SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

                  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 2001

                         Commission file number 0-21304

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

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

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

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

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

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

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

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

     There is no market for the Shares. The aggregate capital contributions made
for the Registrant's voting Shares held by non-affiliates of the Registrant at
March 30, 2002 was $23,537,750.

Exhibit Index is located on Page 31.

<PAGE>


PART I

Item 1.  Business.

Forward-looking statement advisory

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

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

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

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

(a)  General Development of Business.

         The Trust was organized as a Delaware business trust on November 20,
1992 to participate in the development, construction and operation of
independent power generating facilities ("Independent Power Projects" or
"Projects"). Ridgewood Energy Holding Corporation ("Ridgewood Holding"), a
Delaware corporation, is the Corporate Trustee of the Trust.

         The Trust sold shares of beneficial interest in the Trust ("Investor
Shares") in a private placement offering (the "Offering") which ended on January
31, 1994, at which time it had raised approximately $23.5 million. Net of
offering fees, commissions and expenses, the Offering provided approximately
$19.4 million of net funds available for investments in the development and
acquisition of Projects. The Trust has 483 record holders of Investor Shares
(the "Investors"). As described below in Item 1(c)(2), the Trust (and its
subsidiaries) owns interests in five Projects.

        The Trust made an election to be treated as a "business development
company" under the Investment Company Act of 1940, as amended (the "1940 Act").
On February 27, 1993, the Trust notified the Securities and Exchange Commission
of such election and registered the Investor Shares under the Securities
Exchange Act of 1934, as amended (the "1934 Act"). On April 29, 1993, the
election and registration became effective. On November 5, 2001, the Trust
issued to the owners of Investor Shares (the "Investors") a "Notice of
Solicitation of Consents," in which the Trust sought the consent of the
Investors to withdraw its election to be treated as a "business development
company" under the 1940 Act and to make certain amendments to the Trust's
Declaration of Trust ("Declaration") as a result of such withdrawal, including,
but not limited to, deletion of the provision of the Declaration requiring
Independent Trustees. Consents were tabulated at the close of business on
January 7, 2002. A total of 235.3775 Investor Shares were outstanding and
entitled to be voted. Based on such tabulation, a two-third majority, as
required by the Declaration of Trust, consented to such withdrawal and
amendments. On January 10, 2002, the Trust filed with the Securities and
Exchange Commission a notification to withdraw its election to be treated as a
"business development company." As a result of such withdrawal, the Trust now
utilizes generally accepted accounting principles for operating companies.


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

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

The following chart summarizes some of these relationships.

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

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

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

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

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

(b)  Financial Information about Industry Segments.

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

(c)  Narrative Description of Business.

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

(1)      The Trust's Investments.

         (i)  Berkshire Project.

         On January 4, 1994, the Trust made an approximately $2.3 million equity
investment in Pittsfield Investors Limited Partnership, which was formed to
acquire the Berkshire Project, including the assets and business of the
Pittsfield Resource Recovery Facility. The Berkshire Project is a waste to
energy plant located in Pittsfield, Massachusetts. The Berkshire Project, which
has been operating since 1981, burns municipal solid waste supplied by the City
of Pittsfield ("Pittsfield"), surrounding communities and other providers. The
Trust's partners in the Berkshire Project are subsidiaries of Energy Answers
Corporation ("EAC"). EAC made an equity investment of approximately $1.3 million
in the Berkshire Project and also serves as manager and operator of the
facility.

         The Berkshire Project receives "tipping fees" paid by the waste
suppliers based on the number of tons of waste delivered to the facility.
Tipping fees paid by Pittsfield are determined under a long-term waste supply
agreement, which will remain in effect until November 2004, although the
agreement may be cancelled by either party in June 2002. Tipping fees paid by
other waste suppliers are based on the spot market (i.e., current market
prices). The facility generates additional revenue by selling steam produced
from the waste burning process to a nearby paper mill owned by Crane & Co., Inc.
("Crane") under a long-term contract, which will remain in effect until November
2004. The Crane paper mill manufactures currency paper stock used to print
United States currency (as well as currency paper stock for other governments).

         The Trust is entitled to an annual preferred distribution of available
cash flow, representing revenue from the Berkshire Project, (after funding debt
service, debt service reserves and operating and maintenance expenses) in an
amount equal to 15% of its investment. In the event that distributions are
insufficient to pay the 15% preferred distribution in any given year, the
shortfall will be payable out of distributions, if any, in subsequent years.
After the Trust has received its 15% preferred distribution in any given year,
EAC is entitled to an annual management fee for operating and managing the
facility in an amount equal to $300,000, escalating with inflation. After these
initial distributions have been made, the Trust is entitled to receive an
additional amount equal to 5% of its investment and then EAC is entitled to
receive an additional amount equal to 10% of the amount previously distributed
to it. Any remaining distributable cash flow for the year will be shared equally
by the Trust and EAC.

         Distributions from the Berkshire Project ceased in the third quarter of
1998 and have not resumed. In the third quarter of 1998, EAC informed the Trust
that significant and undisclosed cost overruns in the construction of an ash
handling system for the Berkshire Project had depleted the Project's funds. EAC
further advised the Trust that distributions from Berkshire to the Trust were
unlikely to resume. The Berkshire Project's ability to continue operations after
the expiration of the agreements with Crane and Pittsfield in 2004 is uncertain.
This resulted in large part from the 1998 closure of the Pittsfield landfill,
which forced the Project to transport ash to a distant landfill site.
Accordingly, the Trust wrote down the value of the Project to zero as of
December 31, 1998. The Trust has no commitment to fund the Berkshire Project.

     (ii)  Columbia Project.

         On August 31, 1994, the Trust entered into the B-3 Limited Partnership,
with affiliates of EAC, the same firm with which the Trust participates in the
Berkshire Project. The Trust made an investment of approximately $4 million into
the B-3 Limited Partnership to construct a municipal waste transfer station (the
"Columbia Project") located in Columbia County, New York. The Columbia Project
commenced operations in January 1995.

         The purpose of a transfer station like the Columbia Project is to
provide a facility where municipal waste collected from nearby towns by smaller,
short haul trucks can be transferred to larger, long haul trucks for more
efficient transportation of the waste to distant landfills. The primary
customers for the Columbia Project are local waste haulers who dispose of waste
at local landfills scheduled for closing under state and federal requirements.

         The Trust is entitled to receive a cumulative priority return on the
Trust investment of 18% per annum, with any shortfalls being carried forward
into subsequent years. Thereafter, EAC affiliates will be entitled to receive a
management fee of $175,000 escalating with inflation. Any additional cash flow
will be split 50/50 between the Trust and EAC affiliates.

         Distributions from the Columbia Project have been impaired by repeated
extensions of the closing deadlines for some local landfills and capacity
expansions at other local landfills. If waste can be cheaply deposited at local
landfills, there is less demand for consolidating the waste for transfer to
distant sites. See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations for additional information.

(iii)  Monterey Project.

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

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

         In 1996, the State of California deregulated its electric industry and,
among other things, required PG&E, as well as the other two investor-owned
utilities ("IOUs")in California to sell 50% of its fossil-fuel electric
generation resources located in California to unaffiliated third parties,
although PG&E sold more than such 50% amount. In addition, the law required that
PG&E sell all the electricity produced by its remaining electric generation
resources to, and purchase all of its electric energy needs from, the California
Power Exchange ("CalPx"). During the early years of deregulation, this framework
worked well and was profitable for PG&E because the wholesale price of
electricity purchased from the CalPx was substantially lower than the "frozen"
retail price of electricity that PG&E charged its end-use customers. The
difference between the two prices was used by PG&E to recoup stranded
investments and pay dividends to its parent, PG&E Corporation, which dividends
were then invested in unregulated subsidiaries and used for other corporate
purposes. However, beginning in the summer of 2000, the price for electricity
increased and was substantially higher than the retail price that PG&E was
permitted by law to charge. Therefore, the difference between what PG&E paid for
electricity and what it could resell such electricity for resulted in huge
losses.

         As a result of the California energy crisis, PG&E did not pay in full
for electrical energy and capacity delivered by the Monterey Project in December
2000 and January 2001. Accordingly, the Monterey Project was unable to pay its
natural gas supplier for the gas delivered for those months. In late January of
2001, the gas supplier requested assurance of payment before it would agree to
provide natural gas during February. Due to PG&E's financial crisis and its
inability to pay, the Monterey Project was unable on its own to provide an
acceptable assurance or to pay the arrears and, as a result, the supplier
refused to provide natural gas beyond February 6, 2001. On February 1, 2001,
PG&E made a partial payment equal to 15% of the amount due for December 2000. On
March 5, 2001, PG&E made another partial payment equal to 15% of the amount due
January 2001. These amounts were insufficient, after payroll costs were met, to
cover the amount owed to the natural gas supplier. On Tuesday, February 6, 2001,
the Trust shut down the Monterey Project because the supplier of natural gas
terminated deliveries of natural gas as of that date. Many QFs under contract
with PG&E suffered the same fate and were forced to shut operations because of
PG&E's failure to pay for energy and capacity delivered. The Monterey Project,
along with Byron Power Partners, L.P. ("Byron Project ") and JRW Associates,
L.P. ("San Joaquin Project"), both of which are owned by Power III and have
Power Contracts with PG&E, instituted a lawsuit in California state court
against PG&E for breach of the Power Contract. On April 4, 2001, as a result of
its financial problems, PG&E filed for protection under the U.S. Bankruptcy
laws. As a result of such filing, the action the Monterey Project brought
against PG&E in California state court was stayed.

