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 0-24240
RIDGEWOOD ELECTRIC POWER TRUST I
(Exact Name of Registrant as Specified in Its Charter)
Delaware 22-3105824
(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 07450-2939
(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 $10,550,000.
Exhibit index is at page 31.
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 I (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 May 9, 1994. It
was organized to acquire all of the assets and to carry on the business of
Ridgewood Energy Electric Power, L.P. (the "Partnership"). The Partnership was a
Delaware limited partnership, which was organized in March 1991 to participate
in the development, construction and operation of independent power generating
facilities ("Projects"). The Partnership raised $10.5 million in a single
private offering conducted in 1991 and early 1992. Substantially all of those
funds were applied prior to 1995 to the purchase of interests in the Projects
described below, to the funding of business ventures that were unsuccessful and
to the paying the fees and expenses of the Partnership's offering and the
Partnership. On June 15, 1994, with the approval of the partners, the
Partnership was combined into the Trust, which acquired all of the Partnership's
assets and which became liable for all of the Partnership's obligations. In
exchange for their interests in the Partnership, the investors in the
Partnership received an equivalent number of Investor Shares (as defined below)
in the Trust. The Partnership was dissolved.
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 May 26, 1994 the Trust notified the Securities and Exchange Commission of
that election and registered its shares of beneficial interest (the "Investor
Shares") under the Securities Exchange Act of 1934, as amended (the "1934 Act").
On July 15, 1994 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, deleting the section of the Declaration requiring
Independent Trustees. Consents were tabulated at the close of business on
December 18, 2001. A total of 105.5 Investor Shares were outstanding and
entitled to be voted. Based on such tabulation, a majority of Investor Shares
consented to such withdrawal and amendments. On January 10, 2002, the Trust
filed with the Securities and Exchange Commission a notification to withdraw its
election to be treated as a "business development company." As a result of such
withdrawal, the Trust now utilizes generally accepted accounting principles for
operating companies.
The Trust is organized similarly to a limited partnership. Ridgewood
Power LLC (the "Managing Shareholder"), a Delaware limited liability company, is
the managing shareholder of the Trust. In general, the Managing Shareholder has
the powers of a general partner of a limited partnership. It has complete
control of the day-to-day operation of the Trust. The Managing Shareholder is
not regularly elected by the Investors.
Ridgewood Energy Holding Corporation ("Ridgewood Holding"), a Delaware
corporation, is the Corporate Trustee of the Trust. The Corporate Trustee acts
on the instructions of the Managing Shareholder and is not authorized to take
independent discretionary action on behalf of the Trust. See Item 10. Directors
and Executive Officers of the Registrant below for a further description of the
management of the Trust.
The following summarizes some of these relationships.
Robert E. Swanson and certain Swanson family trusts own 100% of the
equity of the following entities:
o Ridgewood Securities Corporation ("Ridgewood Securities")- Placement Agent;
o Ridgewood Power Management, LLC ("RPM") - Operates certain of
the Projects owned by the Trust and six other trusts organized
by the Managing Shareholder;
o Ridgewood Power LLC ("Ridgewood Power")- Managing Shareholder of the Trust
and six other trusts;
o Ridgewood Energy Holding Corporation - Corporate Trustee for
the Trust and six other trusts; and
o Ridgewood Capital Management LLC ("Ridgewood Capital") - marketing affiliate
and manager of seven venture capital funds.
Mr. Swanson has sole voting and investment power over the Swanson family trusts
and is the sole manager and chief executive officer of the above entities.
In addition, the Trust is affiliated with the following trusts
(collectively "Other Power Trusts"), which have been organized by the Managing
Shareholder:
o Ridgewood Electric Power Trust II ("Power II");
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: independent electric power
generation.
(c) Narrative Description of Business.
(1) General Description.
The Trust was formed to participate in the development, construction
and operation of independent electric power projects. These Projects are
Qualifying Facilities or "QFs." Historically, producers of electric power in the
United States consisted of regulated utilities serving end-use retail customers
and certain industrial users that produced electricity to satisfy their own
needs. The independent power industry in the United States was created by
federal legislation passed in response to the energy crises of the 1970s. The
Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), among
other things, requires utilities to purchase electric power from QFs, including
"cogeneration facilities" and "small power producers," and also exempts these
QFs from most federal and state utility regulatory requirements. In addition,
the price paid by electric utilities under PURPA for electricity produced by QFs
is the utility's avoided cost of producing electricity (i.e., the incremental
costs the utility would otherwise face to generate electricity itself or
purchase electricity from another source). Pursuant to PURPA, and state
implementation of PURPA, many electric utilities have entered into long-term
Power Contracts with rates set by contract formula approved by state regulatory
commissions. Although one of the benefits of PURPA is the requirement imposed
upon electric utilities to purchase QF electric power, there are nonetheless
some QFs that do not have Power Contracts with electric utilities because, among
other reasons, such electric utilities take the view that state implementation
of PURPA no longer requires such purchase of QF power. As explained below,
Southern California Edison Company ("SCE") has taken such a position, which is
being legally challenged by several QFs.
(2) Projects.
(i) Brea Project. In October 1994, the Trust purchased, for $3.1
million, an equity interest in Brea Power Partners, L.P., a partnership, which
owns and operates a 5-megawatt capacity electric generating facility fueled by
methane and other burnable gases created by the decomposing of garbage in a
landfill (the "Brea Project"). If not used for fuel, those gases would escape to
the atmosphere. Methane is a potent "greenhouse gas" that increases global
warming by significantly more than the carbon dioxide and water vapor produced
when it is burned.
On June 1, 1997, the Trust, through subsidiaries, acquired the general
partnership interest and the limited partnership interest owned by GSF Energy,
LLC, an indirect subsidiary of DQE Corporation ("DQE"), for a base price of
$3,000,000, and thus acquired the entire beneficial interest in the Brea Power
Partners, L.P. Until June of 1997, an affiliate of DQE operated the Brea Project
under an operations and maintenance agreement. The operations and maintenance
agreement was terminated in June 1997 and RPM, an affiliate of the Trust's
Managing Shareholder, began operating and continues to operate the Brea Project.
RPM is reimbursed by the Trust for its actual costs incurred and allocable
overhead expenses but is not otherwise compensated.
The Brea Project is a QF. Electricity generated by the Brea Project,
over and above its own requirements, is sold to SCE under a long-term power
sales contract (a "Power Contract"). The energy price under the Power Contract
is the higher of 5.8 cents per kilowatt-hour or SCE's avoided cost, which is an
amount determined by a contract formula set forth in the Power Contract.
Generally, QFs are paid avoided cost, which is computed under a contract formula
prescribed by the California Public Utility Commission ("CPUC") consisting of a
fixed payment for capacity and a payment per unit of energy delivered to the
utility.
The Power Contract may be terminated by either party no earlier than
the end of 2004 on 5 years' advance notice. On March 23, 2000, SCE provided such
written notice to the Brea Project notifying the Brea Project it was electing to
terminate the Power Contract as of March 23, 2005. After such termination, the
Brea Project will have to sell its electric output in the competitive electric
power market and there is no assurance that it will be able to do so at a
profit.
The Trust's purchase of the Brea Project in 1994 did not include the
landfill gas collection system. Currently, GSF sells landfill gas to the Brea
Project pursuant to a Landfill Gas Purchase Agreement ("Gas Agreement"). The
price paid by the Brea Project includes both a price per MMBTu for landfill gas
delivered and a fixed annual payment. The Gas Agreement expires on the later of
December 31, 2004 or the expiration of the Power Contract with SCE. The landfill
gas is produced from a landfill owned by the County of Orange, California and is
collected and sold by GSF under a gas lease agreement between GSF and the County
of Orange. As described below, in 2001 RPM renegotiated the Gas Agreement with
GSF and entered into, on behalf of both the Brea Project and the Olinda Project,
an Amended and Restated Gas Sale and Purchase Agreement, which becomes effective
and replaces the Gas Agreement on the date that the Olinda Project is
commercially operable and capable of selling electric power.
Congress has created tax credits as an incentive for selling landfill
gas (with numerous exceptions and phase-outs). The tax credit applicable to the
landfill gas sold by GSF currently expires on December 31, 2002, although
Congress is currently debating an extension of this and other similar tax
credits. The credit can only be obtained, however, by a seller of landfill gas
to an unaffiliated generating facility. Accordingly, neither the Trust nor its
Investors are entitled to any tax credit for landfill gas. If the tax credit is
not extended or another tax or subsidy incentive is not substituted for it, GSF
may not be able to operate the gas collection system under the existing
arrangements and the cost of landfill gas fuel to the Project may increase.
However, GSF has generally complied with its obligations under the Gas Agreement
and the Trust has no indication or evidence that such compliance will not
continue throughout the term of the SCE Power Contract.
On January 16, 2001, SCE sent the QFs under contract with it, including
the Brea Project, a letter stating that it was temporarily suspending payments
to QFs. SCE was at that time experiencing severe financial problems due to the
California electric energy crisis and decided to conserve cash by suspending
payments to QFs and other creditors. SCE did not pay the Brea Project for energy
and capacity delivered to SCE for the months of November and December 2000, and
January and February 2001. SCE issued public statements at that time indicating
that it would be unable to pay QFs, as well as other suppliers and creditors,
for the foreseeable future.
