SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
Commission file number 0-21304
RIDGEWOOD ELECTRIC POWER TRUST II
(Exact Name of Registrant as Specified in Its Charter)
Delaware 22-3206429
(State or Other Jurisdiction (I.R.S. Employer Identification No.)
of Incorporation or Organization)
1314 King Street
Wilmington, DE 19801
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, including Area Code: (302)888-7444
Securities Registered Pursuant to Section 12(b) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
Shares of Beneficial Interest
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
Indicate by check mark whether registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes ___ No X
There is no market for the Shares. The aggregate capital contributions made
for the Registrant's voting Shares held by non-affiliates of the Registrant at
March 31, 2002 was $23,537,750.
Exhibit Index is located on Page 27.
PART I
Item 1. Business.
Forward-looking statement advisory
This Annual Report on Form 10-K, as with some other statements made by
Ridgewood Electric Power Trust II (the "Trust") from time to time, includes
forward-looking statements. These statements discuss business trends and other
matters relating to the Trust's future results and business. In order to make
these statements, the Trust has had to make assumptions as to the future. It has
also had to make estimates in some cases about events that have already
happened, and to rely on data that may be found to be inaccurate at a later
time. Because these forward-looking statements are based on assumptions,
estimates and changeable data, and because any attempt to predict the future is
subject to other errors, what happens to the Trust in the future may be
materially different from the Trust's statements here.
The Trust therefore warns readers of this document that they should not
rely on these forward-looking statements without considering all of the things
that could make them inaccurate. The Trust's other filings with the Securities
and Exchange Commission and its offering materials discuss many (but not all) of
the risks and uncertainties that might affect these forward-looking statements.
Some of these are changes in political and economic conditions, federal
or state regulatory structures, government taxation, spending and budgetary
policies, government mandates, demand for electricity and thermal energy, the
ability of customers to pay for energy received, supplies and prices of fuels,
operational status of plant, mechanical breakdowns, availability of labor and
the willingness of electric utilities to perform existing power purchase
agreements in good faith.
By making these statements now, the Trust is not making any commitment
to revise these forward-looking statements to reflect events that happen after
the date of this document or to reflect unanticipated future events.
(a) General Development of Business.
The Trust was organized as a Delaware business trust on November 20,
1992 to participate in the development, construction and operation of
independent power generating facilities ("Independent Power Projects" or
"Projects"). Ridgewood Energy Holding Corporation ("Ridgewood Holding"), a
Delaware corporation, is the Corporate Trustee of the Trust.
The Trust sold shares of beneficial interest in the Trust ("Investor
Shares") in a private placement offering (the "Offering") which ended on January
31, 1994, at which time it had raised approximately $23.5 million. Net of
offering fees, commissions and expenses, the Offering provided approximately
$19.4 million of net funds available for investments in the development and
acquisition of Projects. The Trust has 491 record holders of Investor Shares
(the "Investors"). As described below in Item 1(c)(2), the Trust (and its
subsidiaries) owns interests in five Projects.
The Trust made an election to be treated as a "business development
company" under the Investment Company Act of 1940, as amended (the "1940 Act").
On February 27, 1993, the Trust notified the Securities and Exchange Commission
of such election and registered the Investor Shares under the Securities
Exchange Act of 1934, as amended (the "1934 Act"). On April 29, 1993, the
election and registration became effective. On November 5, 2001, the Trust
issued to the owners of Investor Shares (the "Investors") a "Notice of
Solicitation of Consents," in which the Trust sought the consent of the
Investors to withdraw its election to be treated as a "business development
company" under the 1940 Act and to make certain amendments to the Trust's
Declaration of Trust ("Declaration") as a result of such withdrawal, including,
but not limited to, deletion of the provision of the Declaration requiring
Independent Trustees. Consents were tabulated at the close of business on
January 7, 2002. A total of 235.3775 Investor Shares were outstanding and
entitled to be voted. Based on such tabulation, a two-third majority, as
required by the Declaration of Trust, consented to such withdrawal and
amendments. On January 10, 2002, the Trust filed with the Securities and
Exchange Commission a notification to withdraw its election to be treated as a
"business development company." As a result of such withdrawal, the Trust now
utilizes generally accepted accounting principles for operating companies.
The Trust is organized similarly to a limited partnership. Ridgewood
Renewable Power LLC (the "Managing Shareholder"), a Delaware limited liability
company, is the Managing Shareholder of the Trust. In general, the Managing
Shareholder has the powers of a general partner of a limited partnership. It has
complete control of the day-to-day operation of the Trust. The Managing
Shareholder is not regularly elected by the owners of the Investor Shares (the
"Investors").
Ridgewood Holding is the Corporate Trustee of the Trust. The Corporate
Trustee acts on the instructions of the Managing Shareholder and is not
authorized to take independent discretionary action on behalf of the Trust. See
Item 10. - Directors and Executive Officers of the Registrant below for a
further description of the management of the Trust.
In addition, the Trust is affiliated with the following trusts
organized by the Managing Shareholder (the "Other Power Trusts"):
o Ridgewood Electric Power Trust I ("Power I");
o Ridgewood Electric Power TrustIII ("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");
o Ridgewood/Egypt Fund ("Egypt Fund"); and
o Ridgewood Power B Fund/Providence Expansion (the "B Fund").
In addition, the Trust is affiliated with certain Delaware limited liability
companies formed by the Managing Shareholder ("Ridgewood LLCs") and for which
the Managing Shareholder acts as Manager. These LLCs are:
o Ridgewood Renewable PowerBank LLC
o Ridgewood Renewable Powerbank II, LLC
(b) Financial Information about Industry Segments.
The Trust operates in only one industry segment: investing in
independent power generation and similar energy projects.
(c) Narrative Description of Business.
The Trust was formed to participate in the development, construction
and operation of Projects that generate electricity or related forms of energy
for sale to manufacturers, utilities and other users. The Trust also may invest
in facilities related to those Projects.
(1) The Trust's Investments.
(i) Berkshire Project and B-3 Project.
On January 4, 1994, the Trust made an approximately $2.3 million equity
investment in Pittsfield Investors Limited Partnership, which was formed to
acquire the Berkshire Project, including the assets and business of the
Pittsfield Resource Recovery Facility. The Berkshire Project is a waste to
energy plant located in Pittsfield, Massachusetts. The Berkshire Project, which
has been operating since 1981, burns municipal solid waste supplied by the City
of Pittsfield ("Pittsfield"), surrounding communities and other providers. The
Trust's partners in the Berkshire Project were subsidiaries of Energy Answers
Corporation ("EAC"). EAC made an equity investment of approximately $1.3 million
in the Berkshire Partnership and also serves as manager and operator of the
facility.
The Trust was entitled to an annual preferred distribution of available
cash flow, representing revenue from the Berkshire Project, (after funding debt
service, debt service reserves and operating and maintenance expenses) in an
amount equal to 15% of its investment. In the event that distributions were
insufficient to pay the 15% preferred distribution in any given year, the
shortfall would be payable out of distributions, if any, in subsequent years.
After the Trust had received its 15% preferred distribution in any given year,
EAC was entitled to an annual management fee for operating and managing the
facility in an amount equal to $300,000, escalating with inflation. After these
initial distributions had been made, the Trust was entitled to receive an
additional amount equal to 5% of its investment and then EAC was entitled to
receive an additional amount equal to 10% of the amount previously distributed
to it. Any remaining distributable cash flow for the year would be shared
equally by the Trust and EAC.
Distributions from the Berkshire Project ceased in the third quarter of
1998 and did not resume. In the third quarter of 1998, EAC informed the Trust
that significant and undisclosed cost overruns in the construction of an ash
handling system for the Berkshire Project had depleted the Project's funds. EAC
further advised the Trust that distributions from Berkshire to the Trust were
unlikely to resume. As a result of the expiration of certain key agreements at
the end of 2004, the Berkshire Project's ability to continue operations
thereafter was uncertain.
In addition, on August 31, 1994, the Trust entered into the B-3 Limited
Partnership, with affiliates of EAC, the same firm with which the Trust
participated in the Berkshire Project. The Trust made an investment of
approximately $4 million into the B-3 Limited Partnership to construct a
municipal waste transfer station located in Columbia County, New York ("B-3
Project"). The B-3 Project is a waste transfer station where municipal waste
collected from nearby towns by smaller, short haul trucks can be transferred to
larger, long haul trucks for more efficient transportation of the waste to
distant landfills. The Trust was entitled to receive a cumulative priority
return on the Trust investment of 18% per annum, with any shortfalls being
carried forward into subsequent years. Thereafter, EAC affiliates were entitled
to receive a management fee of $175,000 escalating with inflation. Any
additional cash flow would be split 50/50 between the Trust and EAC affiliates.