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

         In the second half of 2001, the natural gas supplier made demands for
payment of the arrears owed by Monterey. In December 2001, the Monterey Project
and the Byron and San Joaquin Projects, (each of whom used the same supplier)
and the natural gas supplier executed a settlement agreement. Pursuant to the
settlement agreement, the Monterey, 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 payments to the natural gas supplier were based upon the amount of gas used
by each project. As a result of the upfront payment, the Monterey Project has
completely discharged its obligation to the natural gas supplier. The Byron and
San Joaquin Projects are responsible for the remaining balance.

         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 and wait for payment from PG&E of any outstanding balance until such time
as the Bankruptcy Plan of Reorganization is confirmed by the Bankruptcy Judge.
Such plan has not yet been confirmed. Finally, in order to execute an amendment
with a fixed energy price, it was necessary to procure natural gas at a fixed
price. The Monterey Project was able to procure such supply of natural gas from
Coral Energy Services, Inc., ("Coral") a subsidiary of Shell Oil. Therefore,
until approximately August 2006, the Monterey Project will be operating under
the Amendment, which is expected to result in positive cash flow to the Monterey
Project.

(iv) California Pumping Project

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

         The Pumping Project has been operating since 1992 and uses 26
natural-gas-fired reciprocating engines with a rated equivalent capacity of 6
Megawatts to provide power for irrigation wells that furnish water for orchards
of lemon and other citrus trees. The power is purchased by local farmers and
farmers' co-operatives pursuant to electric services contracts. Presently, the
Pumping Project's rates are approximately 90% of Southern California Edison
Company's agricultural rate of 12.2 cents/kwh. Early in 2001, the Pumping
Project suspended the 10% discount from SCE's rates due to the extremely high
cost of natural gas (the fuel used by the Pumping Project's engines). In
addition, and also due to the high cost of natural gas, the Pumping Project
informed its customers that the cost of such gas would be passed-through and
paid by such customers. The Pumping Project did not lose any customers as a
result of these changes. However, in October of 2001, after natural gas prices
decreased, the Pumping Project reinstated a 10% discount from SCE's rates and
suspended the natural gas pass-through.

         Recently, several of the Pumping Project's customers have indicated
that they would like to own the engines supplying them electricity and requested
proposals from the Pumping Project to buy out of their energy services contract
and purchase the engines. The Pumping Project has proposed to such customers a
transaction in which they would purchase the used engines from the Pumping
Project over a five (5) year term. During such term, the Pumping Project will
provide operation and maintenance services to the customers who opt to purchase
the engines. Such offer has been provided to certain customers, but no final
transaction has been negotiated or finalized.

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

 (v)  San Diego Project.

         The Trust acquired its interest in the San Diego Project on March 21,
1994, when it made an investment of approximately $2.3 million to acquire an 80%
interest in the Project. The Trust made additional capital contributions,
totaling approximately $1.2 million, to the Project to fund working capital and
to purchase various leased equipment. On June 25, 1997 the Trust sold its entire
interest in the San Diego Project to subsidiaries of NRG Energy, Inc. of
Minneapolis, Minnesota ("NRG"). The sale price was $6,200,000, of which
$3,500,000 was paid in cash at the closing. The remaining $2,700,000 was paid by
delivery of a secured, purchase money promissory note of the principal NRG
subsidiary purchasing the Project. The note bears interest at 8% per year and is
payable in equal monthly installments of principal and interest through its
maturity on June 25, 2003. The note is secured by the partnership interests sold
by the Trust to the NRG subsidiaries.

 (3) Project Management and Operations.

         The Monterey Project's revenue from its Power Contract consists of two
components, energy payments and capacity payments. Energy payments are based on
a facility's net electric output, with payment rates 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 Berkshire Project obtains waste for fuel under a long term contract
providing it with revenues from tipping fees, which are subject to the default
risks of dealing with municipalities and small trash haulers, and sells steam to
Crane under a long-term contract. The Columbia Project obtains its revenues from
spot and contract sales of transfer station services which are dependent upon
the volume of waste delivered to it and which are sensitive to the prices of
alternative disposal methods and local economic activity.

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

         The major costs of a Project while in operation will be debt service
(if applicable), fuel, taxes, maintenance and operating labor. The ability to
reduce operating interruptions and to have a Project's capacity available at
times of peak demand are critical to the profitability of a Project.
Accordingly, skilled management is a major factor in the Trust's business. The
Berkshire and Columbia Projects are managed by EAC, which has a subordinated
equity or an income interest in the Projects, which may create an additional
incentive for the manager. The Trust monitors their performance using RPM
personnel and outside consultants.

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

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

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

                                         Calendar year
                                    2001         2000         1999

Pacific Gas & Electric Co.          63.1%         80.0%       68.8%

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

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

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

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

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

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

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

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

         In conclusion, the trend in the industry, as a result of the matters
detailed below, may be a retrenching and reversion to a more regulated electric
industry, with strict reporting requirements and cost of service regulation.
However, many of those charged with the responsibility of investigating the
Enron or the California problems have not disavowed deregulation. In any event,
such market change and reporting requirements, if adopted, may not impact upon
the Monterey Project, which currently has a Power Contract with PG&E. The Trust
has no direct exposure to Enron. The Trust's indirect exposure to Enron cannot
yet be determined.

(5)  Competition

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

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

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

         The Berkshire Project's contract to supply steam terminates in 2004,
although it may be terminated in June 2002 by the Project or Crane. Because it
is normally inefficient to transport steam over long distances, the Trust
believes that so long as the cost of suitable municipal waste does not
substantially increase or the costs of alternate fuels does not decrease far
below current levels, the Berkshire Project should be able to renew its contract
at a price comparable to or lower than the cost to Crane & Co. of running its
own boilers or using a new cogeneration facility. There is no assurance that the
Project can do so or that the customer will be financially capable of doing so.

         The Columbia Project, as described above, faces competition from a
national waste management company much larger than itself, from local landfill
operators (if their permits to receive waste are again extended) and possibly
from other local entrepreneurs. There are few barriers to entry in the waste
transfer and management industry. The Pumping Project is subject to competition
from the local electric utility, which serves much of Southern California and
which offers electricity at discounted rates to operate electric pumps rather
than the natural gas-fueled pumps operated by the Project. As deregulation of
the electricity market proceeds in California, the Project will also face
competition from power marketers and independent generating companies. Barriers
to entry into the electric or gas-fueled irrigation pumping industry are also
low.

(6)  Regulatory Matters.

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

(i)  Energy Regulation.

         (i)  Energy Regulation.

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

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

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


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

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

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

(ii)  Environmental Regulation.

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

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

         The Berkshire Project is not a QF and does not generate electricity.
However, it was operating prior to November 15, 1990 and is thus currently
exempt from the requirement to obtain sulfur dioxide allowances.

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

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

 (iii)  Potential Legislation and Regulation.

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

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

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

(e)  Employees.

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

Item 2.  Properties.

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

         The following table shows the material properties (relating to
Projects) owned or leased by the Trust's subsidiaries or partnerships in which
the Trust has an equity interest. Ownership rights to the property associated
with the Berkshire Project are held under a long-term lease-purchase agreement
and related non-recourse industrial revenue bond financing agreements among
Pittsfield's industrial development authority and others. Upon repayment of the
bonds and the satisfaction of other conditions, the partnership which operates
the facility and in which the Trust owns an interest, will have the option to
acquire the facility for nominal consideration. The other properties are not
subject to any mortgages, liens or encumbrances. All of the Projects are
described in further detail at Item 1(c)(2).

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

Berkshire   Pittsfield,
            MA           Leased     2004      5      30,000     Waste-to energy

Columbia    Columbia,
            NY           Owned       N/A      44     25,000     Municipal waste

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


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

Item 3.  Legal Proceedings.

         On April 1, 1999, Pacific Gas and Electric Company ("PG&E") sued the
Trust's subsidiary that owns the Monterey Project in the Superior Court of
California for the City and County of San Francisco. PG&E alleged that the
Monterey Project did not meet federal and state efficiency requirements and that
accordingly the Project was not entitled to the benefit of discounted natural
gas fuel rates allowable to qualifying cogeneration facilities. The lawsuit
claimed an unspecified amount of damages. The State lawsuit was dismissed
without prejudice and by agreement of the parties and the matter was brought by
PG&E to the Federal Energy Regulatory Commission ("FERC") by petition for a
determination.

         PG&E filed with FERC a petition seeking a revocation of the Monterey
Project's QF status and a refund of certain overpayments PG&E claims it made to
the Project, which were not justified due to the Monterey Project's alleged
failure to maintain QF status. The FERC proceeding generally involved a
determination of the proper location for metering and computing efficiency
standards. The Trust believed that its location of the meter is correct for
determining such standards and that it would succeed at FERC and retain its QF
status and that no refunds will be required.