As a result, on or about April 9, 2001, the Brea Project filed a
lawsuit in California state court against SCE asserting, among other things,
breach of contract for its failure to pay for electric energy and capacity
already delivered pursuant to the Power Contract. The Brea Project was not alone
in filing a lawsuit against SCE and many QFs filed similar lawsuits against SCE.
All of the QF lawsuits, including the Brea Project's, were eventually
consolidated into one case and were subject to a motion to dismiss filed by SCE.
SCE claimed that the CPUC had subject matter jurisdiction over the matters
raised in the QF lawsuits and, as a result, the cases should have been filed
with and brought before the CPUC. On September 13, 2001, the California state
court agreed with SCE and dismissed all of the QF lawsuits, including the Brea
Project's, without prejudice claiming that the matter indeed should be filed
before the CPUC. However, as explained below, long before the California state
court considered and decided the matter, the Brea Project was no longer
economically interested in the progress or outcome of its lawsuit and remained a
party to the consolidated case primarily for administrative and informational
purposes.
In April of 2001, the Brea Project entered into agreements with AMROC
Investment, LLC ("AMROC") to sell to AMROC the Brea Project's rights to the
outstanding SCE accounts receivable. AMROC simply acted as the Brea Project's
counterparty and was an intermediary for the ultimate purchaser of the accounts
receivable, who entered into purchase agreements for such receivables with
AMROC. The Brea Project sold its accounts receivable at a discount but did so at
time when SCE was not in a position to pay, was publicly indicating that it was
possible that it would never be able to pay, and was very likely to declare
bankruptcy. As indicated, the Brea Project had not been paid for the electric
energy and capacity delivered during the period of November 2000 through March
2001 and, although it had shut down operations soon thereafter due to SCE
failure to pay, was nonetheless incurring substantial expenses. Selling the
accounts receivable provided the Brea Project with available cash to pay
outstanding and current expenses and shifted the risk of SCE's failure to pay
and possible bankruptcy to a third party. As a result of such sale, the Brea
Project did not aggressively pursue the litigation against SCE described above.
Additionally, on July 16, 2001, the Brea Project entered into an
"Agreement Addressing Renewable Energy Pricing and Payment Issues" ("Renewable
Agreement") with SCE. The Renewable Agreement essentially was a form agreement
that SCE had obtained approval from the CPUC to present to and execute with
certain of the QFs it had under contract. The Renewable Agreement, generally,
required a QF to agree to a stay of any existing litigation it was prosecuting
against SCE or, alternatively, agree not to bring such litigation, and agree to
a fixed energy price for a term of five (5) years. In exchange, SCE confirmed
the outstanding balance it owed to a QF, agreed to pay ten (10%) percent of the
outstanding balance upon execution, to pay ongoing interest, and then pay the
remaining balance upon the occurrence of certain events, primarily the enactment
of legislation designed to make SCE creditworthy. The Brea Project executed a
form of the Renewable Agreement that did not include a fixed energy price, since
the energy price contained in the Brea Power Contract with SCE was higher than
that offered in the Renewable Agreement. Since the Brea Project no longer owned
the outstanding balance, it sought and received approval from AMROC to execute
the Renewable Agreement.
During the later part of 2001, SCE tried to avoid its obligations under
these Renewable Agreements by asserting that the CPUC, as opposed to the
California Legislature, adopted a plan that would allow SCE to remain
creditworthy and therefore, since the legislature did not enact legislation,
there was no obligation to comply with the Renewable Agreements. SCE's argument
was essentially form over substance and after substantial discussion with QFs
that had executed the Renewable Agreement, and threatened litigation if SCE did
not comply with its obligations thereunder, SCE drafted an amendment to the
Renewable Agreement that, essentially, adopts new payment terms to accommodate
the actual solution and timing to SCE's financial problems reached with the
CPUC. The Brea Project received approval from AMROC to execute the amendment.
SCER has since paid the outstanding balance it owed to the Brea Project for the
energy and capacity the Brea Project delivered during the period November 2000
through March 2001. As required by the Brea Project's agreement with AMROC, such
amounts were forwarded by the Brea Project to AMROC.
(ii) Olinda Project. In early 2001, the Trust decided to expand its
operations at the Orange County Landfill where the Brea Project is located, by
developing and installing a 2.5-megawatt electric generating facility fueled by
methane gas (the "Olinda Project"). The total cost of the Olinda Project is
expected to be $3,000,000, half of which has been financed. The Olinda Project
was designed and built by Stewart & Stevenson, an engineering and construction
firm, for a cost of approximately $2,500,000. The Olinda Project has yet to pay
Stewart & Stevenson in full for its services and is awaiting the results of the
start-up and testing of the facility before paying the outstanding balance to
Stewart & Stevenson. The Olinda Project is a QF but does not have a Power
Contract with SCE or other electric utility. The Olinda Project attempted to
obtain a Power Contract with SCE but was informed by SCE that pursuant to SCE's
interpretation of a CPUC order, they no longer have an obligation to purchase
electric power from new QFs. The Olinda Project and the Trust believe that this
is a violation of PURPA and indeed several other QFs that have been rebuffed by
SCE have instituted legal action against SCE. The Olinda Project is nonetheless
following the lawsuit as it proceeds in the California courts.
In March 2002, the Olinda Project entered into a ninety-day power sales
contract with the California Power Authority. The Olinda Project and the
California Power Authority are in the process of negotiating a longer term
contract.
Landfill Gas to be used by the Olinda Project is being supplied by GSF,
the supplier of landfill gas to the Brea Project. Once the Olinda Project is
commercial and capable of selling its electric power, the current Gas Agreement
is terminated and the Amended and Restated Gas Sale and Purchase Agreement
("Amended Agreement") with GSF becomes effective. Pursuant to the Amended
Agreement, RPM, on behalf of the Brea Project and Olinda Project, is effectively
entitled to purchase all of the landfill gas generated and produced by the
landfill and collected by GSF. Thus, the Trust has contractual rights to all
landfill gas, which is sufficient to fuel further expansion of either or both
the Brea or the Olinda Projects. In addition, the term of the Amended Agreement,
and thus, the right to all such landfill gas, extends to the year 2018.
(iii) Stillwater Project. In October 1991, the Trust acquired a 32.5%
equity interest with respect to a 3.5 megawatt (nominal capacity) hydroelectric
facility which was then under construction on the Hudson River in the village of
Stillwater, New York (approximately 30 miles northeast of Albany) at the site of
a pre-existing 800 foot wide masonry dam structure (the "Stillwater Project")
for a purchase price of $750,000. The Stillwater Project commenced commercial
operation in May 1993.
The Trust and affiliates of the general contractor and affiliates of
the equipment supplier formed Stillwater Hydro Partners, L.P. ("SHP") to
continue development of the Stillwater Project. The Trust's total investment was
$1,162,000. Debt financing for the Project was provided by the CIT Group/Capital
Equipment Financing Inc. ("CIT"). The CIT financing is a fixed rate 15-year term
loan in the principal amount of approximately $8,995,000, with the final payment
due in 2009. In addition to the fixed interest payments, CIT is also entitled to
receive, as additional interest, 22.5% of the available cash flow of the
Stillwater Project. The term loan is payable only by SHP, and is non-recourse to
the Trust.
The Trust now owns a fixed preferred partnership interest entitling it
to aggregate distributions of $1 million, plus a compound annual return of 12%
thereon until paid in full. Over the nine-year schedule of annual payments, the
Trust was to receive total payments, including the annual return, of
approximately $1,720,000. SHP is required to apply substantially all of SHP's
available cash flow after funding of debt service (up to a maximum amount each
year) to satisfy the payment obligation to the Trust, with any shortfalls to be
carried forward with interest into subsequent years.
The Stillwater Project's revenues are dependent upon water levels in
the Hudson River, which have fluctuated significantly during the last several
years. During low flow periods, generation is curtailed. For a variety of
reasons, power output during high flow periods has not reached projected levels.
In addition, even if water flow levels are optimal, the Project is unable to
generate the full projected output of 3.5 megawatts of electricity because of a
design defect. As a result, the Trust has only received a single partial payment
of $126,000 in 1994 and does not expect to receive any additional payments for
several years.
Electricity generated by the Stillwater Project is sold to Niagara
Mohawk Power Corporation under a long-term Power Contract which expires in 2028.
(iv) Lynchburg Project. The Trust owned RW Power Partners, L.P. which
made an approximately $3.9 million equity investment (including without
limitation construction costs and cash advances) in a 3 megawatt electrical
generating facility that was constructed in an industrial park near South
Boston, Virginia (the "Lynchburg Project" also known as the "South Boston
Project"). The Trust shut down the Lynchburg Project in January 1997 and sold it
to an unaffiliated third party in December 1997 for a $700,000 promissory note
secured by the Project property and the right to receive 2% of any future gross
revenues from the Project. The buyer of the Lynchburg Project was unable to
operate it successfully and closed it in August 1999. The Trust wrote off the
mortgage as being uncollectible effective December 31, 1999.