As with the Berkshire Project, distributions from the B-3 Project were
been impaired by repeated extensions of the closing deadlines for some local
landfills and capacity expansions at other local landfills. If waste can be
cheaply deposited at local landfills, there is less demand for consolidating the
waste for transfer to distant sites.
As a result of the financial difficulties experience by both the
Berkshire and B-3 Projects and the lack of distributions form either project,
the Trust began negotiations with EAC in 2002 to either renegotiate certain
aspects of the contractual documents that the Trust believed hindered operation
and failed to properly motivate EAC or, in the alternative, sell its interest in
the Berkshire Project and B-3 Project to EAC. Ultimately, the parties agreed to
a sale.
On September 20, 2002 the Trust, sold 100% of its ownership interest
in the B-3 Project and the Berkshire Project to EAC. The acquisition agreement
provides for the sale of 100% of the Trust's ownership in the two projects in
return for $1,200,000 cash and $5,000,000 of interest bearing promissory notes.
The notes bear interest at a rate of 10% per annum, and will be repaid over a
17-year term. The notes are collateralized by all the assets of the
partnerships.
(ii) Monterey Project.
On January 9, 1995, the Trust purchased 100% of the equity interests in
Sunnyside Cogeneration Partners, L.P., which owns a 5.5-megawatt cogeneration
project located in Salinas, Monterey County, California (the "Monterey
Project"). The aggregate purchase price was approximately $5.2 million including
transaction costs. The Monterey Project has been operating since 1991 and uses
natural gas fired reciprocating engines to generate electricity for sale to
Pacific Gas and Electric Company ("PG&E") under a long term contract expiring in
2020 (the "Power Contract"). Thermal energy from the Monterey Project is used to
provide warm water to an adjacent greenhouse under a long- term contract that
also terminates in 2020. The Monterey Project is operated on behalf of the Trust
by Ridgewood Power Management LLC ("RPM").
The Monterey Project is a "Qualifying Facility" or "QF" under the
Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). The
independent power industry in the United States was created in large part by
PURPA and other federal legislation passed in response to the energy crises of
the 1970s. PURPA, among other things, requires utilities to purchase electric
power from QFs, and also exempts these QFs from most federal and state utility
regulatory requirements. In addition, the price paid by electric utilities under
PURPA for electricity produced by QFs is the utility's avoided cost of producing
electricity (i.e., the incremental costs the utility would otherwise face to
generate electricity itself or purchase electricity from another source).
Pursuant to PURPA, and state implementation of PURPA, many electric utilities
have entered into long-term Power Contracts with QFs at rates set by contract
formula approved by state regulatory commissions. The Monterey Project sells its
output to PG&E under a Power Contract with a capacity and energy payment
determined pursuant to a contract formula approved by the California Public
Utilities Commission ("CPUC"). According to the Power Contract, the energy
payment is based upon a benchmark energy price adjusted for changes over time in
a gas index; the so- called "Short Run Avoided Cost Methodology" or SRAC.
However, as described further below, the Monterey Project executed an Amendment
to the Power Contract with PG&E, which provides that the Monterey Project will
receive a fixed energy payment (as well as the required capacity payment) for a
term of five (5) years, until approximately August 2006.
During calendar years 2000 and 2001, California experienced severe
electric energy crises brought on my many factors including, but not limited to,
implementation of flawed electric deregulation legislation. As a result of the
energy crises, PG&E, among other things, experienced severe cash shortages and
losses due primarily to the fact that it was required under the law to purchase
electric energy at wholesale prices significantly above the regulated rates it
could legally charge retail customers. As a result, PG&E filed for protection
under the U.S. Bankruptcy Code in April of 2001. At the time of PG&E's
bankruptcy filing,, the Monterey Project had not been paid by PG&E for the
electric energy and capacity it had delivered in the last several months of 2000
and the first few months of 2001. In addition, given PG&E's bankruptcy, the
prospects for payment in the near future were extremely remote. However, the
Monterey Project needed to have a reserve of cash to maintain operations and pay
certain fixed costs that would be incurred regardless of whether it operated and
sold to PG&E. Therefore, as further detailed in the Trust's Annual Report on
Form 10K for the Year 2001, the Trust sold its PG&E receivables at a discount.
Subsequent to its bankruptcy filing, PG&E found itself under intense
pressure to pay the QFs offline some amount of the outstanding balance owed and
to renegotiate Power Contracts in order to get their electric generation back
online and supply the electric starved State of California. Therefore, in an
effort to get as many QFs back online as possible, PG&E sought and received
approval from the California Public Utilities Commission ("CPUC") to offer each
QF an agreement, and corresponding amendment to their Power Contracts, for a
term of five (5) years, which would effectively replace, for such 5 year term,
the variable SRAC formula for determining the energy price with a fixed energy
price. Such amendment would allow the QF to operate at a price that was
reasonable in light of the circumstances at that time. In addition, a QF that
executed the amendment agreed that it would not institute, or proceed with
outstanding, litigation against PG&E. The Monterey Project executed such
amendment. However, in order to execute the amendment with a fixed energy price,
it was necessary to procure natural gas at a fixed price. As a result of the
sale of the PG&E receivables, the Monterey Project had sufficient cash available
and was able to procure such supply of natural gas from Coral Energy Services,
Inc., ("Coral") a subsidiary of Shell Oil. Therefore, until approximately August
2006, the Monterey Project will be operating under the Amendment, which is
expected to result in positive cash flow to the Monterey Project. Thereafter,
the Power Contract with the SRAC formula becomes the energy price and there is
no guarantee that SRAC at that time will provide sufficient cash for the
Monterey Project to operate profitably. However, under the Power Contract, the
Monterey Project is also paid a capacity payment. Such payment, along with an
SRAC based energy payment, even if in somewhat low, should be enough for the
Monterey Project to operate and have a positive cash flow.
(iii) California Pumping Project
In 1995, the Trust purchased a package of irrigation service engines
(the "Pumping Project") located in Ventura County, California and also in 1995
the Trust bought additional engines from unaffiliated sellers. The Trust's total
investment in the Pumping Project was approximately $952,000. RPM operates and
manages the Pumping Project.
The Pumping Project has been operating since 1992 and uses 26
natural-gas-fired reciprocating engines with a rated equivalent capacity of 6
Megawatts to provide power for irrigation wells that furnish water for orchards
of lemon and other citrus trees. The power is purchased by local farmers and
farmers' co-operatives pursuant to electric services contracts. Presently, the
Pumping Project's rates are approximately 85% of Southern California Edison
Company's agricultural rate of 12.2 cents/kwh. The discount was provided because
of the low natural gas prices experienced during most of 2002. However, natural
gas prices have risen and the Pumping Project is considering lowering the
discount to 90% of SCE's rate or even less, if natural gas prices continue to
rise.
Power IV owns a package of similar engines located on different sites
and operated under identical terms. The engines operate independently of each
other and revenues and expenses for each Trust are segregated from those of the
other.
(iv) San Diego Project.
The Trust acquired its interest in the San Diego Project on March 21,
1994, when it made an investment of approximately $2.3 million to acquire an 80%
interest in the Project. The Trust made additional capital contributions,
totaling approximately $1.2 million, to the Project to fund working capital and
to purchase various leased equipment. On June 25, 1997 the Trust sold its entire
interest in the San Diego Project to subsidiaries of NRG Energy, Inc. of
Minneapolis, Minnesota ("NRG"). The sale price was $6,200,000, of which
$3,500,000 was paid in cash at the closing. The remaining $2,700,000 was paid by
delivery of a collateralized, purchase money promissory note of the principal
NRG subsidiary purchasing the Project. The note bears interest at 8% per year
and is payable in equal monthly installments of principal and interest through
its maturity on June 25, 2003. The note is collateralized by the partnership
interests sold by the Trust to the NRG subsidiaries.
(3) Project Management and Operations.
The Monterey Project's revenue from its Power Contract consists of two
components, energy payments and capacity payments. Energy payments are based on
a facility's net electric output, with payment rates (other than during the 5
year amendment) usually indexed to the fuel costs of the purchasing utility or
to general inflation indices. Capacity payments are based on either a facility's
net electric output or its available capacity. Capacity payment rates vary over
the term of a Power Contract according to various schedules.