         On December 19, 2001, FERC rendered its decision completely in favor of
the Monterey Project on all aspects of the claims that PG&E raised. The time
period within which PG&E was legally obligated to seek a re-hearing of the order
from FERC has expired with no such rehearing being filed. Therefore, the FERC
order in favor of the Monterey Project is now final and cannot be appealed by
PG&E.

         On February 6, 2001, the Monterey Project, along with the Byron and San
Joaquin Projects owned by Power III, filed an action in the Superior Court of
California for the City and County of San Francisco against PG&E seeking, among
other things, that PG&E's failure to pay is a breach of the Power Contract. Such
lawsuit was stayed when PG&E filed for bankruptcy and was ultimately dismissed
when the Monterey Project executed the 5-year Amendment to the Power Contract
described above.

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


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

         On November 5, 2001, the Trust issued to the owners of Investor Shares
(the "Investors") a "Notice of Solicitation of Consents," in which the Trust
sought the consent of the Investors to withdraw its election to be treated as a
"business development company" under the 1940 Act and to make certain amendments
to the Trust's Declaration as a result of such withdrawal, including, but not
limited to, deletion of the provision of the Declaration requiring Independent
Trustees. Consents were tabulated at the close of business on January 7, 2002. A
total of 235.3775 Investor Shares were outstanding and entitled to be voted.
Based on such tabulation, a two-thirds majority of Investor Shares, as required
by the Declaration, consented to such withdrawal and amendments. On January 10,
2002, the Trust filed with the Securities and Exchange Commission a notification
to withdraw its election to be treated as a "business development company."

PART  II

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

(a)  Market Information.

         The Trust sold 235.3775 Investor Shares of beneficial interest in the
Trust in its private placement offering of Investor Shares which closed on
January 31, 1994. There is currently no established public trading market for
the Investor Shares. As of the date of this Form 10-K, all such Investor Shares
have been issued and are outstanding. There are no outstanding options or
warrants to purchase, or securities convertible into, Investor Shares.

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

         The Managing Shareholder has investigated the possibility and
feasibility of a combination of the six Trusts and the Egypt Fund into a
publicly traded entity. This would require the approval of the Investors in the
Trust and the other programs after proxy solicitations, complying with
requirements of the Securities and Exchange Commission, and a change in the
federal income tax status of the Trust from a partnership (which is not subject
to tax) to a corporation. The process of considering and effecting a
combination, if the decision is made to do so, will be very lengthy. There is no
assurance that the Managing Shareholder will recommend a combination, that the
Investors of the Trust or other programs will approve it, that economic
conditions or the business results of the participants will be favorable for a
combination, that the combination will be effected or that the economic results
of a combination, if effected, will be favorable to the Investors of the Trust
or Other Power Trusts. After conducting investigations during 2001, the Managing
Shareholder concluded, and informed the Investors, that given current market
conditions caused by, among other things, the general U.S. economic down turn,
the September 11th terrorist attacks, the Enron bankruptcy and general
volatility in the independent power business, it is preferable to delay
significant expenditures pursuing any such combination until market conditions,
as described above, improve.

(b)  Holders

         As of the date of this Form 10-K, there are 483 record holders of
Investor Shares.

(c)  Dividends

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

                                         Year Ended       Year ended
                                         December 31,     December 31,
                                            2001            2000

Total distributions to Investors           $ --          $  706,925
Distributions per Investor Share           $ --          $    3,003
Distributions to Managing Shareholder      $ --          $    7,141

         The Trust suspended distributions in April 1999 to create a reserve at
the Monterey Project level for the costs of the Monterey Project legal
proceedings. The Managing Shareholder resumed limited quarterly distributions
from the Trust beginning in April 2000 and then discontinued them effective
January 1, 2001. The Trust's decision whether to make future distributions to
Investors and their timing will depend on, among other things, the net cash flow
of the Trust and retention of reasonable reserves as determined by the Trust to
cover its anticipated expenses. See Item 7 Management's Discussion and Analysis
of Financial Condition and Results of Operations.

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

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

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

Selected Financial Data
                        As of and for the year ended December 31,
                      2001      2000      1999      1998       1997
                               Restated  Restated  Restated  Restated
Total Fund Information:
Revenues         $2,374,396 3,530,580  2,507,166   2,184,036  3,290,545
Net income (loss)(1,088,887)  218,437   (203,368) (1,617,920) 4,335,303
                                                     (A)        (B)
Net assets
(shareholders'
  equity)         7,803,731  8,892,618  9,388,247  9,876,924 15,196,015
Investments in
 Plant and
 Equipment (net
 of depreciation) 2,003,302  2,221,614  2,446,494  2,654,809  2,563,296
Investment
 in Power
 Contract(net
 of amortization) 2,183,040  2,304,320  2,425,600  2,546,880  2,425,601
Total assets      8,216,155  9,595,529 10,311,744 10,597,576 15,681,325
Long-term
 Obligations      1,227,674         --         --         --         --
Per Share:
Revenues             10,087     15,000     10,652      9,279     13,980
Net income(loss)     (4,626)       928       (864)    (6,873)    18,419
                                                         (A)        (B)
Net asset value      33,154     38,163     39,886     41,962     64,560
Distributions
 to Investors            --      3,003      1,200       6,000      19,692


(A) Includes writedown of investment of $2,347,330 ($9,973 per Investor Share)
(B) Includes  $3,652,775 of income from sale of an investment ($15,519 per
     Investor Share)

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

Introduction

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

Outlook

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

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

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

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

         Additional trends affecting the independent power industry generally
are described at Item 1 - Trends Affecting the Electric Utility and Independent
Power Industries.

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

Results of Operations

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

Total revenues decreased $1,157,000, or 33%, to $2,374,000 in 2001 from
$3,531,000 in 2000. The decrease in revenues is due primarily to the shut down
of the Monterey Project from February to August 2001 due to the PG&E's
non-payment of amounts owed to the project (see Item 1(c)iii). The decrease in
revenues from the Monterey Project was partially offset by an increase of
$170,000 of revenues from the Pumping Project due to higher prices.

Gross profit, which represents total revenues reduced by cost of sales,
decreased by $1,127,000 to a gross loss of $460,000 in 2001 from a gross profit
of $667,000 in 2000. The decrease in gross profit primarily reflects the
decrease in revenues discussed above. Cost of sales did not decrease
significantly despite the shut down on the plant for almost six months because
the price of natural gas was substantially higher in 2001 compared to 2000.

General and administrative expenses decreased $292,000, or 39%, to $466,000 in
2001 from $758,000 in 2000. The decrease primarily reflects lower legal costs
associated with the litigation with PG&E related to the Monterey Project and, to
a lesser extent, lower expenses associated with the sale of PG&E receivables to
AMROC(which decreased $117,000 from $244,000 in 2000 to $127,000 in 2001
reflecting the greater amount of 2000 receivables sold as compared to 2001
receivables).

The management fee paid to the Managing Shareholder was $177,000 in 2001. In
2000, the Managing Shareholder had waived the management fee.

The loss from operations increased $1,012,000 to $1,103,000 in 2001 from $91,000
in 2000 which primarily reflects the decline in the Monterey Project's results
as well as the increase in the management fee.

Other income, net, decreased by $295,000 or 79%, to $14,000 in 2001 from
$309,000 in 2000. The decrease is primarily due to a $164,000 decrease in the
Trust's equity income in the Columbia Project and a $106,000 increase in other
expenses. The decrease in income from the Columbia Project was primarily the
result of decreasing margins from the project caused by capacity expansions at
nearby competing landfills. The increase in the other expenses primarily related
to the costs incurred in issuing the "Notice of Solicitation of Consents."

The Trust recorded net income of $218,000 in 2000 compared to a net loss of
$1,089,000 in 2001, a change of $1,307,000. This primarily reflects the
deterioration in results from the Monterey Project, as well as the increased
management fees and the reduction in other income, net.

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

         Total revenues increased $1,024,000, or 41%, to $3,531,000 in 2000 from
$2,507,000 in 1999. The increase in revenues was attributable to the Monterey
Project's election to switch the pricing of its electricity sales from a cost
based price to a market based price in the third quarter of 2000.

Gross profit, which represents total revenues reduced by cost of sales,
increased by $550,000 or 470% to $667,000 in 2000 from $117,000 in 1999. The
increase primarily reflects the higher revenues. The decrease in gross profit
primarily reflects the increase in revenues discussed above partially offset by
higher fuel costs.

General and administrative expenses increased $347,000, or 84%, to $758,000 in
2000 from $411,000 in 1999. The increase primarily reflects $244,000 of expenses
recorded in 2000 associated with the sale of PG&E receivables. The remaining
increase was primarily due to legal expenses associated with the Monterey
Project.

The management fee paid to the Managing Shareholder was $56,000 in 1999. In
2000, the Managing Shareholder had waived the management fee.

The loss from operations decreased $259,000 to $91,000 in 2000 from $350,000 in
1999 which primarily reflects the improved revenue from the Monterey Project,
partially offset by higher fuel costs and general and administrative expenses
associated with the Project.

Other income, net, increased by $162,000 or 110%, to $309,000 in 2000 from
$147,000 in 1999. The increase is primarily due to a $132,000 increase in the
Trust's equity income in the Columbia Project due to increasing margins from the
project.

