $492,430     $592,664     $594,576    $673,933
Shareholder
Cost
Reimburse-  $13,222,465 $11,946,145   $12,143,034  $15,813,187   $15,617,631
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.

Item 14.  Control and Procedures

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

         During the 2002 annual financial reporting process, management has
identified deficiencies in the Trust's ability to process and summarize
financial information of certain individual projects and equity investees on a
timely basis. Management is establishing a project plan to address this
deficiency in 2003.

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

         The term "disclosure controls and procedures" is defined in Rule
13a-14(c) of the Exchange Act as "controls and other procedures designed to
ensure that information required to be disclosed by the issuer in the reports
files or submits under the Exchange Act is recorded, processed, summarized and
reported, within the time periods specified in the [Securities and Exchange]
Commission's rules and forms." The Trust's disclosure controls and procedures
are designed to ensure that material information relating to the consolidated
subsidiaries is accumulated and communicated to management, including the Chief
Executive Officer and Chief Financial Officer, as appropriate to allow timely
decisions regarding the required disclosures.

PART IV

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

(a) Financial Statements.

     See the Index to Financial Statements in Item 8 hereof.

(b) Reports on Form 8-K.

     None.

(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.

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

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




<PAGE>


SIGNATURES

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


RIDGEWOOD ELECTRIC POWER TRUST III (Registrant)

By:/s/ Robert E. Swanson    President                         April 16, 2003

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 16, 2003
Robert E. Swanson

By:/s/ Christopher Naunton  Vice President and                April 16, 2003
Christopher Naunton      Chief Financial Officer

RIDGEWOOD POWER LLC  Managing Shareholder                     April 16, 2003
By:/s/ Robert E. Swanson    President
Robert E. Swanson




<PAGE>






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

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

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

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

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

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
    a) designed such disclosure controls and procedures to ensure that material
    information relating to the registrant, including its consolidated
    subsidiaries, is made known to us by others within those entities,
    particularly during the period in which this annual report is being
    prepared;

    b) evaluated the effectiveness of the registrant's disclosure controls and
    procedures as of a date within 90 days prior to the filing date of this
    annual report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness
    of the disclosure controls and procedures based on our evaluation as of the
    Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and senior management:
    a) all significant deficiencies in the design or operation of internal
    controls which could adversely affect the registrant's ability to record,
    process, summarize and report financial data and have identified for the
    registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other
    employees who have a significant role in the registrant's internal controls;
    and

6. The registrant's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: April 16, 2003
/s/   Robert E. Swanson
Robert E. Swanson
Chief Executive Officer


<PAGE>



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

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

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

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

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

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
     a) designed such disclosure controls and procedures to ensure that material
     information relating to the registrant, including its consolidated
     subsidiaries, is made known to us by others within those entities,
     particularly during the period in which this annual report is being
     prepared;

     b) evaluated the effectiveness of the registrant's disclosure controls and
     procedures as of a date within 90 days prior to the filing date of this
     annual report (the "Evaluation Date"); and

     c) presented in this annual report our conclusions about the effectiveness
     of the disclosure controls and procedures based on our evaluation as of the
     Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and senior management:
    a) all significant deficiencies in the design or operation of internal
    controls which could adversely affect the registrant's ability to record,
    process, summarize and report financial data and have identified for the
    registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other
    employees who have a significant role in the registrant's internal controls;
    and

6. The registrant's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: April 16, 2003
/s/   Christopher I. Naunton
Christopher I. Naunton
Chief Financial Officer