(v) Mobile Power Units. Effective August 1999, the Trust purchased two
mobile electric generating units manufactured by Caterpillar Inc. (the "Units").
The Units combine a large diesel engine with a fuel tank, emission equipment, an
electric generator and control equipment on a single skid and therefore can be
moved to remote areas as a self-contained power plant. The owner of the Units is
Ridgewood Mobile Power I, LLC, a wholly-owned subsidiary of the Trust. The Trust
bought the Units from Hawthorne Power Systems, Inc. ("Hawthorne") of San Diego,
California (a Caterpillar distributor). Hawthorne added the Units to its own
rental fleet of similar equipment and rents them to contractors, engineering
firms and other industrial or commercial customers who need emergency, temporary
or peak power supplies. The Trust receives 80% of the net rental revenues and is
responsible for major maintenance; Hawthorne receives 20% of the net rental
revenues to compensate it for marketing and managing the Units.
The Units are managed by Hawthorne and rented at fixed rates. Their
major costs are capital recovery, maintenance, taxes and storage costs;
operating costs are borne by the customer. Electricity generated from the Units
is generally used by the renter on-site. If there were a shortage of electric
generation capacity, the Units could be rented as additional peak generation
capacity by a utility or electricity seller, subject to local environmental
limitations. The Units are rented at fixed prices per month and are operated by
the renter. Rental periods typically range from one to six weeks.
Additional information regarding the Projects is found in the Notes to
the Consolidated Financial Statements.
(3) Project Management and Operation
The Managing Shareholder has organized RPM to provide operating
management for the Projects, and has assigned day-to-day management of the Brea
Project and Olinda Project to RPM. These services are charged to the Projects at
RPM's cost. See Item 10 - Directors and Executive Officers of the Registrant and
Item 13 Certain Relationships and Related Party Transactions for further
information regarding the Operation Agreement and RPM and for the cost
reimbursements received by RPM. The Stillwater Project is managed by its
remaining equity partners. Hawthorne manages the Mobile Power Units.
Customers that accounted for more than 10% of the consolidated revenue
to the Trust in each of the last three fiscal years are:
Calendar Year
2001 2000 1999
Southern California Edison 94.6% 94.6% 97.6%
(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 Brea Project and Olinda Project are located, the year
began with the state experiencing severe electricity shortages. Such shortages
were due to a variety of factors including, but not limited to, seriously flawed
electric deregulation legislation and implementation, explosive growth in
California's electric consumption, the failure of the state to add significant
electric generation during the last decade, very strict environmental
regulations, electric transmission constraints, natural gas shortages, and the
lack of available electric supply from other areas of the western United States.
As a result, California, particularly San Francisco, experienced rolling
blackouts, high wholesale electric prices, and subsequently, retail electric
rates soared, and the California investor owned electric utilities ("IOUs")
experienced severe and critical cash shortages due, in large part, to the fact
that for 2000 and part of 2001 IOU rates to retail consumers were frozen such
that increased wholesale prices could not be passed on to consumers. Pacific Gas
and Electric Company ("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 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 electric 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 electric crisis are varied and complex and
therefore such assertions are typical political rhetoric, although
investigations at various levels of government still continue. Nonetheless,
despite such rhetoric, the legislators and regulators did respond rather rapidly
to the electric crisis. For example, the Federal Energy Regulatory 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, through the
California Department of Water Resources ("DWR"), to purchase power on behalf of
the IOUs and to enter into long-term power contracts 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 new electric generation. There were estimates that an
additional 50,000 megawatts 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 no doubt that such
crisis accelerated purchasing and proposed construction of power plants by
independent power producers.
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, an extremely mild summer in California, an increase in electric
conservation and a decrease in natural gas prices, which fuels an overwhelming
majority of the power plants in California. Current prices in the CAISO market
are approximately $.030/kWh for on-peak power, which is less than it would cost
to operate the Olinda Project. However, the Olinda Project is an environmentally
friendly renewable energy source and California has made a commitment to
purchase significant amounts of renewable energy.
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. As a result, it has been
negotiating, on behalf of the DWR, for the purchase of such renewable resources.
The Olinda Project has entered into a 90-day power sales agreement with the CPA
and is currently engaged in negotiations with the CPA for a long-term power
sales contract. However, there is no guarantee that such a contract will be
negotiated and executed. In such event, and at current California wholesale
electric prices, it would be difficult for the Olinda Project to sell its
electric output in the market.
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
decisions by IPPs 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 general
U.S. economic downturn, there is a possibility that should the economy rebound,
gas prices increase, conservation decrease and demand increase, shortages
nationwide could result. While such shortages could create social and political
problems for entities that own and operate electric generation facilities, such
as the Trust, electric shortages generally equate to higher wholesale electric
prices and a favorable market within which to sell electric energy.
In conclusion, the trend in the industry, as a result of the matters
detailed above, 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 impact less upon
the Brea Project, which currently has a Power Contract with SCE, as opposed to
the Olinda Project, which, unless it contracts with the CPA, will be subject to
selling its power, to the extent it can, in the general electric market. The
Trust has no direct exposure to Enron. The Trust's indirect exposure to Enron
cannot yet be determined.
(5) Competition
The Brea and Stillwater Projects, as described above, are not currently
subject to competition because those Projects have entered into long-term Power
Contracts to sell their output at specified prices. The Olinda Project, however,
does not have a current long-term Power Contract and is subject to market
competition. The Brea and Stillwater Projects, likewise, would be subject to
future competition to market its electricity output if its Power Contract
expires or is terminated. Given the current environment in California regarding
electric power and generation and the current low wholesale electric rates, as
described above, the Trust believes that, if subjected to competition in the
very near future, the Brea Project could face difficulty competing and selling
its energy and capacity profitably. However, as further detailed in Item
1(c)(4), the recent bankruptcy of Enron Corp., as well as the low electric
rates, have prompted many electric generators to cancel plans to construct and
install new electric generation. As a result, there may very well be a shortage
of generation capacity in the foreseeable future. If this were to occur, the
Brea Project, as well as the Olinda Project, would be in a position to sell its
energy and capacity at favorable rates, although such favorable rates can not be
assured due to certain other uncertainties. The process of deregulation in New
York, where the Stillwater Project is located, is still uncertain and it is
difficult to estimate the level of marketing competition that it would face in
any such event.
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 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 Units compete against numerous other fleets of mobile power
generation equipment on a regional and international level. To some extent,
local or governmental electricity utilities also compete to provide short-term
electricity in less-remote areas. Hawthorne owns many units in its rental fleet
but has agreed to market the Trust's Units on a basis at least as favorable at
it does for its own equipment. Demand for the Units is heavily dependent on the
level of construction and civil engineering work in the Southern California area
and on the availability of equipment from vendors, other area rental fleets and,
to a limited extent, from outside-of-area fleets. Demand can be very volatile.
Further, Hawthorne may cancel the rental arrangement on short notice.
6. Regulatory Matters.
The Projects are subject to energy and environmental laws and
regulations at the federal, state and local levels in connection with
development, ownership, operation, geographical location, zoning and land use of
a Project and emissions and other substances produced by a Project. These energy
and environmental laws and regulations generally require that a wide variety of
permits and other approvals be obtained before the commencement of construction
or operation of an energy-producing facility and that the facility then operate
in compliance with such permits and approvals.
(i) Energy Regulation.
(A) PURPA. The enactment in 1978 of PURPA and the adoption of
regulations thereunder by FERC provided incentives for the development of QFs
meeting certain criteria. QFs are generally exempt from the provisions of the
Public Utility Holding Company Act of 1935, as amended, the Federal Power Act,
as amended, 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 QF 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 Energy Act has resulted
and may continue to 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) State Regulation. The Trust's Projects are not subject to material
state economic regulation except for requirements in California and New York to
supply the purchasing utility with information to confirm compliance with QF
fuel use and efficiency requirements and to make the Projects available for
audit and inspection to confirm QF compliance. The Trust believes that its
Projects meet QF standards. States also have authority to regulate certain
environmental, health and siting aspects of QFs.
(E) Mobile Power Units. The Mobile Power Units, as temporary on-site
units operated by the electricity consumer, are not subject to economic
regulation in California or most other jurisdictions. If a Unit were rented by
a regulated utility, that utility might be subject to economic regulation but
the rental fee for the Unit would probably not be directly regulated. There
might be an indirect regulatory effect to the extent that the utility was
regulated as to the rental price it would be authorized to pay. Under current
conditions in California, this is unlikely.
(ii) Environmental Regulation.
The operation of Independent Power Projects is subject to extensive
federal, state and local environmental laws and regulations. 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 also include wetlands preservation, fisheries protection (at the
Stillwater Project) and noise regulation. These laws and regulations in many
cases require a lengthy and complex process of renewing or obtaining licenses,
permits and approvals from federal, state and local agencies. Obtaining
necessary approvals regarding the discharge of emissions into the air is
critical to 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 that do not require large discharges of
coolant except for periodic flushing to local sewer systems under permit and do
not make other material discharges.