The Trust recorded net income of $218,000 in 2000 compared to a net loss of
$203,000 in 1999, a change of $421,000. This primarily reflects the improvement
in results from the Monterey Project and the increased income from the Columbia
Project.

Liquidity and Capital Resources

In 2001, the Trust's operating activities used $191,000 of cash and in 2000 they
generated $446,000 of cash.

Cash generated from investing activities in 2001 and 2000 was $193,000 and
$298,000, primarily from distributions from the Columbia Project.

Cash used in financing activities of $1,114,000 in 2000 represents distributions
to shareholders of $714,000 and repayments of borrowings under the Trust's line
of credit of $400,000. The Trust temporarily ceased making distributions to
shareholders in the first quarter of 2001.

During 1997, the Trust and Fleet Bank, N.A. (the "Bank") entered into a
revolving line of credit agreement, whereby the Bank provides a three year
committed line of credit facility of $750,000. The credit line was extended
until July 31, 2002. Outstanding borrowings bear interest at the Bank's prime
rate or, at the Trust's choice, at LIBOR plus 2.5%. The credit agreement
requires the Trust to maintain a ratio of total debt to tangible net worth of no
more than 1 to 1 and a minimum debt service coverage ratio of 2 to 1. The credit
facility was obtained in order to allow the Trust to operate using a minimum
amount of cash, maximize the amount invested in Projects and maximize cash
distributions to shareholders. At December 31, 1999, the Trust had $400,000 of
outstanding borrowings which were repaid in the first quarter of 2000. There
were no borrowings under the line of credit in 2001. The Trust has issued
through its bank a standby letter of credit for $504,000 to secure gas purchases
for the Monterey Project. This standby letter of credit is collateralized by the
line of credit and reduces the amount that may be borrowed under the line of
credit from $750,000 to $246,000.

Obligations of the Trust are generally limited to payment of a management fee to
the Managing Shareholder and payments for certain administrative, accounting and
legal services to third persons. Accordingly, the Trust has not found it
necessary to retain a material amount of working capital. The Trust's
significant long-term obligation is limited to a $504,000 letter of credit
issued by the Monterey Project which is collateralized by the Trust's line of
credit facility. The letter of credit expires in August 2002 and the Monterey
Project and the Trust anticipate renewing it annually through 2006. The letter
of credit secures the gas purchases of the Monterey Project.

The Monterey Project has certain long-term obligations relating to its Power
Contract with PG&E and its Gas Agreement with Coral. These long-term obligations
are not guaranteed by the Trust. The Trust and its subsidiaries anticipate that
during 2002 their cash flow from operations will be sufficient to meet their
obligations.

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

  Qualitative Information About Market Risk.

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

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

Quantitative Information About Market Risk

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

                       December 31, 2001
                      Expected Maturity Date
                            2003
                          (U.S. $)

Note receivable from NRG                      $ 800,000
 Interest rate                                        8%

                        December 31, 2001
                       Expected Maturity Date
                            2002
                           (U.S. $)

Bank Deposits and Certificates of Deposit     $  175,000
Average interest rate                               1.77%

Item 8.  Financial Statements and Supplementary Data.

Index to Consolidated Financial Statements

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

Financial Statements for B-3 Limited Partnership

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


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

PART III

Item 10.  Directors and Executive Officers of the Registrant.

(a)  General.

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

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

(b)  Managing Shareholder.

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

         Robert E. Swanson has been the President, sole director and sole
stockholder of Ridgewood Power Corporation since its inception in February 1991
and is now the controlling member, sole manager and President of the Managing
Shareholder. All of the equity in the Managing Shareholder is or will be owned
by Mr. Swanson or by family trusts. Mr. Swanson has the power on behalf of those
trusts to vote or dispose of the membership equity interests owned by them.

         The Managing Shareholder has also organized the Other Power Trusts as
Delaware business trusts to participate in the independent power industry.
Ridgewood Power LLC is now also their managing shareholder. The business
objectives of these six trusts are similar to those of the Trust.

         A number of other companies are affiliates of Mr. Swanson and the
Managing Shareholder. Each of these also was organized as a corporation that was
wholly-owned by Mr. Swanson. In April 1999, most of them were merged into
limited liability companies with similar names and Mr. Swanson became the sole
manager and controlling owner of each limited liability company.

         The Managing Shareholder is an affiliate of Ridgewood Energy
Corporation ("Ridgewood Energy"), which has organized and operated 48 limited
partnership funds and one business trust over the last 17 years (of which 25
have terminated) and which had total capital contributions in excess of $190
million. The programs operated by Ridgewood Energy have invested in oil and
natural gas drilling and completion and other related activities. Other
affiliates of the Managing Shareholder include Ridgewood Securities Corporation
("Ridgewood Securities"), an NASD member which has been the placement agent for
the private placement offerings of the six trusts sponsored by the Managing
Shareholder and the funds sponsored by Ridgewood Energy; Ridgewood Capital
Management LLC ("Ridgewood Capital"), which assists in offerings made by the
Managing Shareholder and which is the sponsor of six privately offered venture
capital funds (the Ridgewood Capital Venture Partners, Ridgewood Capital Venture
Partners II and Ridgewood Capital Venture Partners III funds); Ridgewood Power
VI LLC ("Power VI"), which is a managing shareholder of the Growth Fund, and
RPM. Each of these companies is controlled by Robert E. Swanson, who is their
sole director or manager.

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

         Robert E. Swanson, age 55, has also served as President of the Trust
since its inception in 1991 and as President of RPM and the Other Power Trusts,
since their respective inceptions. Mr. Swanson has been President and registered
principal of Ridgewood Securities and became the Chairman of the Board of
Ridgewood Capital on its organization in 1998. He also is Chairman of the Board
of the Ridgewood Capital Venture Partners I, II, III and IV venture capital
funds (collectively "Ridgewood Venture Funds"). In addition, he has been
President and sole stockholder of Ridgewood Energy since its inception in
October 1982. Prior to forming Ridgewood Energy in 1982, Mr. Swanson was a tax
partner at the former New York and Los Angeles law firm of Fulop & Hardee and an
officer in the Trust and Investment Division of Morgan Guaranty Trust Company.
His specialty is in personal tax and financial planning, including income,
estate and gift tax. Mr. Swanson is a member of the New York State and New
Jersey bars, the Association of the Bar of the City of New York and the New York
State Bar Association. He is a graduate of Amherst College and Fordham
University Law School.


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


         Martin V. Quinn, age 54, has been the Executive Vice President and
Chief Operating Officer of the Managing Shareholder, RPM, the Trust and the
Other Power Trusts since April 2000. Before that, he had assumed the duties of
Chief Financial Officer of these entities in November 1996 under a consulting
arrangement. In April 1997, he became a Senior Vice President and Chief
Financial Officer of Ridgewood Power and the Fund.

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

     Daniel V.  Gulino,  age 41, has been  Senior  Vice  President  and  General
Counsel of the Managing Shareholder, RPM, the Trust and Other Power Trusts since
August 2000. He began his legal career as an associate for Pitney,  Hardin, Kipp
& Szuch, a large New Jersey law firm,  where his experience  included  corporate
acquisitions  and  transactions.  Prior to  joining  Ridgewood,  Mr.  Gulino was
in-house  counsel for several large  electric  utilities,  including  GPU, Inc.,
Constellation Power Source,  Inc. and PPL Resources,  Inc., where he specialized
in  non-utility  generation  projects,  independent  power and  power  marketing
transactions.  Mr. Gulino also has experience  with the electric and natural gas
purchasing of industrial  organizations,  having worked as in-house  counsel for
Alumax,  Inc.  (now part of Alcoa)  where he was  responsible  for,  among other
things,  Alumax's electric and natural gas purchasing  program.  Mr. Gulino is a
member of the New Jersey State Bar and Pennsylvania  State Bar. He is a graduate
of Fairleigh Dickinson University and Rutgers University School of Law - Newark.

         Christopher I. Naunton, 37, has been the Vice President and Chief
Financial Officer of the Managing Shareholder, RPM, the Trust and Other Power
Trusts since April 2000. From February 1998 to April 2000, he was Vice President
of Finance of an affiliate of the Managing Shareholder. Prior to that time, he
was a senior manager at the predecessor accounting firm of
PricewaterhouseCoopers LLP. Mr. Naunton's professional qualifications include
his certified public accountant qualification in Pennsylvania, membership in the
American Institute of Certified Public Accountants and the Pennsylvania
Institute of Certified Public Accountants. He holds a Bachelor of Science degree
in Business Administration from Bucknell University (1986).

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

(c)  Management Agreement.

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

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

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

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

(d) Executive Officers of the Trust.

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

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

(e)      Corporate Trustee

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

         The Managing Shareholder does not charge RPM for the full amount of
rent, utility supplies and office expenses allocable to RPM. As a result, RPM's
charges for its services to the Trust are likely to be materially less than its
economic costs and the costs of engaging comparable third persons as managers.
RPM will not receive any compensation in excess of its costs.

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

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

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

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

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

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

Item 13.  Certain Relationships and Related Transactions.