The Berkshire Project obtains waste for fuel under a long-term contract
providing it with revenues from tipping fees, which are subject to the default
risks of dealing with municipalities and small trash haulers, and sells steam to
Crane under a long-term contract. The Columbia Project obtains its revenues from
spot and contract sales of transfer station services which are dependent upon
the volume of waste delivered to it and which are sensitive to the prices of
alternative disposal methods and local economic activity.
The Pumping Project sells its power to the farmers on whose land its
engines are situated under contracts terminable at any time on 60 days' prior
notice to the Trust. Although the Trust thus is at risk if many customers
concurrently terminate contracts, as might happen if an electric utility or
other supplier were to offer substantially discounted rates, the Trust believes
that it is currently a competitive supplier and that alternate customers can be
secured in the event contracts are terminated.
The major costs of a Project while in operation will be debt service
(if applicable), fuel, taxes, maintenance and operating labor. The ability to
reduce operating interruptions and to have a Project's capacity available at
times of peak demand are critical to the profitability of a Project.
Accordingly, skilled management is a major factor in the Trust's business.
Electricity produced by a Project is delivered to the purchaser through
transmission lines that are built to interconnect with the utility's existing
power grid. Steam produced by the Berkshire Project is conveyed directly to the
user by pipeline and the energy produced by the engines in the Pumping Project
is applied directly to pumps.
Generally, revenues from the sales of electric energy from a
cogeneration facility will represent the most significant portion of the
facility's total revenue. However, to maintain its status as a QF under PURPA,
it is imperative that the Monterey Project continues to satisfy PURPA
cogeneration requirements as to the amount of thermal products generated. See
Item 1(c)(6) - Regulatory Matters, for an explanation of these requirements.
Therefore, since the Monterey Project has only two customers (the electric
energy purchaser and the thermal products purchaser), loss of either of these
customers would have a material adverse effect on the Monterey Project.
Customers that accounted for more than 10% of consolidated revenue to
the Trust in each of last three fiscal years are:
Calendar year
2002 2001 2000
Pacific Gas & Electric Co. 69.0% 63.1% 80.0%
(4) Trends in the Electric Utility and Independent Power Industries
As a result of the energy crises experience by California during the
years 2000 and 2001, both the state legislature and the California Public
Utilities Commission ("CPUC") have taken significant action by enacting
legislation and implementing regulations, respectively, intended primarily to
avoid a repeat of the energy crises by creating amore stable, efficient and
economic energy market. While it will take some time to determine whether the
results hoped for by the state legislature and CPUC occur, the impact on the
energy market from such actions could be significant. For example, the
legislature enacted legislation designed to enhance, promote and encourage
renewable generation in the state by implementing a renewable portfolio standard
("RPS"), which will require all California investor owned utilities ("IOUs"), as
well as retail electric suppliers to have in their energy supply portfolio a
certain percentage of renewable generation. This percentage increases overtime
until the requirement equals 20%. In addition to the RPS, California enacted
legislation that will streamline the time required for and the costs of new
electric power plant permitting and construction. Finally, legislation has been
enacted that will fundamentally change the manner in which California IOUs
procure electric energy for their customers.
The deregulation legislation enacted by California in 1994 required,
among other things, that the California IOUs satisfy their energy needs by
procuring the electric energy from the wholesale power market. The energy prices
obtained from such market fluctuated and the IOUs could either make money, if
they purchased at prices less than the prices at which they sold, or lose money
if the wholesale prices was significantly higher than the retail price. The
California energy crises occurred in some measure because the wholesale price
actually became significantly higher than the retail rate, causing severe losses
to the IOUs and, in the case of PG&E, bankruptcy.
The process through which California IOUs will now procure electricity
for their customers, although subject to CPUC implementation and regulation,
will be akin to the methods used prior to deregulation. The IOUs will be
required to submit to the CPUC a procurement plan that details how the IOU
intends to procure energy from a diversified portfolio of generating resources,
including renewable generators, and using contracts terms of varying lengths,
including short-term and long-term contracts. The IOUs procurement plans are
subject to CPUC approval. The CPUC, among other things, is required to develop a
process for evaluating the IOUs procurement plans as well as criteria for
evaluating individual energy contracts. The CPUC is currently engaged in the
rule-making process that will implement these and many other requirements of the
legislation.
As this legislation described above indicates, the trend in the
industry, appears to be a reversion to a more regulated electric industry, with
reporting requirements and regulatory oversight and review. In any event, these
market changes do not significantly impact upon the Monterey Project, which
currently has a Power Contract with PG&E, although market changes which
strengthen PG&E benefit the Monterey Project over the long term by ensuring
PG&E's ability to pay under such Power Contract.
(5) Competition
After the Power Contract expires in 2020 or terminates for other
reasons, the Monterey Project under currently anticipated conditions would be
free to sell its output on the competitive electric supply market, either in
spot, auction or short-term arrangements or under long-term contracts if those
Power Contracts could be obtained. There is no assurance that the Project could
sell its output or do so profitably. Because the Project is fueled by natural
gas normally purchased at market prices and because the Project is relatively
small-scale, it might have cost disadvantages in competing against larger
competitors that would enjoy economies of scale. The Trust is unable to
anticipate whether thermal sales from cogeneration would offset any possible
cost disadvantages in electric generation or whether in fact the Project would
have cost disadvantages after the Power Contract ends in 2020. It is thus
impossible to predict the profitability of the Project after the scheduled
termination of the Power Contract.
There are a large number of participants in the independent power
industry. Several large corporations specialize in developing, building and
operating Independent Power Projects. Equipment manufacturers, including many of
the largest corporations in the world, provide equipment and planning services
and provide capital through finance affiliates. In addition, there are many
smaller firms whose businesses are conducted primarily on a regional or local
basis. Many of these companies focus on limited segments of the cogeneration and
independent power industry and do not provide a wide range of products and
services. There is significant competition among non-utility producers,
subsidiaries of utilities and utilities themselves in developing and operating
energy-producing projects and in marketing the power produced by such projects.
The Trust is unable to accurately estimate the number of competitors
but believes that there are many competitors at all levels and in all sectors of
the industry. Many of those competitors, especially affiliates of utilities and
equipment manufacturers, may be far better capitalized than the Trust.
(6) Regulatory Matters.
Projects are subject to energy and environmental laws and regulations
at the federal, state and local levels in connection with development,
ownership, operation, geographical location, zoning and land use of a Project
and emissions and other substances produced by a Project. These energy and
environmental laws and regulations generally require that a wide variety of
permits and other approvals be obtained before the commencement of construction
or operation of an energy-producing facility and that the facility then operates
in compliance with such permits and approvals.
(i) Energy Regulation.
(i) Energy Regulation.
(A) PURPA. The enactment in 1978 of PURPA and the adoption of
regulations thereunder by FERC provided incentives for the development of
cogeneration facilities and small power production facilities meeting certain
criteria. QFs under PURPA are generally exempt from the provisions of the Public
Utility Holding Company Act of 1935, as amended (the "Holding Company Act"), the
Federal Power Act, as amended (the "FPA"), and, except under certain limited
circumstances, from state laws regarding rate or financial regulation. In order
to be a QF, a cogeneration facility must (a) produce not only electricity but
also a certain quantity of heat energy (such as steam) which is used for a
purpose other than power generation, (b) meet certain energy efficiency
standards when natural gas or oil is used as a fuel source and (c) not be
controlled or more than 50% owned by an electric utility or electric utility
holding company. Other types of Independent Power Projects, known as "small
power production facilities," can be QFs if they meet regulations respecting
maximum size (in certain cases), primary energy source and utility ownership.
The exemptions from extensive federal and state regulation afforded by
PURPA to QFs are important to the Trust and its competitors. The Trust believes
that each of its Projects is a QF. If a Project loses its QF status, the utility
can reclaim payments it made for the Project's non-qualifying output to the
extent those payments are in excess of current avoided costs or the Project's
Power Contract can be terminated by the electric utility.
(B) The 1992 Energy Act. The Comprehensive Energy Policy Act of 1992
(the "1992 Energy Act") empowered FERC to require electric utilities to make
available their transmission facilities to and wheel power for Independent Power
Projects under certain conditions and created an exemption for electric
utilities, electric utility holding companies and other independent power
producers from certain restrictions imposed by the Holding Company Act. Although
the Trust believes that the exemptive provisions of the 1992 Energy Act will not
materially and adversely affect its business plan, the 1992 Energy Act may
result in increased competition in the sale of electricity.
(C) The Federal Power Act. The FPA grants FERC exclusive rate-making
jurisdiction over wholesale sales of electricity in interstate commerce. Again,
this will not affect the Trust's Projects unless they were to attempt sales to
other customers.