The Trust's Projects are subject to and comply with 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 Mobile Power Units, which do not have a fixed location, are subject
to differing air quality standards that depend in part on the locations of use,
the amount of time and time periods of use and the quantity of pollutants
emitted. The Trust believes that the Units as used comply with all applicable
air quality rules.
The Managing Shareholder expects that environmental and land use
regulations may become more stringent or, at a minimum, remain constant. 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 co-owners of the Stillwater Project and as to all Projects
on 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, New York and
Virginia and has no foreign operations.
(e) Employees.
The employees of the Brea Project and the Olinda Project are employed
by RPM, the Trust is administered by the Managing Shareholder 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.
The following table shows the material properties (relating to Projects)
owned or leased by the Trust's subsidiaries or partnerships in which the Trust
has an interest. All of the Projects are described in further detail at Item
1(c)(2).
Est.Amount Approximate
of Land Square
Project Location Land (acreage) Footage
Brea Brea, CA Leased 2 6,000
Olinda Brea, CA Leased 2,000
Still Stillwater, Leased .75 N/A
Water NY and
Licensed
Item 3. Legal Proceedings.
On January 16, 2001, SCE sent the QFs under contract with it, including
the Brea Project, a letter informing them that it was temporarily suspending
payments to QFs. SCE was at that time experiencing severe financial problems due
to the California electric energy crisis and decided to conserve cash by
suspending payments. SCE did not pay the Brea Project for energy and capacity
delivered to SCE for the months of November and December 2000 and January and
February 2001. SCE issued public statements at that time indicating that it
would be unable to pay QFs, as well as other suppliers and creditors, for the
foreseeable future.
As a result, on or about April 9, 2001, the Brea Project filed a
lawsuit against SCE asserting, among other things, breach of contract for its
failure to pay for electric energy already delivered pursuant to the Power
Contract. The Brea Project was not alone in filing such lawsuits and eventually
over 25 QFs filed similar lawsuits against SCE. All of the QF lawsuit were
eventually consolidated into one case and were subject to a motion to dismiss
filed by SCE. SCE claimed that the California Public Utilities Commission
("CPUC") had subject matter jurisdiction over the mater raised in the QF
complaints and. As a result, the matter should have been brought before the
CPUC. On September 13, 2001, the California Court agreed with SCE and dismissed
all of the QF lawsuits, including the Brea Project's, without prejudice claiming
that the matter indeed should be filed before the CPUC.
Item 4. Submission of Matters to a Vote of Security Holders.
On November 5, 2001, the Trust issued to the Investors a "Notice of
Solicitation of Consents," in which the Trust sought the consent of the
Investors to withdraw its election to be treated as a "business development
company" under the 1940 Act and to make certain amendments to the Trust's
Declaration as a result of such withdrawal, including, but not limited to,
deleting the section of the Declaration requiring Independent Trustees. Consents
were tabulated at the close of business on December 18, 2001. A total of 105.5
Investor Shares were outstanding and entitled to be voted. Based on such
tabulation, a majority of Investor Shares consented to such withdrawal and
amendments. On January 10, 2002, the Trust filed with the Securities and
Exchange Commission a notification to withdraw its election to be treated as a
"business development company."
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
(a) Market Information.
The Trust has 105.5 Investor Shares. There is currently no established
public trading market for the Investor Shares. As of the date of this Form 10-K,
all such Investor Shares have been issued and are outstanding. There are no
outstanding options or warrants to purchase, or securities convertible into,
Investor Shares.
Investor Shares are restricted as to transferability under the
Declaration. In addition, under federal laws regulating securities the Investor
Shares have restrictions on transferability when they 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 registered under the Securities Act of 1933, as
amended (the "1933 Act"), or under any other similar law of any state (except
for certain registrations that do not permit free resale) in reliance upon what
the Trust believes to be exemptions from the registration requirements contained
therein. Because the Investor Shares have not been registered, they are
"restricted securities" as defined in Rule 144 under the 1933 Act.
The Managing Shareholder has investigated the possibility and
feasibility of a combination of the Trust and the Other Power Trusts into a
publicly traded entity. This would require the approval of the Investors in the
Trust and the Other Power Trusts 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, is very lengthy. There is no
assurance that the Managing Shareholder will recommend a combination, that the
Investors of the Trust or Other Power Trusts 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 223 holders of record 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 $ -- $1,477,793
Distributions per Investor Share -- 14,008
Total distributions to
Managing Shareholder -- 14,927
The Managing Shareholder discontinued quarterly distributions effective
January 1, 2001. The Trust's decision whether to make future distributions to
Investors and their timing will depend on, among other things, the net cash flow
of the Trust and retention of reasonable reserves as determined by the Trust to
cover its anticipated expenses. See Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operation.
Occasionally, distributions may include funds derived from the release
of cash from operating or debt services 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 than 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 $4,379,154 $3,259,562 $3,114,503 $3,158,596 $3,158,599
Net income 1,454,876 1,487,998 799,717 1,685,035 1,270,392
(A) (B)
Net assets
(shareholders'
equity) 7,773,229 6,318,353 6,323,075 6,834,120 6,149,545
Investments in
Plant and
Equipment (net
of depreciation)4,922,297 2,688,320 2,920,044 2,401,543 2,642,498
Investment
in Power
Contract(net
of amortization) 788,489 1,103,887 1,419,284 1,734,682 2,036,064
Total assets 9,386,999 6,507,720 6,543,322 6,925,985 7,568,059
Long-term
obligations 1,227,674 -- -- -- --
Per Share:
Revenues 41,509 30,896 29,521 29,939 29,939
Net income 13,790 14,104 7,580 15,971 12,042
(A) (B)
Net asset value 73,679 59,890 59,934 64,778 58,290
Distributions
to Investors -- 6,701 7,096 6,894 3,517
(A) Includes writedown of investment of $422,019 ($4,000 per Investor Share).
(B) Includes writedown of investment of $400,000 ($3,791 per Investor Share).
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operation.
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 Brea and Stillwater Projects are QFs under PURPA and currently sell their
electric output to utilities under long-term Power Contracts expiring in 2005
and 2029, respectively. During the term of the Power Contracts, the utilities
may or may not attempt to buy out the contracts prior to expiration. At the end
of the Power Contracts, the Projects will become merchant plants and may be able
to sell the electric output at then current market prices. There can be no
assurance that future market prices will be sufficient to allow the Trust's
Projects to operate profitably.
All available cash flow from the Stillwater Project is being used to meet debt
service requirements. Distributions to the Trust will resume after repayment of
the bonds. Assuming normal water flows and no operational failures, the bonds
are expected to be repaid in 2008.
Additional trends affecting the independent power industry generally are
described at Item 1(c)(4).
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 5 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 increased $1,119,000, or 34%, to $4,379,000 in 2001 from
$3,260,000 in 2000. The increase in revenues is due primarily to higher energy
prices received from the Brea Project, which receives a rate equal to the higher
of the contract price or market price (as defined). During part of 2001, market
prices were higher than the contract price. Revenues in 2001 from the
Caterpillar rental modules were consistent with 2000 revenues.
Gross profit, which represents total revenues reduced by cost of sales,
increased $518,000, or 27%, to $2,450,000 in 2001 from $1,932,000 in 2000. The
increase in gross profit reflects the higher revenues in 2001 compared to 2000,
partially offset by higher maintenance costs at the Brea Project.
General and administrative expenses increased $325,000, or 76%, to $753,000 in
2001 from $428,000 in 2000. The increase primarily reflects an increase in
charges associated with the sale of the Brea Project's SCE receivables to AMROC
(which increased $146,000 from $334,000 in 2000 to $480,000 in 2001) as well as
legal costs associated with the Brea Project's dispute with SCE (which increased
$158,000 from 2000 to 2001).
The management fee paid to the Managing Shareholder increased $17,000, or 24%,
to $87,000 in 2001 from $70,000 in 2000 which reflects the higher net assets of
the Trust.
Income from operations increased $176,000, or 12%, to $1,610,000 in 2001 from
$1,434,000 in 2000 which reflects the increased revenues of the Trust, partially
offset by the increased expenses.
Other income (expense), net, changed from income of $54,000 in 2000 to an
expense of $155,000 in 2001, a change of $209,000. The change was primarily
related to the costs incurred in issuing the "Notice of Solicitation of
Consents." In addition, the Trust recorded an equity loss from its investment in
Stillwater of $29,000 in 2001 compared to income of $12,000 in 2000 reflecting
lower revenues due to reduced river flows.
Net income decreased $33,000, or 2%, to $1,455,000 in 2001 from $1,488,000 in
2000, reflecting the increased revenues of the Trust, which was more than offset
by increase operating and other expenses.
The year ended December 31, 2000 compared to the year ended December 31, 1999.
Total revenues increased $145,000, or 5%, to $3,260,000 in 2000 from $3,115,000
in 1999. The increase in revenues is due primarily to higher rental revenues
from the Caterpillar rental modules which were acquired in August 1999.