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

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

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

         In 2001 and 2000, as stated at Item 5 - Market for Registrant's Common
Equity and Related Stockholder Matters, as well as in prior years, the Trust
made distributions to the Managing Shareholder (which is a member of the Board
of the Trust) as stated at Item 5 - Market for Registrant's Common Equity and
Related Stockholder Matters. In addition, the Trust and its subsidiaries paid
fees and reimbursements to the Managing Shareholder and its affiliates as
follows:

                     2001        2000      1999       1998        1997
Managing
Shareholder       $177,727       -0-     55,607     381,594     401,085
RPM Cost
Reimbursements     2,955,915  3,032,954  2,841,952  1,470,207  1,610,806

     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. Under the
Declaration of Trust, the annual rate fell to 1.5% per year beginning February
1, 1999. Beginning April, 1999, the Managing Shareholder waived the fee.
Effective January 1, 2001, it resumed payment of the management fee at the 1.5%
of net asset value annual rate.

         In addition to the foregoing, the Trust reimbursed the Managing
Shareholder at cost for expenses and fees of unaffiliated persons engaged by the
Managing Shareholder for Trust business and in years before 1996 for payroll and
other costs of operation of the Monterey and Pumping Projects. In 1996 and 1997,
these reimbursements were paid to RPM. The reimbursements to RPM, which do not
exceed its actual costs and allocable overhead, are described at Item 10(g) -
Directors and Executive Officers of the Registrant -- RPM.

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

PART IV

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

(a)  Financial Statements.

     See the Index to Consolidated Financial Statements in Item 8 hereof.

(b) Reports on Form 8-K.

     No Forms 8-K were filed with the Commission by the Registrant during the
quarter ending December 31, 2001.

(c)  Exhibits

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     21.   Subsidiaries of the Registrant.           Page 66

<PAGE>


SIGNATURES

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


RIDGEWOOD ELECTRIC POWER TRUST II (Registrant)

By:/s/ Robert E. Swanson    President                         April 16, 2002

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

By:/s/ Robert E. Swanson    President                         April 16, 2002
Robert E. Swanson

By:/s/ Christopher Naunton  Vice President and       April 16, 2002
Christopher Naunton       Chief Financial Officer

RIDGEWOOD POWER LLC  Managing Shareholder            April 16, 2002
By:/s/ Robert E. Swanson    President
Robert E. Swanson


                Ridgewood Electric Power Trust II

                Consolidated Financial Statements

                December 31, 2001, 2000 and 1999



<PAGE>




Report of Independent Accountants


To the Shareholders of
Ridgewood Electric Power Trust II:

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in shareholders' equity and cash
flows present fairly, in all material respects, the financial position of
Ridgewood Electric Power Trust II and its subsidiaries(the "Trust") at
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Trust's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

As discussed in Notes 1 and 2, effective on January 7, 2002, the shareholders
of the Trust consented to end its election to be treated as a Business
Development Corporation under the Investment Company Act of 1940. As a result,
accounting principles generally accepted in the United States of America for
investment companies no longer applied to the Trust and the Trust adopted
accounting principles generally accepted in the United States of America
applicable to operating companies. The financial statements of the Trust for
December 31, 2000 and 1999 have been restated to reflect the application of
accounting principles generally accepted in the United States of America for
operating companies.




PricewaterhouseCoopers LLP
Florham Park, NJ
April 2, 2002


<PAGE>



Ridgewood Electric Power Trust II
Consolidated Balance Sheets

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

                                                            December 31,
                                                     --------------------------
                                                         2001            2000
                                                                      Restated
                                                     -----------    -----------
Assets:
Cash and cash equivalents ........................   $   175,403    $   173,054
Restricted cash ..................................       202,570           --
Trade receivables, net of allowance
 of $244,169 in 2000 .............................       267,870        902,672
Current portion of note receivable
 from sale of investment .........................       522,938        482,902
Due from affiliates ..............................        20,200          6,174
Other current assets .............................        35,909         20,432
                                                     -----------    -----------

       Total current assets ......................     1,224,890      1,585,234

Investment in B-3 Limited Partnership ............     2,527,395      2,683,936

Plant and equipment ..............................     3,419,000      3,412,383
Accumulated depreciation .........................    (1,415,698)    (1,190,769)
                                                     -----------    -----------
                                                       2,003,302      2,221,614
                                                     -----------    -----------

Electric power sales contract ....................     3,032,000      3,032,000
Accumulated amortization .........................      (848,960)      (727,680)
                                                     -----------    -----------
                                                       2,183,040      2,304,320
                                                     -----------    -----------

Note receivable from sale of investment,
 less current portion ............................       277,528        800,425
                                                     -----------    -----------

        Total assets .............................   $ 8,216,155    $ 9,595,529
                                                     -----------    -----------

Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ............   $   230,209    $   378,862
Due to affiliates ................................       182,215        324,049
                                                     -----------    -----------
        Total current liabilities ................       412,424        702,911

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

Shareholders' Equity:
Shareholders' equity (235.3775 investor shares
 issued and outstanding) .........................     7,926,938      9,004,936
Managing shareholder's accumulated deficit
(1 management share issued and outstanding) ......      (123,207)      (112,318)
                                                     -----------    -----------
        Total shareholders' equity ...............     7,803,731      8,892,618
                                                     -----------    -----------

        Total liabilities and shareholders' equity   $ 8,216,155    $ 9,595,529
                                                     -----------    -----------








    See accompanying notes to the consolidated financial statements.


Ridgewood Electric Power Trust II
Consolidated Statements of Operations

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

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

Power generation revenue ..........   $ 2,374,396    $ 3,530,580    $ 2,507,166

Cost of sales, including
 depreciation and amortization
  of $346,209, $347,693 and
   $348,385 in 2001, 2000 and 1999.     2,834,668      2,863,841      2,390,255
                                      -----------    -----------    -----------

Gross (loss) profit ...............      (460,272)       666,739        116,911

General and administrative expenses       465,945        757,836        411,314
Management fee paid to managing
 shareholder.......................       177,337           --           55,607
                                      -----------    -----------    -----------
     Total other operating expenses       643,282        757,836        466,921
                                      -----------    -----------    -----------

Loss from operations ..............    (1,103,554)       (91,097)      (350,010)
                                      -----------    -----------    -----------

Other income (expense):
   Interest income ................        99,848        134,135        162,686
   Interest expense ...............          --           (9,063)       (27,378)
   Equity income from B-3 Limited
    Partnership ...................        43,459        207,339         75,565
    Other expense .................      (128,640)       (22,877)       (64,231)
                                      -----------    -----------    -----------

     Other income (expense), net ..        14,667        309,534        146,642
                                      -----------    -----------    -----------

Net income (loss) .................   $(1,088,887)   $   218,437    $  (203,368)
                                      -----------    -----------    -----------



















 See accompanying notes to the consolidated financial statements.









Ridgewood Electric Power Trust II
Consolidated Statements of Changes in Shareholders' Equity
For the Years Ended December 31, 2001, 2000 and 1999
--------------------------------------------------------------------------------

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

Shareholders' equity,
 January 1, 1999 ......   $ 9,979,398    $  (102,474)   $ 9,876,924

Cash distributions ....      (282,456)        (2,853)      (285,309)

Net loss for the year .      (201,334)        (2,034)      (203,368)
                          -----------    -----------    -----------

Shareholders' equity,
 December 31, 1999 ....     9,495,608       (107,361)     9,388,247

Cash distributions ....      (706,925)        (7,141)      (714,066)

Net income for the year       216,253          2,184        218,437
                          -----------    -----------    -----------

Shareholders' equity,
 December 31, 2000 ....     9,004,936       (112,318)     8,892,618

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

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

























    See accompanying notes to the consolidated financial statements.


<PAGE>



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

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

Cash flows from operating
 activities:
    Net income (loss) ...........   $(1,088,887)   $   218,437    $  (203,368)


    Adjustments to reconcile net
     income (loss)to net cash
      flows from operating
       activities:
    Depreciation and
     amortization ...............       346,209        347,693        348,385
    Provision for doubtful
     accounts ...................          --          244,169           --
    Proceeds from note receivable       482,861        445,853        411,685
    Equity in earnings from
     unconsolidated B-3 Limited
      Partnership ...............       (43,459)      (207,339)       (75,565)
    Changes in assets and
     liabilities:
      Restricted cash ...........      (202,570)          --             --
      Decrease (increase) in
       trade receivable .........       634,802       (773,933)        29,717
      Increase in other
       current assets ...........       (15,477)        (2,509)        (1,635)
      (Decrease) increase in
        accounts payable and
         accrued expenses .......      (148,653)        61,371        107,205
      (Decrease) increase in due
        to/from affiliates,net ..      (155,860)       111,870          4,458
                                    -----------    -----------    -----------
        Total adjustments .......       897,853        227,175        824,250
                                    -----------    -----------    -----------

       Net cash provided by
        operating activities ....      (191,034)       445,612        620,882
                                    -----------    -----------    -----------

Cash flows from investing
 activities:
     Distributions from B-3
      Limited Partnership .......       200,000        300,000        100,000
     Capital expenditures .......        (6,617)        (1,533)       (18,790)
                                    -----------    -----------    -----------
       Net cash provided by
        investing activities ....       193,383        298,467         81,210
                                    -----------    -----------    -----------

Cash flows from financing
  activities:
     Borrowings under line of
      credit facility ...........          --             --          550,000
     Repayments under line of
      credit facility ...........          --         (400,000)      (450,000)
     Cash distributions to
      shareholders ..............          --         (714,066)      (285,309)
                                    -----------    -----------    -----------
       Net cash used in financing
        activities ..............          --       (1,114,066)      (185,309)
                                    -----------    -----------    -----------

Net increase in cash and
 cash equivalents ...............         2,349       (369,987)       516,783
Cash and cash equivalents,
 beginning of year ..............       173,054        543,041         26,258
                                    -----------    -----------    -----------

Cash and cash equivalents,
 end of year ....................   $   175,403    $   173,054    $   543,041
                                    -----------    -----------    -----------

















  See accompanying notes to the consolidated financial statements.