(D) Fuel Use Act. Projects may also be subject to the Fuel Use Act,
which limits the ability of power producers to burn natural gas in new
generation facilities unless such facilities are also coal-capable within the
meaning of the Fuel Use Act. The Trust believes that the Monterey Project is
coal-capable and thus qualifies for exemption from the Fuel Use Act.
(E) State Regulation. State public utility regulatory commissions have
broad jurisdiction over Independent Power Projects which are not QFs under
PURPA, and which are considered public utilities in many states. In states where
the wholesale or retail electricity market remains regulated, Projects that are
not QFs may be subject to state requirements to obtain certificates of public
convenience and necessity to construct a facility and could have their
organizational, accounting, financial and other corporate matters regulated on
an ongoing basis. Although FERC generally has exclusive jurisdiction over the
rates charged by a non-QF to its wholesale customers, state public utility
regulatory commissions have the practical ability to influence the establishment
of such rates by asserting jurisdiction over the purchasing utility's ability to
pass through the resulting cost of purchased power to its retail customers. In
addition, states may assert jurisdiction over the siting and construction of
non-QFs and, among other things, issuance of securities, related party
transactions and sale and transfer of assets. The actual scope of jurisdiction
over non-QFs by state public utility regulatory commissions varies from state to
state.
(ii) Environmental Regulation.
The construction and operation of Independent Power Projects are
subject to extensive federal, state and local laws and regulations adopted for
the protection of human health and the environment and to regulate land use. The
laws and regulations applicable to the Trust and Projects in which it invests
primarily involve the discharge of emissions into the water and air and the
disposal of waste, but can also include wetlands preservation and noise
regulation. These laws and regulations in many cases require a lengthy and
complex process of renewing licenses, permits and approvals from federal, state
and local agencies. Obtaining necessary approvals regarding the discharge of
emissions into the air is critical to the development of a Project and can be
time-consuming and difficult. Each Project requires technology and facilities
that comply with federal, state and local requirements, which sometimes result
in extensive negotiations with regulatory agencies. Meeting the requirements of
each jurisdiction with authority over a Project may require modifications to
existing Projects.
The Trust's Projects must comply with many federal and state laws and
regulations governing wastewater and storm water discharges from the Projects.
These are generally enforced by states under permits for point sources of
discharges and by storm water permits. Under the Clean Water Act, such permits
must be renewed every five years and permit limits can be reduced at that time
or under re-opener clauses at any time. The Projects have not had material
difficulty in complying with their permits or obtaining renewals. The Projects
use closed-loop engine cooling systems, which do not require large discharges of
coolant except for periodic flushing to local sewer systems under permit and do
not make other material discharges to groundwater or streams.
The Berkshire Project is not a QF and does not generate electricity.
However, it was operating prior to November 15, 1990 and is thus currently
exempt from the requirement to obtain sulfur dioxide allowances.
The Trust's Monterey, Berkshire and Columbia Projects are subject to
the reporting requirements of the Emergency Planning and Community Right-to-Know
Act that require the Projects to prepare toxic release inventory release forms.
These forms list all toxic substances on site that are used in excess of
threshold levels so as to allow governmental agencies and the public to learn
about the presence of those substances and to assess potential hazards and
hazard responses. The Trust does not anticipate that this will result in any
material adverse effect on it.
The Managing Shareholder expects that environmental and land use
regulations may become more stringent. The Trust and the Managing Shareholder
have developed a certain expertise and experience in obtaining necessary
licenses, permits and approvals, but will nonetheless rely upon qualified
environmental consultants and environmental counsel retained by it to assist in
evaluating the status of Projects regarding such matters.
(iii) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not
limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are
subject to amendment or repeal. Future legislation and regulation is uncertain,
and could have material effects on the Trust.
(d) Financial Information about Foreign and Domestic Operations and Export
Sales.
The Trust has invested in Projects located in California, Massachusetts
and New York and has no foreign operations.
(e) Employees.
The operating personnel of the Monterey and Pumping Projects are
employed by RPM and accordingly the Trust has no employees. The persons
described below at Item 10 - Directors and Executive Officers of the Registrant
serve as executive officers of the Trust and have the duties and powers usually
applicable to similar officers of a Delaware corporation in carrying out the
Trust business.
Item 2. Properties.
Pursuant to the Management Agreement between the Trust and the Managing
Shareholder (described at Item 10(c) - Directors and Executive Officers of the
Registrant - Management Agreement), the Managing Shareholder provides the Trust
with office space at the Managing Shareholder's principal office at The
Ridgewood Commons, 947 Linwood Avenue, Ridgewood, New Jersey 07450.
The following table shows the material properties (relating to
Projects) owned or leased by the Trust's subsidiaries or partnerships in which
the Trust has an equity interest. Ownership rights to the property associated
with the Berkshire Project are held under a long-term lease-purchase agreement
and related non-recourse industrial revenue bond financing agreements among
Pittsfield's industrial development authority and others. Upon repayment of the
bonds and the satisfaction of other conditions, the partnership which operates
the facility and in which the Trust owns an interest, will have the option to
acquire the facility for nominal consideration. The other properties are not
subject to any mortgages, liens or encumbrances. All of the Projects are
described in further detail at Item 1(c)(2).
Square
Ownership Ground Approximate Footage of Description
Interests Lease Acreage Project(Actual of
Project Location in Land Expiration of Land or Projected) Project
Monterey Monterey, Gas-fired cogen
CA Leased 2020 2 10,000 eration facility
Pumping Ventura Cy, Leased N/A N/A N/A Natural gas
Project CA or engines powering
licensed irrigation pumps
Item 3. Legal Proceedings.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
(a) Market Information.
The Trust sold 235.3775 Investor Shares of beneficial interest in the
Trust in its private placement offering of Investor Shares, which closed on
January 31, 1994. There is currently no established public trading market for
the Investor Shares. As of the date of this Form 10-K, all such Investor Shares
have been issued and are outstanding. There are no outstanding options or
warrants to purchase, or securities convertible into, Investor Shares.
Investor Shares are restricted as to transferability under the
Declaration, and are restricted under federal and state laws regulating
securities when the Investor Shares are held by persons in a control
relationship with the Trust. Investors wishing to transfer Investor Shares
should also consider the applicability of state securities laws. The Investor
Shares have not been and are not expected to be registered under the Securities
Act of 1933, as amended (the "1933 Act"), or under any other similar law of any
state in reliance upon what the Trust believes to be exemptions from the
registration requirements contained therein. Because the Investor Shares have
not been registered, they are "restricted securities" as defined in Rule 144
under the 1933 Act.
The Managing Shareholder has investigated the possibility and
feasibility of a combination of the Other Power Trusts and the Ridgewood LLCs
into a publicly traded entity. This would require the approval of the Investors
in the Trust and the other programs after proxy solicitations, complying with
requirements of the Securities and Exchange Commission, and a change in the
federal income tax status of the Trust from a partnership (which is not subject
to tax) to a corporation. The process of considering and effecting a
combination, if the decision is made to do so, will be very lengthy. There is no
assurance that the Managing Shareholder will recommend a combination, that the
Investors of the Trust or other programs will approve it, that economic
conditions or the business results of the participants will be favorable for a
combination, that the combination will be effected or that the economic results
of a combination, if effected, will be favorable to the Investors of the Trust,
Other Power Trusts and the Ridgewood LLCs. After conducting investigations
during 2001, the Managing Shareholder concluded, and informed the Investors,
that given current market conditions caused by, among other things, the general
U.S. economic down turn, the September 11th terrorist attacks, the Enron
bankruptcy and general volatility in the independent power business, it is
preferable to delay significant expenditures pursuing any such combination until
market conditions, as described above, improve.
(b) Holders
As of the date of this Form 10-K, there are 483 record holders of
Investor Shares.
(c) Dividends
The Trust made distributions as follows for the years ended December 31,
2002 and 2001:
Year Ended Year ended
December 31, December 31,
2002 2001
Total distributions to Investors $823,824 $ --
Distributions per Investor Share $3,500 $ --
Distributions to Managing Shareholder $8,321 $ --
The Trust's decision whether to make future distributions to Investors
and their timing will depend on, among other things, the net cash flow of the
Trust and retention of reasonable reserves as determined by the Trust to cover
its anticipated expenses. See Item 7 Management's Discussion and Analysis.