Gross profit, which represents total revenues reduced by cost of sales,
increased $575,000, or 42%, to $1,932,000 in 2000 from $1,357,000 in 1999. The
increase in gross profit primarily reflects lower maintenance costs at the Brea
Project, as well as the increased revenue from the Caterpillar rental modules.
General and administrative expenses increased $373,000, or 678%, to $428,000 in
2000 from $55,000 in 1999. The increase primarily reflects the $334,000
provision for doubtful accounts recorded on receivables due from SCE.
The management fee paid to the Managing Shareholder decreased $6,000, or 8%, to
$70,000 in 2000 from $76,000 in 1999 which reflects the lower net assets of the
Trust. In 1999, the Trust recorded a writedown of $422,000 relating to its
investment in the Lynchburg Project, which had ceased operations in that year.
Income from operations increased $630,000, or 78%, to $1,434,000 in 2000 from
$804,000 in 1999 which reflects the increased gross profit from the Brea Project
and Caterpillar rental modules and the absence of the 1999 writedown of the
Lynchburg Project.
Other income (expense), net, changed from a loss of $4,000 in 1999 to income of
$54,000 in 2000, a change of $58,000. The change was primarily related to
improved results from the Trust's equity investment in Stillwater, which
resulted in income of $12,000 in 2000 compared to a loss of $30,000 in 1999
reflecting higher revenues due to improved river flows.
Net income increased $688,000, or 86%, to $1,488,000 in 2000 from $800,000 in
1999, reflecting the increased income from the Brea Project and Caterpillar
rental modules and the absence of the 1999 writedown of the Lynchburg Project.
Liquidity and Capital Resources
In 2001 and 2000, the Trust's operating activities generated $2,127,000 and
$2,063,0000 of cash, respectively.
Cash used in investing activities in 2001 of $2,471,000 is due to capital
expenditures relating to the Olinda Project expansion.
Cash provided by financing activities of $1,480,000 in 2001 represents the
long-term project financing the Trust received for the Olinda Project expansion.
Cash used in financing activities in 2000 of $1,493,000 represented
distributions to shareholders. The Trust temporarily ceased making distributions
to shareholders in the first quarter of 2001.
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 $1,480,000 of long-term debt
related to the Brea expansion which is guaranteed by the Trust. Scheduled
principal payments of the long-term debt are as follows:
2002 $253,000
2003 275,000
2004 300,000
2005 327,000
2006 325,000
The Brea project has certain long-term obligations relating to its Power
Contract with SCE and its Gas Agreement with GSF. 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
2002
(U.S. $)
Bank Deposits and Certificates of Deposit $ 2,848,000
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
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. Ridgewood Power LLC is now also their managing
shareholder. The business objectives of these 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 (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, an NASD member, which has been the placement agent
for the private placement offerings of the seven trusts sponsored by the
Managing Shareholder and the funds sponsored by Ridgewood Capital, which assists
in offerings made by the Managing Shareholder and which is the sponsor of
privately offered venture capital funds; and RPM. Each of these companies is
controlled by Robert E. Swanson, who is their sole director or manager.
Set forth below is certain information concerning Mr. Swanson and other
executive officers of the Managing Shareholder.
Robert E. Swanson, age 55, has also served as President of the Trust
since its inception in 1991 and as President of RPM, the Other Power Trusts,
since their respective inceptions. Mr. Swanson has been President and registered
principal of Ridgewood Securities and became the Chairman of the Board of
Ridgewood Capital on its organization in 1998. He also is Chairman of the Board
of the Ridgewood Capital Venture Partners I, II, III and IV venture capital
funds ("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,
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 Other
Power Trusts since April 2000. Before that, he had assumed the duties of Chief
Financial Officer of Ridgewood Power in November 1996 under a consulting
arrangement. In April 1997, he became a Senior Vice President and Chief
Financial Officer of Ridgewood Power.
Mr. Quinn has over 30 years of experience in financial management and
corporate mergers and acquisitions, gained with major, publicly traded companies
and an international accounting firm. He formerly served as Vice President of
Finance and Chief Financial Officer of NORSTAR Energy, an energy services
company, from February 1994 until June 1996. From 1991 to March 1993, Mr. Quinn
was employed by Brown-Forman Corporation, a diversified consumer products
company and distiller, where he was Vice President-Corporate Development. From
1981 to 1991, Mr. Quinn held various officer-level positions with NERCO, Inc., a
mining and natural resource company, including Vice President- Controller and
Chief Accounting Officer for his last six years and Vice President-Corporate
Development. Mr. Quinn's professional qualifications include his certified
public accountant qualification in New York State, membership in the American
Institute of Certified Public Accountants, six years of experience with the
international accounting firm of PricewaterhouseCoopers,LLP and a Bachelor of
Science degree in Accounting and Finance from the University of Scranton (1969).
Daniel V. Gulino, age 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 Pennsylvannia
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, Other Power Trusts since their
respective inceptions. She has also served as Vice President of Ridgewood Energy
since October 1984, when she joined the firm. Her primary areas of
responsibility are investor relations, communications and administration. Prior
to her employment at Ridgewood Energy, Ms. Olin was a Regional Administrator at
McGraw-Hill Training Systems where she was employed for two years. Prior to
that, she was employed by RCA Corporation. Ms. Olin has a Bachelor of Arts
degree from Queens College.
(c) Management Agreement.
The Trust has entered into a Management Agreement with the Managing
Shareholder, detailing how the Managing Shareholder will render management,
administrative and investment advisory services to the Trust. Specifically, the
Managing Shareholder will perform (or arrange for the performance of) the
management and administrative services required for the operation of the Trust.
Among other services, it will administer the accounts and handle relations with
the Investors, provide the Trust with office space, equipment and facilities and
other services necessary for its operation, and conduct the Trust's relations
with custodians, depositories, accountants, attorneys, brokers and dealers,
corporate fiduciaries, insurers, banks and others, as required.
The Managing Shareholder will also be responsible for making investment
and divestment decisions, subject to the provisions of the Declaration. The
Managing Shareholder will be obligated to pay the compensation of the personnel
and administrative and service expenses necessary to perform the foregoing
obligations. The Trust will pay all other expenses of the Trust, including
transaction expenses, valuation costs, expenses of preparing and printing
periodic reports for Investors and the Commission, postage for Trust mailings,
Commission fees, interest, taxes, legal, accounting and consulting fees,
litigation expenses and other expenses properly payable by the Trust. The Trust
will reimburse the Managing Shareholder for all such Trust expenses paid by it.
As compensation for the Managing Shareholder's performance under the
Management Agreement, the Trust is obligated to pay the Managing Shareholder an
annual management fee described below at Item 13 -- Certain Relationships and
Related Transactions.
Each Investor consented to the terms and conditions of the initial
Management Agreement by subscribing to acquire Investor Shares in the Trust. The
Management Agreement is subject to termination at any time on 60 days' prior
notice by a majority in interest of the Investors or the Managing Shareholder.
The Management Agreement is subject to amendment by the parties with the
approval of a majority in interest of the Investors.
(d) Executive Officers of the Trust.
Pursuant to the Declaration, the Managing Shareholder has appointed
officers of the Trust to act on behalf of the Trust and sign documents on behalf
of the Trust as authorized by the Managing Shareholder. Mr. Swanson has been
named the President of the Trust and the other principal 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 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 Trusts 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 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
All individuals subject to the requirements of Section 16(a) have
complied with those reporting requirements during 2001.
(g) RPM.
As discussed above at Item 1 - Business, RPM assumed day-to-day
management responsibility for the Brea Project, effective June 1, 1997. Like the
Managing Shareholder, RPM is wholly owned by Robert E. Swanson. RPM will also
provide management services to the Olinda Project. RPM will charge 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 will
be borne by the Managing Shareholder.
The Managing Shareholder does not charge RPM for the full amount of
rent, utilities, 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; and 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.
The Operation Agreement does not have a fixed term and is terminable by
RPM, by the Managing Shareholder or by vote of a majority in 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 the officers for the
Managing Shareholder, as set forth above.
Item 11. Executive Compensation.
The Managing Shareholder compensates its officers without additional
payments by the Trust. The Trust will reimburse RPM at cost for services
provided by RPM's employees. Information as to the fees payable to the Managing
Shareholder and certain affiliates is contained at Item 13 - Certain
Relationships and Related Transactions.
Ridgewood Holding, the Corporate Trustee of the Trust, is not entitled
to compensation for serving in such capacity, but is entitled to be reimbursed
for Trust expenses incurred by it, which are properly reimbursable under the
Declaration.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The Trust sold 105.5 Investor Shares (approximately $10.5 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 March 31, 1992. Further details concerning the offering are
set forth above at Item 1--Business. No person beneficially owns 5% or more of
the Investor Shares.
The Managing Shareholder of the Trust, purchased for cash in the
offering 1 Investor Share, equal to .9 of 1% of the outstanding Investor Shares,
and Mr. Swanson purchased an additional 2.1 Investor Shares. The total cost of
the 3.0 Investor Shares was $273,000. By virtue of its purchase of that Investor
Share, Ridgewood Power is entitled to the same ratable interest in the Trust as
all other purchasers of Investor Shares. No other executive officers of the
Trust acquired Investor Shares in the Trust's offering.