<PAGE>


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


1.       Organization and Purpose

Nature of business
Ridgewood Electric Power Trust II (the "Trust") was formed as a Delaware
business trust on November 20, 1992, 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 4, 1993 and discontinued its offering of shares on
January 31, 1994.

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

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

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

2.    Summary of Significant Accounting Policies

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

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

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

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

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

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

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

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

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

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

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

Depreciation is recorded using the straight-line method over the useful lives of
the assets, which are 3 to 20 years with a weighted average of 15 years at
December 31, 2001 and 2000. During 2001, 2000 and 1999, the Trust recorded
depreciation expense of $224,929, $226,413 and $227,105, respectively.

Electric Power Sales Contract
A portion of the purchase price of the Monterey Project was assigned to the
electric power sales contract and is being amortized over the life of the
contract (25 years) on a straight-line basis. The electric power sales contract
is reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount of the asset may not be recoverable. During 2001, 2000
and 1999, the Trust recorded amortization expense of $121,280.

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

Supplemental cash flow information
Total interest paid during the years ended December 31, 2000 and 1999 was $9,063
and $27,378, respectively.

Significant Customers
During 2001, 2000 and 1999, the Trust's largest customer, Pacific Gas and
Electric Company ("PG&E"), accounted for 63%, 80% and 69%, respectively of total
revenues.

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.

3.       Projects

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

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

See Note 9 - Pacific Gas and Electric Company Financial Crisis, for developments
affecting the Monterey Project.

On April 1, 1999, PG&E sued the Trust's subsidiary that owns the Monterey
Project in the Superior Court of California for the City and County of San
Francisco. PG&E alleged that the Monterey Project did not meet federal and state
efficiency requirements and that accordingly the Project was not entitled to the
benefit of discounted natural gas fuel rates allowable to qualifying
cogeneration facilities. The lawsuit claimed an unspecified amount of damages.
The State lawsuit was dismissed without prejudice and by agreement of the
parties and the matter was brought by PG&E to the Federal Energy Regulatory
Commission ("FERC") by petition for a determination.

PG&E filed with FERC a petition seeking a revocation of the Monterey Project's
QF status and a refund of certain overpayments PG&E claims it made to the
Project, which were not justified due to the Monterey Project's alleged failure
to maintain QF status. The FERC proceeding generally involved a determination of
the proper location for metering and computing efficiency standards. The Trust
believed that its location of the meter is correct for determining such
standards and that it would succeed at FERC and retain its QF status and that no
refunds will be required.

On December 19, 2001, FERC rendered its decision completely in favor of the
Monterey Project on all aspects of the claims that PG&E raised. The time period
within which PG&E was legally obligated to seek a re-hearing of the order from
FERC has expired with no such rehearing being filed. Therefore, the FERC order
in favor of the Monterey Project is now final and cannot be appealed by PG&E.

On December 31, 1998 the Trust, through subsidiaries, filed a legal complaint in
the Superior Court of California for Monterey County against Waukesha-Pierce,
Inc. and subsidiaries, alleging that the subsidiaries had not disclosed the
existence of an obligation of the Monterey project to Pacific Gas and Electric
Company and therefore breached a warranty in the acquisition agreement. The
claim was for approximately $273,000 plus interest and expenses.
Waukesha-Pierce, Inc. was included in the proceeding as a contractual guarantor.
On January 17, 1999, a separate action against Waukesha-Pierce, Inc. was filed
by the Trust's subsidiaries in the United States District Court for the Northern
District of Texas to enforce the guaranty. The parties agreed to dismiss the
Texas case without prejudice before material proceedings resulted. The
California case was settled in March 2000; Waukesha-Pierce Inc. agreed to pay
the Project approximately $190,000 and to cooperate with the Project in the
potential FERC proceedings involving the Monterey project discussed above and
the Trust agreed to cooperate with Waukesha-Pierce in releasing funds due from
PG&E to Waukesha-Pierce, accordingly no amounts have been recorded. The
settlement has not yet been completed, as the funds due from PG&E to
Waukesha-Pierce have not yet been released by PG&E. As a result, no amounts have
been recorded related to this potential settlement.

Pump Services Company, LP (known as California Pumping Project)
In 1995, the Trust acquired a package of natural gas and diesel engines, which
drive deep irrigation well pumps in Ventura County, California. The engines'
shaft horsepower-hours are sold to farmers at a discount from the price of
equivalent kilowatt hours of electricity. The operator pays for fuel,
maintenance, repair and replacement. The project has an equivalent of 6
megawatts of power.

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

In exchange for its investment, the Trust is entitled to receive annually a
preferred distribution of available net cash flow from the facility equal to 18%
of its investment. In the event that in any given year available net cash flow
from the project does not at least equal the amount of the preferred minimum
return, the amount of such shortfall is payable on a priority basis out of any
available net cash flow in subsequent years. The Trust may also be entitled to
receive additional distributions from any net cash flow in excess of the 18%
return on its investment. The aggregate purchase price of the Trust's investment
in the partnership was $3,975,240. The Trust received distributions of $200,000,
$300,014 and $100,000 from the project for the years ended December 31, 2001,
2000 and 1999, respectively.

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

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

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

Balance Sheet Information

                                 December 31, 2001      December 31, 2000
                                 -------------------    -------------------

Current assets                         $ 1,560,006            $ 1,572,896
Non-current assets                       2,366,793              2,526,960
                                 -------------------    -------------------
Total assets                            $3,926,799             $4,099,856
                                 -------------------    -------------------

Current liabilities                      $ 644,757              $ 623,540
Long-term debt                              21,843                 74,263
                                 -------------------    -------------------
Total liabilities and equity            $3,926,799             $4,099,856
                                 -------------------    -------------------


Statement of Operations Information

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

Revenue .........   $5,948,082   $5,856,071   $5,308,904
Operating expense    5,889,936    5,525,722    5,089,672
                    ----------   ----------   ----------

Net income ......   $   58,146   $  330,349   $  219,232
                    ----------   ----------   ----------


During the dissolution or termination of the partnership, profits and losses are
allocated to the partners proportionally according to their original capital
contributions to the partnership until the amount allocated equals the initial
capital contributions. Any remaining profits and losses are allocated to the
partners according to their partnership interests. Distributions are allocated
proportionally to the partners having positive capital balances until those
balances are reduced to zero. Distributions are then allocated to the partners
according to their partnership interests.

4.   Note Receivable from Sale of Investment

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

5.       Line of Credit Facility, Letter 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 $750,000. The credit facility was extended
until July 31, 2002. At December 31, 1999, borrowings under this credit facility
equaled $400,000. The balance outstanding at December 31, 1999 was repaid on
March 6, 2000. Outstanding borrowings bear interest at LIBOR plus 2.5% (4.376%
and 9.07% at December 31, 2001 and 2000, respectively). The amount outstanding
under the line of credit facility must be reduced to zero for a thirty-day
period each year. The credit agreement will require the Trust to maintain a
ratio of total debt to tangible net worth of no more than 1 to 1 and a minimum
debt service coverage ratio of 2 to 1.

In August 2001, the Trust issued through its bank a standby letter of credit in
the amount of $504,000 to secure the gas purchases of the Monterey project. The
Trust used its credit facility and a restricted certificate of deposit in the
amount of $202,570 to collateralize the letter of credit which is presented as
restricted cash on the Consolidated Balance Sheets.

6. Commitments

The Monterey project has a long-term operating ground lease. The lease is for a
term of thirty years.

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

                                                   Year Ended
                             December 31,          Repayment
                             ------------          ---------
                                 2002                12,396
                                 2003                12,396
                                 2004                12,396
                                 2005                12,396
                                 2006                12,396
                               Thereafter           177,676

Rent expense for each of the years ended December 31, 2001, 2000 and 1999 was
$12,396.

7.   Transactions with Managing Shareholder and Affiliates

The Trust entered into a management agreement with the managing shareholder,
under which the managing shareholder renders certain management, administrative
and advisory services and provides office space and other facilities to the
Trust. As compensation to the managing shareholder, the Trust paid to 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. Under the
terms of the management agreement, the annual management fee decreased to 1.5%
of the net asset value of the Trust effective February 1, 1999. For the years
ended December 31, 2001 and 1999, the Trust paid management fees to the managing
shareholder of $177,337 and $55,607, respectively. During the period of April
1999 to December 2000, the managing shareholder waived the management fee to
which it was entitled.