Occasionally, distributions may include funds derived from the release
of cash from operating or restricted cash. Further, the Declaration authorizes
distributions to be made from cash flows rather than income, or from cash
reserves in some instances. For purposes of generally accepted accounting
principles, amounts of distributions in excess of accounting income may be
considered to be capital in nature. Investors should be aware that the Trust is
organized to return net cash flow rather that accounting income to Investors.
Item 6. Selected Financial Data.
The following data is qualified in its entirety by the financial
statements presented elsewhere in this Annual Report on Form 10-K. The selected
financial data for 1998 are derived from unaudited data.
Selected Financial Data
As of and for the year ended December 31,
2002 2001 2000 1999 1998
Total Fund Information:
Revenues $3,075,114 $2,374,396 3,530,580 2,507,166 2,184,036
Net income (loss) 255,529 (1,088,887) 218,437 (203,368) (1,617,920)
(A)
Net assets
(shareholders'
equity) 7,227,155 7,803,731 8,892,618 9,388,247 9,876,924
Investments in
Plant and
Equipment (net
of depreciation) 1,798,352 2,003,302 2,221,614 2,446,494 2,654,809
Investment
in Power
Contract(net
of amortization) 2,061,760 2,183,040 2,304,320 2,425,600 2,546,880
Total assets 7,512,445 8,216,155 9,595,529 10,311,744 10,597,576
Long-term
Obligations -- -- -- -- --
Per Share:
Revenues 13,065 10,087 15,000 10,652 9,279
Net income(loss) 1,086 (4,626) 928 (864) (6,873)
(A)
Net asset value 30,704 33,154 38,163 39,886 41,962
Distributions
to Investors 3,500 -- 3,003 1,200 6,000
(A) Includes writedown of investment of $2,347,330 ($9,973 per Investor Share).
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Introduction
The following discussion and analysis should be read in conjunction
with the Trust's financial statements and the notes thereto presented below.
Dollar amounts in this discussion are generally rounded to the nearest $1,000.
Outlook
The Monterey Project is a QF as defined by PURPA and currently sells
its electric output to PG&E under a Power Contract expiring in 2020. During the
term of the Power Contract, the utility may or may not attempt to buy out the
Power Contract prior to expiration. At the end of the Power Contract, the
Monterey Project will become a merchant plant and may be able to sell the
electric output at then current market prices. There can be no assurance that
future market prices will be sufficient to allow the Monterey Project to operate
profitably. See Item 1(c)(3) - Plant Operations for information concerning a
potential challenge to the Project's Power Contract.
The Berkshire Project receives revenue in the form of tipping fees for
waste delivered to the facility and from steam sold under a long-term contract,
which expires in 2004. Tipping fees are based on spot market prices, which may
fluctuate from time to time. The Project's steam customer may or may not extend
its purchases beyond the year 2004.
The Columbia Project receives revenue in the form of tipping fees for
waste delivered to the facility by local waste haulers and transferred to long
haul trucks for delivery to distant landfills. The Project's profit margins are
affected by the level of competition from national waste management companies
operating in the same region and the availability of other sources of waste
disposal.
The Pumping Project owns irrigation well pumps in Ventura County,
California, which supply water to farmers. The demand for water pumped by the
project varies inversely with rainfall in the area.
Additional trends affecting the independent power industry generally
are described at Item 1 - Trends Affecting the Electric Utility and Independent
Power Industries.
Significant Accounting Policies
The Trust's plant and equipment is recorded at cost and is depreciated
over its estimated useful life. The estimate useful lives of the Trust's plant
and equipment range from 3 to 20 years. A significant decrease in the estimated
useful life of a material amount of plant and equipment could have a material
adverse impact on the Trust's operating results in the period in which the
estimate is revised and subsequent periods. The Trust evaluates the impairment
of its long-lived assets (including power sales contracts) based on projections
of undiscounted cash flows whenever events or changes in circumstances indicate
that the carrying amounts of such assets may not be recoverable. Estimates of
future cash flows used to test the recoverability of specific long-lived assets
are based on expected cash flows from the use and eventual disposition of the
assets. A significant reduction in actual cash flows and estimated cash flows
may have a material adverse impact on the Trust's operating results and
financial condition.
Results of Operations
The year ended December 31, 2002 compared to the year ended December
31, 2001. Power generation revenue increased $704,000, or 30 %, to $3,075,000 in
2002 compared to $2,3748,000 in 2001. The increase is primarily due to the
Monterey project operating on its normal schedule in 2002 as compared to 2001
when the plant was idle from February to August due to PG&E's failure to pay the
project for power delivered since December 1, 2000, as a result of the
California energy crisis.
Gross profit, which represents total revenues reduced by cost of sales,
increased by $96,000 to a gross profit of $144,000 in 2002 from a gross loss of
$460,000 in 2001. The increase is a result of an increase in energy generation.
General and administrative expenses decreased $81,000, or 24%, to $258,000
in 2002 from $339,000 in 2001. The decrease primarily reflects the legal costs
associated with the Monterey Project's dispute with PG&E that ended in 2001 with
a favorable result for the project.
The $127,000 of bad debt expense in 2001 is associated with the sale of the
Monterey Project's PG&E receivables to AMROC. In 2002, the Trust recovered
$157,000 relating to prior year PG&E revenues.
The management fee paid to the Managing Shareholder decreased by
$60,000, or 34%, to $117,000 in 2002 from $177,000 reflecting the lower net
assets of the Trust.
Loss from operations decreased $1,030,000, or 93%, to $74,000 in 2002
from $1,104,000 in 2001 as a result of the increase in revenues and the decrease
in operating expenses.
Other income, net, increased by $314,000, to $329,000 in 2002 from
$15,000 in 2001. The increase is primarily due to the $190,000 of cash received
in 2002 from the 1999 settlement of the Waukesha-Pierce litigation, as well as
the costs incurred in 2001 in issuing the "Notice of Solicitation of Consents"
to investors.
Net income increased $1,296,000,to $207,000 in 2002 from a net loss of
$1,089,000 in 2001. The increase in income is a result of the increase in
revenues and the decrease in operating expenses.
The year ended December 31, 2001 compared to the year ended December 31, 2000.
Total revenues decreased $1,157,000, or 33%, to $2,374,000 in 2001 from
$3,531,000 in 2000. The decrease in revenues is due primarily to the shut down
of the Monterey Project from February to August 2001 due to the PG&E's
non-payment of amounts owed to the project (see Item 1(c)iii). The decrease in
revenues from the Monterey Project was partially offset by an increase of
$170,000 of revenues from the Pumping Project due to higher prices.
Gross profit, which represents total revenues reduced by cost of sales,
decreased by $1,127,000 to a gross loss of $460,000 in 2001 from a gross profit
of $667,000 in 2000. The decrease in gross profit primarily reflects the
decrease in revenues discussed above. Cost of sales did not decrease
significantly despite the shut down on the plant for almost six months because
the price of natural gas was substantially higher in 2001 compared to 2000.
General and administrative expenses decreased $175,000, or 34%, to
$339,000 in 2001 from $514,000 in 2000. The decrease primarily reflects lower
legal costs associated with the litigation with PG&E related to the Monterey
Project.
Provision for bad debt expense decreased $117,000 to $127,000 in 2001 from
$244,000 in 2000. The bad debt expense for both periods reflects the loss
recognized on the sale of the Monterey Project's PG&E receivables to AMROC.
The management fee paid to the Managing Shareholder was $177,000 in
2001. In 2000, the Managing Shareholder had waived the management fee.
The loss from operations increased $1,012,000 to $1,103,000 in 2001
from $91,000 in 2000, which primarily reflects the decline in the Monterey
Project's results as well as the increase in the management fee.
Other income, net, decreased by $295,000 or 79%, to $14,000 in 2001
from $309,000 in 2000. The decrease is primarily due to a $164,000 decrease in
the Trust's equity income in the Columbia Project and a $106,000 increase in
other expenses. The decrease in income from the Columbia Project was primarily
the result of decreasing margins from the project caused by capacity expansions
at nearby competing landfills. The increase in the other expenses primarily
related to the costs incurred in issuing the "Notice of Solicitation of
Consents."
The Trust recorded net income of $218,000 in 2000 compared to a net
loss of $1,089,000 in 2001, a change of $1,307,000. This primarily reflects the
deterioration in results from the Monterey Project, as well as the increased
management fees and the reduction in other income, net.
Liquidity and Capital Resources
In 2002, the Trust's operating activities provided $81,000 of cash as
compared to a cash usage of $674,000 in 2001.
Cash generated from investing activities in 2002 was $1,925,000
compared to $676,000 in 2001. The increase is due to the $1,224,000 received
from the transfer of the B-3 and PILP projects.