The Managing Shareholder was issued one Management Share in the Trust
representing the beneficial interests and management rights of Ridgewood Power
in its capacity as the Managing Shareholder (excluding its interest in the Trust
attributable to Investor Shares it acquired in the offering). The management
rights of Ridgewood Power are described in further detail above at Item 1 -
Business and in Item 10 - Directors and Executive Officers of the Registrant.
Its beneficial interest in cash distributions of the Trust and its allocable
share of the Trust's net profits and net losses and other items attributable to
the Management Share are described in further detail below at Item 13. Certain
Relationships and Related Transactions.
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable
reserves that 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 received annual distributions equal to 15% of
their Capital Contributions (a "15% Priority Distribution") and thereafter any
remaining distributions will be allocated 80% to the 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, 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:
Paid to 2001 2000 1999 1998 1997
Managing
Shareholder $87,406 $70,083 $76,332 $69,931 $67,483
Cost
reimbursement
RPM $1,842,315 $1,255,007 $1,334,451 1,434,588 2,040,979
The management fee, payable monthly under the Management Agreement at
the annual rate of 1% of the Trust's net asset value (until June 1994, of the
Trust's total capital contributions), began on the closing of the offering and
compensates the Managing Shareholder for certain management, administrative and
advisory services for the Trust. In addition to the foregoing, the Trust
reimbursed the Managing Shareholder at cost for expenses and fees of
unaffiliated persons engaged by the Managing Shareholder for Trust business and
for payroll and other costs of operation of the Trust's Projects. The
reimbursements to RPM, which do not exceed its actual costs, are described at
Item 10(f) - Directors and Executive Officers of the Registrant -- RPM.
Other information in response to this item is reported in response to
Item 11 -- Executive Compensation, which information is incorporated by
reference into this Item 13.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Financial Statements.
See the Index to Consolidated Financial Statements in Item 8 hereof.
(b) Reports on Form 8-K.
The Trust filed a report on Form 8-K on December 20, 2001 in which the
Trust reported upon the results of its consent solicitation to withdraw its
election as a business development company under the Investment Company Act of
1940 and make certain conforming amendments to the Declaration of Trust.
(c) Exhibits.
2A. Acquisition Agreement, by and between GSF Energy, L.L.C. and Olinda,
L.L.C., dated as of May 31, 1997. Incorporated by reference to Exhibit 2A in
Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
2B. Letter, dated as of May 31, 1997, supplementing Acquisition Agreement.
Incorporated by reference to Exhibit 2B in Registrant's Current Report on Form
8-K dated June 1, 1997.
3A. Certificate of Trust of the Registrant is incorporated by reference to
Exhibit 3A of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.
3B. Declaration of Trust of Registrant is incorporated by reference to
Exhibit 3B of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.
3C. Agreement of Limited Partnership of Ridgewood Energy Electric Power,
L.P. dated as of March 6, 1991 is incorporated by reference to Exhibit 3C of
Registrant's Registration Statement which was filed with the Commission on May
26, 1994.
10A. Management Agreement between the Registrant and Ridgewood Power
Corporation is incorporated by reference to Exhibit 10A of Registrant's
Registration Statement which was filed with the Commission on May 26, 1994.
10B. Stillwater Hydro Partners L.P. Amended and Restated Agreement of
Limited Partnership dated as of July 29, 1991 and letter of amendment thereof
dated as of May 16, 1994 is incorporated by reference to Exhibit 10B of
Registrant's Registration Statement which was filed with the Commission on May
26, 1994.
10C. Power Purchase Agreement dated as of September 19, 1989 between
Stillwater Hydro Partners L.P. and Niagara Mohawk Power Corporation and
amendment thereof dated as of August 28, 1990 is incorporated by reference to
Exhibit 10C of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.
10D. RW Power Partners L.P. Agreement and Restated Agreement of Limited
Partnership dated as of October 1, 1992 among Ridgewood Energy Electric Power,
L.P., Ridgewood Power Corporation and WE GEN, Inc. is incorporated by reference
to Exhibit 10D of Registrant's Registration Statement which was filed with the
Commission on May 26, 1994.
10E. The Registrant has terminated the agreement designated 10E in its
prior Annual Reports on Form 10-K.
10F. The Registrant has terminated the agreement designated 10F in its
prior Annual Reports on Form 10-K.
10G. Agreement of Limited Partnership of Brea Power Partners, L.P. dated as
of October 12, 1994 by and between Brea Power (I), Inc., GSF Energy Inc. and
Ridgewood Electric Power Trust I is incorporated by reference to Registrant's
Form 8-K filed with the Commission on October 27, 1994.
10H. Agreement, dated as of January 16, 1997, by and between RW Power
Partners, L.P. and Virginia Electric Power Company Incorporated by reference to
Exhibit 10H in the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1997.
10I. Amendment to Transaction Documents, dated as of May 31, 1997, by and
among GSF Energy, L.L.C., Brea Power Partners, L.P. and Ridgewood Electric Power
Trust I. Incorporated by reference to Exhibit 10I in Registrant's Amendment No.
1 to Current Report on
Form 8-K dated June 1, 1997.
10J. Parallel Generation Agreement, by and between Southern California
Edison Company and GSF Energy, Inc. (Brea Power Partners, L.P., assignee), as
amended. Incorporated by reference to Exhibit 10J in Registrant's Amendment No.
1 to Current Report on Form 8-K dated June 1, 1997.
10K. Partial Assignment and Assumption Agreement, dated as of November 29,
1994, by and between GSF Energy, Inc. and Brea Power Partners, L.P. Incorporated
by reference to Exhibit 10K in Registrant's Amendment No. 1 to Current Report on
Form 8-K dated June 1, 1997.
10L. Amended and Restated Gas Lease Agreement, dated as of December 14,
1993, by and between the County of Orange, California and GSF Energy, Inc., as
modified. Incorporated by reference to Exhibit 10L in Registrant's Amendment No.
1 to Current Report on Form 8-K dated June 1, 1997.
10M. Gas Sale and Purchase Agreement, dated November 29, 1994 by and
between GSF Energy, Inc. and Brea Power Partners, L.P. Incorporated by reference
to Exhibit 10M in Registrant's Amendment No. 1 to Current Report on Form 8-K
dated June 1, 1997.
10N. Support Agreement, dated as of November 29, 1994, by and among Brea
Power Partners, L.P., the Trust and GSF Energy, Inc. Incorporated by reference
to Exhibit 10N in Registrant's Amendment No. 1 to Current Report on Form 8-K
dated June 1, 1997.
10O. Amended and Restated Gas Sale and Purchase Agreement, dated June
11, 2001, by and between GSF Energy, LLC and Ridgewood Power Management, LLC, on
behalf of Brea Power Partners, L.P. and Ridgewood Olinda, LLC.
Exhibits and schedules to these exhibits are omitted, and lists of the omitted
documents are found in their tables of contents. The Registrant agrees to
furnish supplementally a copy of any omitted exhibit or schedule to these
exhibits to the Commission upon request.
21. Subsidiaries of the Registrant. 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 I (Registrant)
By:/s/ Robert E. Swanson President April 15, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
By:/s/ Robert E. Swanson President April 15, 2002
Robert E. Swanson
By:/s/ Christopher Naunton Vice President and April 15, 2002 C
hristopher Naunton Chief Financial Officer
RIDGEWOOD POWER LLC Managing Shareholder April 15, 2002
By:/s/ Robert E. Swanson President
Robert E. Swanson
Ridgewood Electric Power Trust I
Consolidated Financial Statements
December 31, 2001, 2000 and 1999
Report of Independent Accountants
To the Shareholders of
Ridgewood Electric Power Trust I:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in shareholders' equity and of
cash flows present fairly, in all material respects, the financial position of
Ridgewood Electric Power Trust I and its subsidiaries (the "Trust")at December
31, 2001 and 2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Trust's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As discussed in Notes 1 and 2, effective on December 18, 2001, the shareholders
of the Trust consented to end its election to be treated as a Business
Development Corporation under the Investment Company Act of 1940. As a result,
accounting principles generally accepted in the United States of America for
investment companies no longer applied to the Trust and the Trust adopted
accounting principles generally accepted in the United States of America
applicable to operating companies. The financial statements of the Trust for
December 31, 2000 and 1999 have been restated to reflect the application of
accounting principles generally accepted in the United States of America for
operating companies.