Under the Declaration of Trust, the managing shareholder is entitled to receive
each year 1% of all distributions made by the Trust (other than those derived
from the disposition of Trust property) until the shareholders have been
distributed a cumulative amount equal to 15% per annum of their equity
contribution. Thereafter, the managing shareholder is entitled to receive 20% of
the distributions for the remainder of the year. The managing shareholder is
entitled to receive 1% of the proceeds from dispositions of Trust properties
until the shareholders have received cumulative distributions equal to their
original investment ("Payout"). After Payout, the managing shareholder is
entitled to receive 20% of all remaining distributions of the Trust.

Where permitted, in the event the managing shareholder or an affiliate performs
brokering services in respect of an investment acquisition or disposition
opportunity for the Trust, the managing shareholder or such affiliate may charge
the Trust a brokerage fee. Such fee may not exceed 2% of the gross proceeds of
any such acquisition or disposition. No such fees have been incurred through
December 31, 2001.

The managing shareholder owns 1.45 investor shares of the Trust with a cost of
$121,800. The Trust granted the managing shareholder a single Management Share
representing the managing shareholder's management rights and rights to
distributions of cash flow.

In 1996, under an Operating Agreement with the Trust, Ridgewood Management
provides management, purchasing, engineering, planning and administrative
services to the power generation project operated by the Trust. Ridgewood
Management charges the project at its cost for these services and for the
allocable amount of certain overhead items. Allocations of costs are on the
basis of identifiable direct costs, time records or in proportion to amount
invested in projects managed by Ridgewood Management. During the year ended
December 31, 2001, 2000 and 1999, Ridgewood Management charged Sunnyside
Cogeneration Partners $153,354, $109,148, and $150,711, respectively, for
overhead items allocated in proportion to the amount invested in projects
managed. During the years ended December 31, 2001, 2000 and 1999, Ridgewood
Management charged the California Pumping Project $77,103, $70,118 and $75,818,
respectively, for overhead items allocated in proportion to the amount invested
in projects managed. Ridgewood Management also charged Sunnyside Cogeneration
Partners and the California Pumping Project for all of the direct operating and
non-operating expenses incurred during the periods.

At December 31, 2001 and 2000, the Trust had outstanding payables of $182,215
and $324,049, respectively, to Ridgewood Management. From time to time, the
Trust records short-term payables and receivables from other affiliates in the
ordinary course of business. The amounts payable and receivable do not bear
interest.

8.  Fair Value of Financial Instruments

At December 31, 2001 and 2000, the carrying value of the Trust's cash and cash
equivalents, trade receivables, and accounts payable and accrued expenses
approximates their fair value. The fair value of the letter of credit does not
differ materially from its carrying value.

9. Pacific Gas and Electric Company Financial Crisis

Due to financial difficulties, PG&E did not pay in full for electrical energy
and capacity delivered by the Monterey Project in December 2000 and January
2001. Accordingly, the Monterey Project was unable to pay its natural gas
supplier for the gas delivered for those months. In late January of 2001, the
gas supplier requested assurance of payment before it would agree to provide
natural gas during February. Due to PG&E's financial crises and its inability to
pay, the Monterey Project was unable on its own to provide an acceptable
assurance or to pay the arrears and, as a result, the supplier refused to
provide natural gas beyond February 6, 2001 and the Trust shut down the Monterey
Project. Many 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 Monterey Project entered into an agreement with a financial
institution whereby it sold, irrevocably and without recourse, its undivided
interest in all eligible trade accounts receivables for December 2000 and
January 2001. Costs associated with the sale of receivables of $127,130 and
$244,169 for 2001 and 2000, respectively, primarily related to the discount and
loss on sale, are included in general and administrative expenses in the
Consolidated Statements of Operations.

In August 2001, PG&E and the Monterey Project entered into an amendment to the
electric power sales contract for a term of five years, which would effectively
replace, for such 5 year term, the variable formula for determining the energy
price with a fixed energy price. Also in August 2001, the Monterey Project
entered into a five year fixed price natural gas supply agreement with Coral
Energy Services, Inc., a subsidiary of Shell Oil.
<PAGE>
B-3 Limited Partnership
Financial Statements
(and Report of Independent Accountants)
For the Years Ended December 31, 2001, 2000 and 1999


<PAGE>


B-3 Limited Partnership
Index
--------------------------------------------------------------------------------



                                                                       Page(s)


Report of Independent Accountants.........................................1


Financial Statements

              Balance sheets..............................................2

              Statements of income........................................3

              Statements of partners' equity..............................4

              Statements of cash flows....................................5

              Notes to financial statements..............................6-9




<PAGE>



                                        1
                        Report of Independent Accountants


To the Partners of
B-3 Limited Partnership


In our opinion, the accompanying balance sheets and the related statements of
income, partners' equity and cash flows present fairly, in all material
respects, the financial position of B-3 Limited Partnership (the "Partnership")
at December 31, 2001 and 2000, and the results of its operations and its cash
flows for the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Partnership's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.


/s/ PricewaterhouseCoopers LLP




March 15, 2002



<PAGE>


B-3 Limited Partnership
Balance Sheets
For the Years Ended December 31, 2001, 2000 and 1999
--------------------------------------------------------------------------------


                                                               December 31,
                                                   -----------------------------
                                                           2001           2000
                                                        ----------    ----------
Assets:
Cash and cash equivalents ..........................    $  281,363    $  501,070
Trade receivables, less allowance of $56,000 in
   2001 and $15,411 in 2000 ........................     1,065,214       987,091
Related party receivables ..........................       213,429        84,735
                                                        ----------    ----------
     Total current assets ..........................     1,560,006     1,572,896
                                                        ----------    ----------

Property, plant and equipment, net .................     2,366,794     2,526,960
                                                        ----------    ----------

     Total assets ..................................    $3,926,800    $4,099,856
                                                        ----------    ----------


Liabilities and Partners' Equity:

Liabilities:
Accounts payable ...................................    $   88,774    $  156,936
Related party payables .............................        56,373        66,211
Notes payable, current portion .....................        52,421        61,189
Accrued liabilities ................................       447,190       339,204
                                                        ----------    ----------
     Total current liabilities .....................       644,758       623,540

Notes payable, net of current portion ..............        21,843        74,263
                                                        ----------    ----------

     Total liabilities .............................       666,601       697,803

Partners' equity ...................................     3,260,199     3,402,053
                                                        ----------    ----------

     Total liabilities and partners' equity ........    $3,926,800    $4,099,856
                                                        ----------    ----------








       The accompanying notes are an integral part of the financial statements.

<PAGE>

B-3 Limited Partnership
Statements of Operations
For the Years Ended December 31, 2001, 2000 and 1999


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

Revenue:
Operating fees ..........................   $5,948,082   $5,842,758   $5,305,655
Interest income .........................        5,112       10,042        6,612
Other income ............................           --       13,313        3,249
                                            ----------   ----------   ----------
Total revenue ...........................    5,953,194    5,866,113    5,315,516
                                            ----------   ----------   ----------

Cost and expenses:
     Operating expenses .................    5,610,533    5,215,593    4,782,040
     Depreciation and amortization ......      276,864      309,373      287,663
     Interest expense ...................        7,651       10,798        5,091
     Loss on sale of fixed assets .......           --           --       21,490
                                            ----------   ----------   ----------

           Total costs and expenses .....    5,895,048    5,535,764    5,096,284
                                            ----------   ----------   ----------


Net income ..............................   $   58,146   $  330,349   $  219,232
                                            ----------   ----------   ----------









The accompanying notes are an integral part of the financial statements.


<PAGE>

B-3 Limited Partnership
Statements of Partners' Equity
For the Years Ended December 31, 2001, 2000 and 1999
------------------------------------------------------------------------------

                                          2001           2000           1999
                                      -----------    -----------    -----------

Balance at beginning of period ....   $ 3,402,053    $ 3,371,704    $ 3,252,472
Net income ........................        58,146        330,349        219,232
Distributions .....................      (200,000)      (300,000)      (100,000)
                                      -----------    -----------    -----------

Balance at end of period ..........   $ 3,260,199    $ 3,402,053    $ 3,371,704
                                      -----------    -----------    -----------















The accompanying notes are an integral part of the financial statements.