Cash used by financing activities of $832,000 in 2002 represents
distributions to shareholders. The Trust did not make distributions to
shareholders in 2001.
During the fourth quarter of 1997, the Trust and its principal bank
executed a revolving line of credit agreement, whereby the bank provided a three
year committed line of credit facility of $750,000. The credit facility was
extended until July 31, 2002. During the third quarter of 2002, the Trust
extended its revolving line of credit agreement with its principal bank through
August 31, 2002 and subsequently finalized a further extension until July 31,
2003. The extension provides the Trust with a committed line of credit of
$550,000. Outstanding borrowings bear interest at LIBOR plus 2.5% (3.882% and
4.376% at December 31, 2002 and 2001, respectively). The amount outstanding
under the line of credit facility must be reduced to zero for a thirty-day
period each year. The credit agreement requires the Trust to provide 100% cash
collateral for any borrowings or letters of credit outstanding after September
30, 2002. There were no outstanding borrowings at December 31, 2002 and 2001.
In August 2001, the Trust issued through its bank a standby letter of
credit in the amount of $504,000 to secure the gas purchases of the Monterey
project. The letter of credit expired in August 2002. The Trust used its credit
facility and a restricted certificate of deposit in the amount of $202,570 to
collateralize the letter of credit, which is presented as restricted cash on the
Consolidated Balance Sheets at December 31, 2001. In October 2002, the Trust
increased the amount of the certificate of deposit to $550,000.
Obligations of the Trust are generally limited to payment of a
management fee to the Managing Shareholder and payments for certain
administrative, accounting and legal services to third persons. Accordingly, the
Trust has not found it necessary to retain a material amount of working capital.
The Monterey Project has certain long-term obligations relating to its
Power Contract with PG&E and its Gas Agreement with Coral (See Note 6 of the
Consolidated Financial Statements). These long-term obligations are not
guaranteed by the Trust. The Trust and its subsidiaries anticipate that during
2003 their cash flow from operations will be sufficient to meet their
obligations.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Qualitative Information About Market Risk.
The Trust's investments in financial instruments are short-term investments of
working capital or excess cash. Those short-term investments are limited by its
Declaration of Trust to investments in United States government and agency
securities or to obligations of banks having at least $5 billion in assets.
Because the Trust invests only in short-term instruments for cash management,
its exposure to interest rate changes is low. The Trust has limited exposure to
trade accounts receivable and believes that their carrying amounts approximate
fair value.
The Trust's primary market risk exposure is limited interest rate risk caused
by fluctuations in short-term interest rates. The Trust does not anticipate any
changes in its primary market risk exposure or how it intends to manage it. The
Trust does not trade in market risk sensitive instruments.
Quantitative Information About Market Risk
This table provides information about the Trust's financial instruments that
are defined by the Securities and Exchange Commission as market risk sensitive
instruments. These include only short-term U.S. government and agency securities
and bank obligations. The table includes principal cash flows and related
weighted average interest rates by contractual maturity dates.
December 31, 2002
Expected Maturity Date
2003
(U.S. $)
Note receivable from NRG $ 278,000
Interest rate 8%
December 31, 2002
Expected Maturity Date
2003
(U.S. $)
Bank Deposits and Certificates of Deposit $1,349,000
Average interest rate 1.04%
Item 8. Financial Statements and Supplementary Data.
A. Index to Consolidated Financial Statements
Index to Consolidated Financial Statements
Report of Independent Accountants F-2
Consolidated Balance Sheets at December 31,
2002 and 2001 F-3
Consolidated Statements of Operations for the
three years ended December 31, 2002 F-4
Consolidated Statements of Changes in
Shareholders' Equity for the three years
ended December 31, 2002 F-5
Consolidated Statements of Cash Flows for the three
years ended December 31, 2002 F-6
Notes to Consolidated Financial Statements F-7 to F-15
B. Supplementary Financial Information
Selected Quarterly Financial Data for the years ended December 31, 2002 and 2001
(Unaudited)
2002
- --------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
Revenue ................ $ 737,000 $ 771,000 $ 900,000 $ 667,000
Income (loss)
from operations ........ (22,000) (17,000) 27,000 (62,000)
Net income (loss) ...... (69,000) 281,000 (23,000) 67,000
2001
- --------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
Revenue ............ $ 375,000 $ 275,000 $ 613,000 $ 1,111,000
Loss from operations (290,000) (295,000) (330,000) (189,000)
Net loss ........... (350,000) (187,000) (306,000) (246,000)
Report of Independent Accountants
To the Shareholders of Ridgewood Electric Power Trust II:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in shareholders' equity and cash
flows present fairly, in all material respects, the financial position of
Ridgewood Electric Power Trust II and its subsidiaries (the "Trust") at December
31, 2002 and 2001, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2002, in conformity
with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Trust's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Florham Park, NJ
April 3, 2003
Ridgewood Electric Power Trust II
Consolidated Balance Sheets
- --------------------------------------------------------------------------------
December 31,
---------------------------
2002 2001
----------- -----------
Assets:
Cash and cash equivalents ...................... $ 1,348,825 $ 175,403
Restricted cash ................................ 550,000 202,570
Trade receivables .............................. 255,082 267,870
Current portion of note
receivable from sale of investment ............ 277,528 522,938
Due from affiliates ............................ 14,512 20,200
Other current assets ........................... 47,151 35,909
----------- -----------
Total current assets .................... 2,493,098 1,224,890
Investment in B-3 Limited Partnership .......... -- 2,527,395
Note receivable from transfer of
investment in Limited Partnership
interests under contractual agreements ........ 1,207,795 --
Plant and equipment ............................ 3,441,432 3,419,000
Accumulated depreciation ....................... (1,643,080) (1,415,698)
----------- -----------
1,798,352 2,003,302
----------- -----------
Electric power sales contract .................. 3,032,000 3,032,000
Accumulated amortization ....................... (970,240) (848,960)
----------- -----------
2,061,760 2,183,040
----------- -----------
Note receivable from sale of
investment, less current portion .............. -- 277,528
----------- -----------
Total assets ........................... $ 7,561,005 $ 8,216,155
----------- -----------
Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable ............................... $ 156,036 $ 7,334
Accrued fuel expense ........................... 71,833 167,399
Accrued professional fees ...................... 58,138 55,476
Due to affiliates .............................. 47,883 182,215
----------- -----------
Total current liabilities ............. 333,890 412,424
Commitments and contingencies .................. -- --
Shareholders' Equity:
Shareholders' equity (235.3775 investor
shares issued and outstanding) ................ 7,356,088 7,926,938
Managing shareholder's accumulated deficit
(1 management share issued and outstanding) ... (128,973) (123,207)
----------- -----------
Total shareholders' equity ............ 7,227,115 7,803,731
----------- -----------
Total liabilities and
shareholders' equity ................. $ 7,561,005 $ 8,216,155
----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II
Consolidated Statements of Operations
- --------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------
2002 2001 2000
----------- ----------- -----------
Power generation revenue .......... $ 3,075,114 $ 2,374,396 $ 3,530,580
Cost of sales, including
depreciation and
amortization of $348,662,
$346,209 and $347,693 in
2002, 2001 and 2000 ............. 2,931,122 2,834,668 2,863,841
----------- ----------- -----------
Gross profit (loss) ............... 143,992 (460,272) 666,739
General and administrative
expenses ........................ 257,739 338,815 513,667
Provision for bad debt
(recoveries) expense ............. (156,938) 127,130 244,169
Management fee paid to
managing shareholder ............. 117,058 177,337 --
----------- ----------- -----------
Total other operating
expenses ................... 217,859 643,282 757,836
----------- ----------- -----------
Loss from operations .............. (73,867) (1,103,554) (91,097)
----------- ----------- -----------
Other income (expense):
Interest income ................ 56,641 99,848 134,135
Interest expense ............... (3,506) -- (9,063)
Equity income from B-3
Limited Partnership .......... 104,497 43,459 207,339
Other income .................. 190,331 -- --
Other expense ................. (18,567) (128,640) (22,877)
----------- ----------- -----------
Other income (expense), net .. 329,396 14,667 309,534
----------- ----------- -----------
Net income (loss) ................. $ 255,529 $(1,088,887) $ 218,437
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II
Consolidated Statements of Changes in Shareholders' Equity
For the Years Ended December 31, 2002, 2001 and 2000
- --------------------------------------------------------------------------------
Managing
Shareholders Shareholder Total
----------- ----------- -----------
Shareholders' equity,
January 1, 2000 ............ $ 9,495,608 $ (107,361) $ 9,388,247