PricewaterhouseCoopers LLP
Florham Park, NJ
April 2, 2002
Ridgewood Electric Power Trust I
Consolidated Balance Sheets
- --------------------------------------------------------------------------------
December 31,
---------------------------
2001 2000
Restated
----------- -----------
Assets:
Cash and cash equivalents ....................... $ 2,848,041 $ 1,712,745
Trade receivables, net of allowance
of $334,106 in 2000 ............................ 228,958 397,762
Due from affiliates ............................. 1,698 --
Other current assets ............................ 17,197 13,372
----------- -----------
Total current assets ..................... 3,095,894 2,123,879
Investment in Stillwater Hydro Partners, L.P. ... 562,319 591,634
Plant and equipment ............................. 5,869,018 3,397,717
Accumulated depreciation ........................ (946,721) (709,397)
----------- -----------
4,922,297 2,688,320
----------- -----------
Electric power sales contract ................... 2,207,778 2,207,778
Accumulated amortization ........................ (1,419,289) (1,103,891)
----------- -----------
788,489 1,103,887
----------- -----------
Total assets ............................ $ 9,368,999 $ 6,507,720
----------- -----------
Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ........... $ 114,707 $ 149,400
Current maturities of long-term debt ............ 252,272 --
Due to affiliates ............................... 1,117 39,967
----------- -----------
Total current liabilities .............. 368,096 189,367
Long-term debt, less current portion ............ 1,227,674 --
Commitments and contingencies ................... -- --
Shareholders' Equity:
Shareholders' equity (105.5 investor
shares issued and outstanding)
7,785,656 6,345,329
Managing shareholder's accumulated
deficit (1 management share
issued and outstanding) ...................... (12,427) (26,976)
----------- -----------
Total shareholders' equity ............. 7,773,229 6,318,353
----------- -----------
Total liabilities and shareholders' equity $ 9,368,999 $ 6,507,720
----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I
Consolidated Statements of Operations
- --------------------------------------------------------------------------------
Year Ended December 31,
------------------------------------------
2001 2000 1999
Restated Restated
----------- ----------- -----------
Power generation revenue ......... $ 4,140,580 $ 3,083,679 $ 3,040,674
Rental revenue ................... 238,574 175,883 73,829
----------- ----------- -----------
Total revenue ................. 4,379,154 3,259,562 3,114,503
Cost of sales, including
depreciation and amortization
of $552,722, $547,121 and$522,006
in 2001, 2000 and 1999 ........... 1,929,321 1,327,339 1,757,910
----------- ----------- -----------
Gross profit ...................... 2,449,833 1,932,223 1,356,593
General and administrative expenses 752,589 427,826 54,929
Write down of investment in
Ridgewood Power Partners, L.P. ... -- -- 422,019
Management fee paid to managing
shareholder....................... 87,406 70,083 76,332
----------- ----------- -----------
Total other operating expenses 839,995 497,909 553,280
----------- ----------- -----------
Income from operations ............ 1,609,838 1,434,314 803,313
----------- ----------- -----------
Other income (expense):
Interest income ................ 78,584 89,163 69,746
Interest expense ............... (10,852) -- --
Other expense .................. (193,379) (46,963) (43,618)
Equity (loss) income from
Stillwater Hydro
Partners, L.P. .............. (29,315) 11,484 (29,724)
----------- ----------- -----------
Other income (expense), net .. (154,962) 53,684 (3,596)
----------- ----------- -----------
Net income ........................ $ 1,454,876 $ 1,487,998 $ 799,717
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I
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 ...... $ 6,855,938 $ (21,818) $ 6,834,120
Cash distributions .... (1,297,654) (13,108) (1,310,762)
Net income for the year 791,720 7,997 799,717
----------- ----------- -----------
Shareholders' equity,
December 31, 1999 ..... 6,350,004 (26,929) 6,323,075
Cash distributions .... (1,477,793) (14,927) (1,492,720)
Net income for the year 1,473,118 14,880 1,487,998
----------- ----------- -----------
Shareholders' equity,
December 31, 2000 .... 6,345,329 (26,976) 6,318,353
Net income for the year 1,440,327 14,549 1,454,876
----------- ----------- -----------
Shareholders' equity,
December 31, 2001 ..... $ 7,785,656 $ (12,427) $ 7,773,229
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I
Consolidated Statements of Cash Flows
- -------------------------------------------------------------------------------
Year Ended December 31,
----------------------------------------
2001 2000 1999
Restated Restated
----------- ----------- -----------
Cash flows from operating
activities:
Net income ................. $ 1,454,876 $ 1,487,998 $ 799,717
----------- ----------- -----------
Adjustments to reconcile net
income to net cash flows
from operating activities:
Depreciation and
amortization .............. 552,722 547,121 522,006
Provision for doubtful
accounts .................. -- 334,106 --
Write down of investment in
Ridgewood Power Partners,
L.P ..................... -- -- 422,019
Equity in (earnings)/loss
from unconsolidated
Stillwater Hydro Partners,
L.P ..................... 29,315 (11,484) 29,724
Changes in assets and
liabilities:
Decrease (increase) in
trade receivables ....... 168,804 (262,602) (26,788)
(Increase) decrease in
other current assets ... (3,825) (801) 162,879
(Decrease) increase in
accounts payable and
accrued expenses ...... (34,693) (20,061) 134,278
Decrease in due to/from
affiliates, net ........ (40,548) (10,819) (554)
----------- ----------- -----------
Total adjustments ...... 671,775 575,460 1,243,564
----------- ----------- -----------
Net cash provided by
operating activities ... 2,126,651 2,063,458 2,043,281
----------- ----------- -----------
Cash flows from investing
activities:
Investment in Ridgewood
Power Partners, L.P. ...... -- -- (3,505)
Capital expenditures ....... (2,471,301) -- (725,109)
----------- ----------- -----------
Net cash used in
investing activities ... (2,471,301) -- (728,614)
----------- ----------- -----------
Cash flows from financing
activities:
Proceeds from long-term debt 1,500,000 -- --
Payments to reduce long-term
debt ..................... (20,054) -- --
Cash distributions to
shareholders ............. -- (1,492,720) (1,310,762)
----------- ----------- -----------
Net cash provided by
(used in)financing
activities ........... 1,479,946 (1,492,720) (1,310,762)
----------- ----------- -----------
Net increase in cash and cash
equivalents .................. 1,135,296 570,738 3,905
Cash and cash equivalents,
beginning of year ............ 1,712,745 1,142,007 1,138,102
----------- ----------- -----------
Cash and cash equivalents,
end of year .................. $ 2,848,041 $ 1,712,745 $ 1,142,007
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I
Notes to the Consolidated Financial Statements
- -------------------------------------------------------------------------------
1. Organization and Purpose
Nature of Business
Ridgewood Energy Electric Power, L.P. (the "Partnership") was formed as a
Delaware limited partnership on March 6, 1991, by Ridgewood Power LLC, (formerly
Ridgewood Power Corporation) acting as the general partner. On June 15, 1994,
with the approval of the partners, the Partnership merged all of its assets and
liabilities into a newly formed trust, called Ridgewood Electric Power Trust I
(the "Trust"). Effective July 25, 1994, the Trust elected to be treated as a
"business development company" ("BDC") under the Investment Company Act of 1940
(the "1940 Act") and registered its shares under the Securities Act of 1934. In
connection with this transaction, the Trust issued 105.5 shares in exchange for
outstanding Partnership units. Ridgewood Power LLC is the sole managing
shareholder.
In November 2001, through a proxy solicitation the Trust requested investor
consent to end the BDC status. On December 18, 2001, the consents were tabulated
and more than 50% of the investor shares consented to the elimination of the BDC
status. Accordingly, the Trust is no longer an investment company under the 1940
Act.
The Trust invests in independent power generation facilities and other power
generation assets. These independent power generation facilities include small
power production facilities which produce electricity from landfill gas and
water.
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.
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. At December 31, 2001, the Trust had
construction in progress of $2,449,052.
Depreciation is recorded using the straight-line method over the useful lives of
the assets, which are 5 to 20 years with a weighted average of 14 and 15 years
at December 31, 2001 and 2000, respectively. During 2001, 2000 and 1999, the
Trust recorded depreciation expense of $237,324, $231,723 and $206,608,
respectively.
Electric Power Sales Contract
A portion of the purchase price of the Brea Project was assigned to the electric
power sales contract and is being amortized over the life of the contract (7
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 $315,398.
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 year ended December 31, 2001 was $10,852.
Significant Customers
During 2001, 2000 and 1999, the Trust's largest customer, Southern California
Edison ("SCE"), accounted for 95%, 95% and 98%, 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
Brea Power Partners, L.P. (known as the Brea Project)
In October 1994, the Trust invested in a limited partnership ("Brea
Partnership"), which acquired a 5 megawatt gas-fired electric generating
facility and related landfill gas processing facility. On June 1, 1997, the
Trust purchased the general and other limited partnership interests in Brea to
increase its ownership in the Brea Project to 100%. The aggregate purchase price
of the Trust's investments totaled $5,916,879 including, the assumption of
liabilities and acquisition costs.
Electricity generated by the Brea Project, over and above its own requirements,
is sold to SCE under a Power Contract. The Power Contract may be terminated by
either party no earlier than the end of 2004 on 5 years' advance notice. On
March 23, 2000, SCE provided such written notice to the Brea Project notifying
the Brea Project it was electing to terminate the Power Contract as of March 23,
2005. After such termination, the Brea Project will sell its electric output in
the competitive electric power market The landfill gas is produced from a
landfill owned by the County of Orange, California and is collected and sold by
GSF Energy, L.L.C. ("GSF") under a gas lease agreement between GSF and the
County of Orange.