<PAGE>







B-3 Limited Partnership
Statements of Cash Flows
For the Years Ended December 31, 2001, 2000 and 1999
------------------------------------------------------------------------------


                                            For the Year Ended December 31,
                                          -----------------------------------
                                            2001         2000         1999
                                          ---------    ---------    ---------
Cash flows from operating activities:
Net income ............................   $  58,146    $ 330,349    $ 219,232

Adjustments to reconcile net income to
 net cash provided by operating
  activities:
   Depreciation and amortization ......     276,864      309,373      287,663
   Provision for bad debt .............      40,589      (95,573)          --

   Loss on sale of equipment ..........          --           --       21,490

   Changes in assets and liabilities:
     Trade receivables ................    (118,712)     148,680     (566,470)
     Related party receivables ........    (128,694)     (81,481)      (3,254)
     Other assets .....................          --       17,000       17,576
     Related party payables ...........      (9,838)      51,097       13,771
     Accounts payable .................     (68,162)    (210,656)     (94,045)
     Accrued liabilities ..............     107,986      139,675      121,338
                                          ---------    ---------    ---------
      Net cash provided by
        operating activities ..........     158,179      608,464       17,301
                                          ---------    ---------    ---------

Cash flows from investing activities:
Proceeds from sale of equipment .......          --           --       44,000
Acquisition of property, plant
 and equipment ........................    (116,698)     (40,021)     (52,849)
                                          ---------    ---------    ---------
      Net cash used in investing
        activities ....................    (116,698)     (40,021)      (8,849)
                                          ---------    ---------    ---------

Cash flows from financing activities:
Payments on notes payable .............     (61,188)     (57,899)     (23,102)
Distributions to partners .............    (200,000)    (300,000)    (100,000)
                                          ---------    ---------    ---------

       Net cash used in
        financing activities ..........    (261,188)    (357,899)    (123,102)
                                          ---------    ---------    ---------


Net (decrease) increase in cash
 and cash equivalents .................    (219,707)     210,544     (114,650)

Cash and cash equivalents,
  beginning of year ...................     501,070      290,526      405,176
                                          ---------    ---------    ---------

Cash and cash equivalents,
  end of year .........................   $ 281,363    $ 501,070    $ 290,526
                                          ---------    ---------    ---------

Supplemental disclosure of
 cash flow information:
 Cash paid for interest ...............   $   6,632    $   6,837    $   5,091
                                          ---------    ---------    ---------


During 1999, the Partnership financed the purchase of approximately $217,000 in
equipment with notes payable.







The accompanying notes are an integral part of the financial statements.





<PAGE>


B-3 Limited Partnership
Notes to Financial Statements
--------------------------------------------------------------------------------


1.     Organization and Nature of Operations

       B-3 Limited Partnership (the Partnership) was formed on August 19, 1994.
       Berkshire B-3, Inc. (B-3 Corp) is the general partner. EAC Operations,
       Inc. (eco) and Ridgewood Electric Power Trust II (Ridgewood II) are
       limited partners. The Partnership was formed for the purpose of owning
       and operating a solid waste Transfer Station near Exit B-3 of the New
       York State Thruway, Berkshire Spur in Canaan, New York.

       The Transfer Station is designed to accept and prepare solid waste for
       transport to properly licensed waste management facilities. The Transfer
       Station accepts solid waste from towns and private solid waste haulers.


2.     Summary of Significant Accounting Policies

       Revenue
       Revenue is recognized upon the receipt of waste.

       Cash and cash equivalents
       The Partnership considers money market account balances to be cash
       equivalents.

       Property, plant and equipment
       Property, plant and equipment are stated at cost and are depreciated
       using the straight-line method over the estimated useful lives of the
       assets, as follows:

                  Equipment                          3 - 7 years
                  Building                           15 years

       Intangible assets
       Intangible assets included organization costs. These costs were amortized
       using the straight-line method over five years, and were fully amortized
       at the end of 1999.

       Income taxes
       The Partnership's income is not subject to income taxes under existing
       federal and state tax laws. Partnership income or loss is allocated to
       the partners for income tax purposes.

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






<PAGE>


3.     Property, Plant and Equipment

       Property, plant and equipment consist of the following at December 31,
       2001 and 2000:

                                             2001           2000

Building .............................   $ 3,490,743    $ 3,490,743
Land and land improvements ...........       254,079        228,383
Equipment ............................       404,445        313,445
                                         -----------    -----------
     Total ...........................     4,149,267      4,032,571
Less accumulated depreciation ........    (1,782,473)    (1,505,611)
                                         -----------    -----------

     Net property, plant and equipment   $ 2,366,794    $ 2,526,960
                                         ===========    ===========


4.     Notes Payable

       On August 15, 1999, the Partnership entered into two separate financing
       agreements to purchase equipment. At December 31 the balances on such
       notes are:

                                                         2001        2000

Note payable to financing company in monthly
 installments of $3,190,including interest charged
  at 6.65%, through July 2003 ....................   $  57,378    $  90,632

Note payable to financing company in monthly
 installments of $2,449 including interest charged
  at 4.49%, through July 2002 ....................      16,886       44,820
                                                     ---------    ---------

Total obligations ................................      74,264      135,452
Less current maturities ..........................     (52,421)     (61,189)
                                                     ---------    ---------

Long-term obligations ............................   $  21,843    $  74,263
                                                     =========    =========

Below is a summary of minimum payments due under the Partnership's notes
       payable obligations:

                                Year
                                2002               $52,421
                                2003                21,843
                                                   -------
  Total minimum payments due under notes payable
     including current maturities ..............   $74,264
                                                   =======



<PAGE>


5.     Distributions and Allocation of Partnership Income

       Ridgewood II is entitled to receive annually a preferred distribution of
       available net cash flow from the facility equal to 18% of its investment.
       In the event that in any given year available net cash flow from the
       project does not at least equal the amount of the preferred minimum
       return, the amount of such shortfall is payable on a priority basis out
       of any available net cash flow in subsequent years.

       The Partnership agreement requires income (loss) earned by the
       Partnership to be allocated and distributed to the partners as follows:

          1.    Gross income is allocated as distributions declared have been
                allocated to the partners.
          2.    The difference between distributions declared and net income
                before depreciation and amortization is allocated to the
                partners according to partnership interests.
          3.    Depreciation and amortization expense is allocated to the
                partners proportionally according to their original capital
                contributions to the partnership.

       The Partnership terminates in 2041 unless sooner terminated in accordance
       with the Partnership agreement. During the dissolution or termination of
       the partnership, profits and losses are allocated to the partners
       proportionally according to their original capital contributions to the
       partnership until the amount allocated equals the initial capital
       contributions. Any remaining profits and losses are allocated to the
       partners according to their partnership interests. Distributions are
       allocated proportionally to the partners having positive capital balances
       until those balances are reduced to zero. Distributions are then
       allocated to the partners according to their partnership interests.


6.     Related Party Transactions

       The Partnership's general partner is owned by Ridgewood Power Trust II
       (51% ownership interest) and eco (49% ownership interest). eco has a
       ten-year contract with the Partnership to operate and maintain the
       records for the B-3 Transfer Station, which expires in January 2005. eco
       is 100% owned by Energy Answers Corporation (EAC). This relationship
       resulted in the following transactions with EAC affiliates for the years
       ended December 31, 2001, 2000 and 1999:

                          2001                  2000                1999
                  -------------------- --------------------- -------------------
                  Revenues   Expenses   Revenues  Expenses   Revenues   Expenses
                  Received    Paid To   Received   Paid To   Received    Paid To
                    From                  From                 From
                  --------   --------   --------  --------   --------   --------
100% owned
 subsidiaries
 of EAC .......  $458,593   $357,418   $144,147   $235,699   $  3,464   $221,849
Pittsfield
 Investors
 Limited
 Partnership
 (PILP)eco/
 Pittsfield,
 Inc.is the
 general
 partner of
 PILP and
 is a 100%
 subsidiary
 of EAC .......   107,424     25,019     91,582     21,492     33,624     27,193
Capital
 Compost
 and Waste
 Reduction
 Services, LLC
 60%
 subsidiary
 of EAC in
 2000 and 1999,
 wholly owned
 by EAC in 2001        --     86,118        --      108,021       --       2,133


<PAGE>


6.     Related Party Transactions, Continued

       The contract with eco provides for eco to receive a management fee should
       the Partnership achieve certain profitability and capital return targets.
       No such management fee was earned by or paid to eco for the years ended
       December 31, 2001, 2000 and 1999.

       The Partnership leases equipment from eco on a month-to-month basis for
       $7,439, $6,527 and $3,676 per month, respectively, in 2001, 2000 and
       1999. The amounts due to eco at December 31, 2001, 2000 and 1999
       associated with this lease were $8,584, $0 and $3,676, respectively, and
       are included in related party payable. Rent expense for each of the years
       ended December 31, 2001, 2000 and 1999 associated with this lease was
       $89,272, $78,323 and $44,112.


7.      Concentrations of Credit Risk

       Concentrations of credit risk consists primarily of cash and cash
       equivalents and accounts receivable.

       From time to time, the Partnership has on deposit with certain banks and
       financial institutions, cash and cash equivalents which exceed the amount
       subject to federal insurance. The amount of cash and cash equivalents on
       deposit in excess of FDIC insurance limits was $478,270 and $418,275 at
       December 31, 2001 and 2000. The Partnership attempts to mitigate this
       risk by depositing its cash and cash equivalents with high credit quality
       financial institutions.

       At December 31, 2001, 72% of trade accounts receivables balances were
       from four customers, and in 2000, 61% of the trade accounts receivables
       balances were from four customers.

       Revenues from three customers represented approximately 18%, 16% and 11%
       of operating revenues for the year ended December 31, 2001, 15%; 13% and
       11% of operating revenues for the year ended December 31, 2000 and 17%,
       16% and 16% of operating revenues for the year ended December 31, 1999.


8.     Contingencies

       The Partnership is subject to various requirements including the
       procurement of requisite licenses and permits at the Transfer Station.
       These licenses and permits are subject to periodic renewal. The
       Partnership anticipates that once a license or permit is issued with
       respect to the Transfer Station, the license or permit will be renewed at
       the end of its term if the Transfer Station's operations are in
       compliance with the applicable regulatory requirements. The loss of a
       license or permit would have a material adverse affect on the
       Partnership's operations.