Cash distributions .......... (706,925) (7,141) (714,066)
Net income for the year ..... 216,253 2,184 218,437
----------- ----------- -----------
Shareholders' equity,
December 31, 2000 ......... 9,004,936 (112,318) 8,892,618
Net loss for the year ....... (1,077,998) (10,889) (1,088,887)
----------- ----------- -----------
Shareholders' equity,
December 31, 2001 .......... 7,926,938 (123,207) 7,803,731
Cash distributions .......... (823,824) (8,321) (832,145)
Net income for the year ..... 252,974 2,555 255,529
----------- ----------- -----------
Shareholders' equity,
December 31, 2002 .......... $ 7,356,088 $ (128,973) $ 7,227,115
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II
Consolidated Statements of Cash Flows
- --------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------
2002 2001 2000
----------- ----------- -----------
Cash flows from operating
activities:
Net income (loss) ............ $ 255,529 $(1,088,887) $ 218,437
----------- ----------- -----------
Adjustments to reconcile net
income (loss) to net cash
flows from operating
activities:
Depreciation and amortization 348,662 346,209 347,693
Provision for doubtful
accounts .................... -- -- 244,169
Equity in earnings from
unconsolidated B-3 Limited
Partnership .............. (104,497) (43,459) (207,339)
Changes in assets and
liabilities:
Increase in restricted cash (347,430) (202,570) --
Decrease (increase) in
trade receivable .......... 12,788 634,802 (773,933)
Increase in other current
assets .................... (11,242) (15,477) (2,509)
Increase (decrease) in
accounts payable and
accrued expenses .......... 148,702 (14,425) 61,371
Increase in accrued
professional fees ......... 2,662 -- --
Decrease in accrued fuel
expense ................... (95,566) (134,228) --
(Decrease) increase in
due to/from affiliates,net (128,644) (155,860) 111,870
----------- ----------- -----------
Total adjustments ........ (174,565) 414,992 (218,678)
----------- ----------- -----------
Net cash provided by
(used in)operating
activities .............. 80,964 (673,895) (241)
----------- ----------- -----------
Cash flows from investing
activities:
Distributions from B-3
Limited Partnership ......... 200,000 200,000 300,000
Cash received from transfer
of investments, net ......... 1,224,097 -- --
Proceeds from note
receivable .................. 522,938 482,861 445,853
Capital expenditures ......... (22,432) (6,617) (1,533)
----------- ----------- -----------
Net cash provided by
investing activities .... 1,924,603 676,244 744,320
----------- ----------- -----------
Cash flows from financing
activities:
Repayments under line
of credit facility ......... -- -- (400,000)
Cash distributions to
shareholders ............... (832,145) -- (714,066)
----------- ----------- -----------
Net cash used in
financing activities .... (832,145) -- (1,114,066)
----------- ----------- -----------
Net increase in cash
and cash equivalents ............. 1,173,422 2,349 (369,987)
Cash and cash equivalents,
beginning of year ................ 175,403 173,054 543,041
----------- ----------- -----------
Cash and cash equivalents,
end of year ...................... $ 1,348,825 $ 175,403 $ 173,054
----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II
Notes to Consolidated Financial Statements
- --------------------------------------------------------------------------------
1. Organization and Purpose
Nature of business
Ridgewood Electric Power Trust II (the "Trust") was formed as a Delaware
business trust on November 20, 1992, by Ridgewood Energy Holding Corporation
acting as the Corporate Trustee. The managing shareholder of the Trust is
Ridgewood Power LLC (formerly Ridgewood Power Corporation). The Trust began
offering shares on January 4, 1993 and discontinued its offering of shares on
January 31, 1994.
The Trust was organized to invest in independent power generation facilities and
in the development of these facilities. These independent power generation
facilities include cogeneration facilities which produce electricity and thermal
energy and other power plants that use various fuel sources (except nuclear).
The power plants sell electricity and, in some cases, thermal energy to
utilities and industrial users under long-term contracts.
Ridgewood Energy Holding Corporation, a Delaware corporation, is the Corporate
Trustee of the Trust. The Corporate Trustee acts on the instructions of the
Managing Shareholder and is not authorized to take independent discretionary
action on behalf of the Trust.
"Business Development Company"
Effective April 29, 1993, the Trust elected to be treated as a "business
development company" ("BDC") under the Investment Company Act of 1940 ("the 1940
Act") and registered its shares under the Securities Exchange Act of 1934.
In November 2001, through a proxy solicitation the Trust requested investor
consent to end the BDC status. On January 7, 2002, the consents were tabulated
and more than two-thirds of the investor shares consented to the elimination of
the BDC status. Accordingly, the Trust is no longer an investment company under
the 1940 Act.
2. Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of the Trust and its
controlled subsidiaries. All material intercompany transactions have been
eliminated.
The Trust uses the equity method of accounting for its investments in affiliates
which are 50% or less owned if the Trust has the ability to exercise significant
influence over the operating and financial policies of the affiliates but does
not control the affiliate. The Trust's share of the operating results of the
affiliates is included in the Consolidated Statements of Operations.
Critical accounting policies and estimates
The preparation of consolidated financial statements requires the Trust to make
estimates and judgements that affect the reported amounts of assets,
liabilities, sales and expenses, and related disclosure of contingent assets and
liabilities. On an on-going basis, the Trust evaluates its estimates, including
provision for bad debts, carrying value of investments,
amortization/depreciation of plant and equipment and intangible assets, and
recordable liabilities for litigation and other contingencies. The Trust bases
its estimates on historical experience, current and expected conditions and
various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgements about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates under different
assumptions or conditions.
New Accounting Standards and Disclosures
SFAS 141
In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") 141, Business Combinations, which
eliminates the pooling-of-interest method of accounting for business
combinations and requires the use of the purchase method. In addition, SFAS 141
requires the reassessment of intangible assets to determine if they are
appropriately classified either separately or within goodwill. SFAS 141 is
effective for business combinations initiated after June 30, 2001. The Trust
adopted SFAS 141 on July 1, 2001, with no material impact on the consolidated
financial statements.
SFAS 142
In June 2001, the FASB issued SFAS 142, Goodwill and Other Intangible Assets,
which eliminates the amortization of goodwill and other acquired intangible
assets with indefinite economic useful lives. SFAS 142 requires an annual
impairment test of goodwill and other intangible assets that are not subject to
amortization. Other intangible assets with definite economic lives will continue
to be amortized over their useful lives. The Trust adopted SFAS 142 effective
January 1, 2002, with no material impact on the consolidated financial
statements.
SFAS 143
In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations, on the accounting for obligations associated with the retirement of
long-lived assets. SFAS 143 requires a liability to be recognized in the
consolidated financial statements for retirement obligations meeting specific
criteria. Measurement of the initial obligation is to approximate fair value,
with an equivalent amount recorded as an increase in the value of the
capitalized asset. The asset will be depreciated in accordance with normal
depreciation policy and the liability will be increased for the time value of
money, with a charge to the income statement, until the obligation is settled.
SFAS 143 is effective for fiscal years beginning after June 15, 2002. The Trust
will adopt SFAS 143 effective January 1, 2003 and has assessed that this
standard will not have a material impact on the Trust.
SFAS 144
In August 2001, the FASB issued SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, which replaces SFAS 121, Accounting for the
Impairment of Long-lived Assets and for Long-Lived Assets to Be Disposed Of. For
long-lived assets to be held and used, SFAS 144 retains the requirements of SFAS
121 to (a) recognize an impairment loss only if the carrying amount is not
recoverable from undiscounted cash flows and (b) measure an impairment loss as
the difference between the carrying amount and fair value of the asset. For
long-lived assets to be disposed of, SFAS 144 establishes a single accounting
model based on the framework established in SFAS 121. The accounting model for
long-lived assets to be disposed of by sale applies to all long-lived assets,
including discontinued operations and replaces the provisions of APB Opinion No.
30, Reporting the Results of Operations - Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions, for the disposal of segments of a business. SFAS 144
also broadens the reporting of discontinued operations. The Trust adopted SFAS
144 effective January 1, 2002, with no material impact on the consolidated
financial statements.
SFAS 145
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Correction.
SFAS No. 145 eliminates extraordinary accounting treatment for reporting gain or
loss on debt extinguishment, and amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings, or
describe their applicability under changed conditions. The Trust will adopt SFAS
145 effective January 1, 2003 and has determined that this standard will not
have a material impact on the Trust.