Ridgewood Mobile Power I, LLC
Effective August 1999, the Trust, through a subsidiary, acquired two Caterpillar
mobile power modules with a total capacity of 2.35 megawatts for $710,241. These
modules are rented to domestic and international customers. As per an agreement
with Hawthorne Power Systems ("Hawthorne"), the Trust pays Hawthorne, a
California company that maintains a large fleet of similar rental modules, a fee
of 20% of gross rental revenues to arrange and administer the rental of the
units. The revenue from these modules is included as rental revenue and
Hawthorne's fee is included in cost of sales in the Consolidated Statements of
Operations.
Ridgewood Olinda, LLC
In April 2001, the Trust formed Ridgewood Olinda, LLC. Ridgewood Olinda, LLC,
contracted with an unaffiliated engineering and construction firm to construct a
$3,000,000 2.5 megawatt expansion to the Brea Project. The completion and
testing of the new addition is expected to occur in the second quarter of 2002.
RW Power Partners, L.P. (known as the Lynchburg project)
In October 1992, the Trust acquired a limited partnership interest in RW Power
Partners, L.P. ("RWPP") which provided construction funding of a 3 megawatt
project using waste oil as its primary fuel source located in South Boston,
Virginia. Commercial operations began in June 1993.
During the fourth quarter of 1997, the Trust sold the Lynchburg Project to a
privately-held, unaffiliated processor of waste oil for $700,000 in the form of
an 8%, seven-year, promissory note, collateralized by a mortgage on the Project,
and the right of the Trust to receive 2% of the Project's gross revenues for an
indefinite period. Due to the uncertainty surrounding the Trust's ability to
collect the note receivable, the note was recorded at the carrying value of the
investment of $290,983. From 1997 to 1999, the Trust provided loans totaling
$125,000 to finance additional capital improvements at the Project,
collateralized by a mortgage lien, which were added to the investment balance.
In 1999, the privately held unaffiliated processor ceased operations at the
Lynchburg Project. Operations are not expected to resume and the Trust is not
expected to recover its investment. As a result, in 1999, the Trust wrote down
its investment in the Project to its estimated fair value of zero and recorded a
loss of $422,019.
Stillwater Hydro Partners, L.P.
On October 31, 1991, the Trust acquired, for $1,000,000, a 32.5% general
partner's interest in a limited partnership whose sole business is the
construction, ownership and operation of a 3.5 megawatt hydroelectric facility,
located on the Hudson River in Stillwater, New York (the "Stillwater Project").
At the time of the investment, the project was under construction and commenced
operations in May 1993. Electricity generated by the Stillwater Project is sold
to the Niagara Mohawk Power Corporation under a long-term Power Contract that
expires in 2028.
On May 16, 1994, the Trust, as stipulated in the limited partnership agreement,
elected to exchange its general partner interest for a 32.5% limited partnership
interest and a priority distribution of available cash flow from the project in
the aggregate amount of $1,000,000. Such distribution is payable from available
cash flows in nine annual installments together with interest at 12% per year,
which were scheduled to begin in May 1995.
The ultimate ability of the project to meet its payment obligations to the Trust
is dependent on the actual operating performance of the Stillwater Project,
which, in turn, is largely dependent upon water levels in the Hudson River.
Since 1995, water levels in the Hudson River basin have frequently been below
normal. As a result of the low water levels, the operating results of the
project were insufficient to meet its debt payments, and accordingly, no
distributions were made to the Trust since 1994.
As a result, all available cash flow from the Stillwater Project is being
applied to meet debt service requirements. Until the current arrears in debt
servicing are paid, it appears likely that most, if not all, of the payments due
to the Trust will be carried forward, with interest, into subsequent years.
The Trust accounts for its investment in the Stillwater Project under the equity
method of accounting. The Trust's equity in the income/loss of the Stillwater
Project has been included in the consolidated financial statements since
acquisition.
Summarized financial information for the Stillwater Project is as follows:
Balance Sheet Information
December 31, 2001 December 31, 2000
------------------- -------------------
Current assets $ 202,060 $ 155,519
Non-current assets 8,911,576 9,273,668
------------------- -------------------
Total assets $9,113,636 $9,429,187
------------------- -------------------
Current liabilities $ 964,925 $ 608,436
Long-term debt 4,727,555 5,498,778
Other non-current liabilities 2,442,848 2,206,238
Equity 978,308 1,115,735
------------------- -------------------
Total liabilities and equity $9,113,636 $9,429,187
------------------- -------------------
Statement of Operations Information
For the Year Ended December 31,
-----------------------------------------
2001 2000 1999
----------- ----------- -----------
Revenue .......... $ 1,262,217 $ 1,415,315 $ 1,334,051
Operating expenses 1,472,418 1,499,980 1,545,510
----------- ----------- -----------
----------- ----------- -----------
Net loss ......... $ (210,201) $ (84,665) $ (211,459)
----------- ----------- -----------
4. Long-Term Debt
In August 2001, Ridgewood Olinda, LLC entered into an agreement, effective
December 2001, to borrow $1,500,000. The proceeds from the loan were used to
finance the 2.5 megawatt expansion of the Olinda facility. The collateralized
non-recourse notes are due in monthly installments of $30,906, including
interest at 8.68%. Final payment is due on November 30, 2006. The loan is
collateralized by the newly expanded portion of the Olinda facility.
Following is a summary of long-term debt at December 31, 2001:
Senior collateralized non-recourse notes payable $ 1,479,946
Less - Current maturity (252,272)
-----------------
-----------------
Total long-term debt $ 1,227,674
-----------------
Scheduled repayments of long-term debt principal for the next five years are as
follows:
Year Ended
December 31, Repayment
2002 $ 252,272
2003 275,067
2004 299,921
2005 327,022
2006 325,664
5. Commitments
In April of 2001, Ridgewood Olinda, LLC entered into an agreement with an
unaffiliated engineering and construction firm to construct the expansion of the
Olinda facility. The agreement calls for the construction of a 2.5 megawatt
addition with a cost of $2,500,000. As of December 31, 2001, Ridgewood Olinda,
LLC had paid $2,000,000 of the agreed upon cost. As stated in the agreement, the
remaining $500,000 will be paid upon completion and satisfactory testing of the
expanded facility. The time frame for completion and payment is expected to be
in the second quarter of 2002.
6. Transactions With Managing Shareholder and Affiliates
On June 15, 1994, the Trust entered into a management agreement with the
managing shareholder, under which the managing shareholder renders certain
management, administrative and advisory services and provides office space and
other facilities to the Trust. As compensation to the managing shareholder, the
Trust pays the managing shareholder an annual management fee equal to 1% of the
net assets of the Trust payable monthly. During 2001, 2000 and 1999, the Trust
paid management fees to the managing shareholder of $87,406, $70,083 and
$76,331, respectively.
Under the Declaration of Trust, the managing shareholder is entitled to receive
each year 1% of all distributions made by the Trust (other than those derived
from the disposition of Trust property) until the shareholders have been
distributed a cumulative amount equal to 15% per annum of their equity
contribution. Thereafter, the managing shareholder is entitled to receive 20% of
the distributions for the remainder of the year. The managing shareholder is
entitled to receive 1% of the proceeds from dispositions of Trust properties
until the shareholders have received cumulative distributions equal to their
original investment ("Payout"). After Payout, the managing shareholder is
entitled to receive 20% of all remaining distributions of the Trust.
The managing shareholder and affiliates own, in the aggregate, 3.0 investor
shares of the Trust with a cost of $273,000. The Trust granted the managing
shareholder a single Management Share representing the managing shareholder's
management rights and rights to distributions of cash flow.
Under an Operating Agreement with the Trust, Ridgewood Power Management LLC
("Ridgewood Management," formerly Ridgewood Power Management Corporation), an
entity related to the managing shareholder through common ownership, provides
management, purchasing, engineering, planning and administrative services to the
Brea Project. 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 or in proportion to amounts
invested in projects managed by Ridgewood Management. During the year ended
December 31, 2001, 2000 and 1999, Ridgewood Management charged the Brea Project
$165,083, $118,169 and $163,480, respectively, for overhead items allocated in
proportion to the amount invested in projects managed. Ridgewood Management also
charged the Brea Project for all of the direct operating and non-operating
expenses incurred during the period.
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.
7. Fair Value of Financial Instruments
At December 31, 2001 and 2000, the carrying value of the Trust's cash and cash
equivalents, trade receivables, and accounts payable and accrued expenses
approximates their fair value. The fair value of the long-term debt, calculated
using current rates for loans with similar maturities, does not differ
materially from its carrying value.
8. Sale of Trade Receivables
In January 2001, SCE informed the Brea Project, as well as numerous other
unaffiliated electric generating facilities in California, that it was
temporarily suspending payments to such facilities due to SCE's severe financial
problems. SCE did not pay the Brea Project for energy and capacity delivered to
SCE for the months of November and December 2000, January and February 2001. In
April 2001, the Brea 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 those months. Costs
associated with the sale of receivables of $480,252 and $334,106 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. SCE is current in its payments for energy and capacity delivered
after February 2001.