SFAS 146
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. SFAS No. 146 requires recording costs associated
with exit or disposal activities at their fair values when a liability has been
incurred. The Trust will adopt SFAS 146 effective January 1, 2003 and has
determined that this standard will not have a material impact on the Trust.
FIN 45
In November 2002, the FASB issued FASB Interpretation No. 45 ("FIN 45"),
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees and Indebtedness of Others." FIN 45 elaborates on the
disclosures to be made by the guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also requires that a guarantor recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002; while the provisions of the disclosure
requirements are effective for financial statements of interim or annual reports
ending after December 15, 2002. The Trust adopted the disclosure provisions of
FIN 45 during the fourth quarter of 2002 with no material impact to the
consolidated financial statements.
FIN 46
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities" ("FIN 46") which changes the criteria by which one
company includes another entity in its consolidated financial statements. FIN 46
requires a variable interest entity to be consolidated by a company if that
company is subject to a majority of the risk of loss from the variable interest
entity's activities or entitled to receive a majority of the entity's residual
returns or both. The consolidation requirements of FIN 46 apply immediately to
variable interest entities created after January 31, 2003, and apply in the
first fiscal period beginning after June 15, 2003, for variable interest
entities created prior to February 1, 2003. The Trust will adopt the disclosure
provisions of FIN 46 effective June 15, 2003 and has determined that the
adoption will not have a material impact on the Trust's consolidated financial
statements.
Cash and cash equivalents
The Trust considers all highly liquid investments with maturities when purchased
of three months or less to be cash and cash equivalents. Cash and cash
equivalents consist of commercial paper and funds deposited in bank accounts.
Impairment of Long-Lived Assets and Intangibles
In accordance with the provisions of SFAS No. 144, Accounting for the Impairment
of Long-Lived Assets to be Disposed Of, the Trust evaluates long-lived assets,
such as fixed assets and specifically identifiable intangibles, when events or
changes in circumstances indicate that the carrying value of such assets may not
be recoverable. The determination of whether an impairment has occurred is made
by comparing the carrying value of an asset to the estimated undiscounted cash
flows attributable to that asset. If an impairment has occurred, the impairment
loss recognized is the amount by which the carrying value exceeds the discounted
cash flows attributable to the asset or the estimated fair value of the asset.
Plant and equipment
Plant and equipment, consisting principally of electrical generating equipment,
is stated at cost. Major renewals and betterments that increase the useful lives
of the assets are capitalized. Repair and maintenance expenditures that increase
the efficiency of the assets are expensed as incurred. The Trust periodically
assesses the recoverability of plant and equipment, and other long-term assets,
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable
Depreciation is recorded using the straight-line method over the useful lives of
the assets, which are 3 to 20 years with a weighted average of 15 years at
December 31, 2002 and 2001. During 2002, 2001 and 2000, the Trust recorded
depreciation expense of $227,382, $224,929 and $226,413, respectively.
Electric Power Sales Contract
A portion of the purchase price of the Monterey Project was assigned to the
electric power sales contract and is being amortized over the life of the
contract (25 years) on a straight-line basis. The electric power sales contract
is reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount of the asset may not be recoverable. During 2002, 2001
and 2000, the Trust recorded amortization expense of $121,280.
Revenue recognition
Power generation revenue is recorded in the month of delivery, based on the
estimated volumes sold to customers at rates stipulated in the power sales
contract. Adjustments are made to reflect actual volumes delivered when the
actual information subsequently becomes available. Billings to customers for
power generation generally occurs during the month following delivery. Final
billings do not vary significantly from estimates. Interest income is recorded
when earned and dividend income is recorded when declared.
Supplemental cash flow information
Total interest paid during the years ended December 31, 2002, 2001 and 2000 was
$3,506, $0 and $9,063, respectively.
Significant Customers
During 2002, 2001 and 2000, the Trust's largest customer, Pacific Gas and
Electric Company ("PG&E"), accounted for 69%, 63% and 80%, respectively of total
revenues. PG&E is experiencing severe financial difficulty, see Note 9 for
additional discussion. Income taxes No provision is made for income taxes in the
accompanying consolidated financial statements as the income or losses of the
Trust are passed through and included in the tax returns of the individual
shareholders of the Trust. At December 31, 2002 and 2001, the Trust's net assets
had a tax basis of $11,051,680 and $12,015,786, respectively.
Reclassification
Certain items in previously issued consolidated financial statements have been
reclassified for comparative purposes.
3. Projects
Sunnyside Cogeneration Partners, L.P. (known as the Monterey project)
On January 9, 1995, the Trust acquired 100% of the existing partnership
interests of Sunnyside Cogeneration Partners, L.P., which owns and operates a
5.5 megawatt electric cogeneration facility, located in Monterey County,
California. The aggregate purchase price was $5,198,058 including transaction
costs. Electricity is sold to PG&E under a long term contract expiring in 2020.
The acquisition of the Monterey Project was accounted for as a purchase and the
results of operations of the Monterey Project have been included in the Trust's
consolidated financial statements since the acquisition date. The purchase price
was allocated to the net assets acquired, based on their respective fair values.
Of the purchase price, $3,032,000 was allocated to the electric power sales
contract and is being amortized over the life of the contract (25 years).
See Note 9 - Pacific Gas and Electric Company Financial Crisis, for developments
affecting the Monterey Project.
On December 31, 1998 the Trust, through subsidiaries, filed a legal complaint in
the Superior Court of California for Monterey County against Waukesha-Pierce,
Inc. and subsidiaries, alleging that the subsidiaries had not disclosed the
existence of an obligation of the Monterey project to Pacific Gas and Electric
Company and therefore breached a warranty in the acquisition agreement. The
claim was for approximately $273,000 plus interest and expenses.
Waukesha-Pierce, Inc. was included in the proceeding as a contractual guarantor.
On January 17, 1999, a separate action against Waukesha-Pierce, Inc. was filed
by the Trust's subsidiaries in the United States District Court for the Northern
District of Texas to enforce the guaranty. The parties agreed to dismiss the
Texas case without prejudice before material proceedings resulted. The
California case was settled in March 2000; Waukesha-Pierce Inc. agreed to pay
the Project approximately $190,000 and to cooperate with the Project in the
potential FERC proceedings involving the Monterey project discussed above and
the Trust agreed to cooperate with Waukesha-Pierce in releasing funds due from
PG&E to Waukesha-Pierce. In May 2002, the Project received settlement proceeds
of $190,306.
Pump Services Company, LP (known as California Pumping Project)
In 1995, the Trust acquired a package of natural gas and diesel engines, which
drive deep irrigation well pumps in Ventura County, California. The engines'
shaft horsepower-hours are sold to farmers at a discount from the price of
equivalent kilowatt hours of electricity. The operator pays for fuel,
maintenance, repair and replacement. The project has an equivalent of 2
megawatts of power.
B-3 Limited Partnership (known as the Columbia project)
On August 31, 1994, the Trust made a limited partnership investment in this
partnership, which was formed to construct and operate a municipal waste
transfer station, located in Columbia County, New York. The project commenced
operations in January 1995.
In exchange for its investment, the Trust was entitled to receive annually a
preferred distribution of available net cash flow from the facility equal to 18%
of its investment. In the event that in any given year available net cash flow
from the project does not at least equal the amount of the preferred minimum
return, the amount of such shortfall was payable on a priority basis out of any
available net cash flow in subsequent years. The Trust was also be entitled to
receive additional distributions from any net cash flow in excess of the 18%
return on its investment. The aggregate purchase price of the Trust's investment
in the partnership was $3,975,240. The Trust received distributions of $200,000,
$200,000 and $300,014 from the project for the years ended December 31, 2002,
2001 and 2000, respectively.
Due to the protective rights of the other partner and in accordance with
Emerging Issues Task Force ("EITF") 96-16 "Investor's Accounting for an Investee
When the Investor Has a Majority of the Voting Interest but the Minority
Shareholder or Shareholders Have Certain Approval or Veto Rights", the Trust's
50.5% ownership in the B-3 Limited Partnership was accounted for under the
equity method of accounting. The Trust's equity in the earnings of the B-3
Project has been included in the consolidated financial statements since
acquisition in accordance with the terms in the partnership agreement.
The partnership agreement required income (loss) earned by the partnership to be
allocated and distributed to the partners as follows:
1. Gross income isallocated as distributions declared have been allocated to the
partners.
2. The difference between distributions declared and net income before
depreciation is allocated to the partners according to partnership interests
3. Depreciation expense is allocated to the partners proportionally according to
their original capital contributions to the partnership.
Summarized financial information for the B-3 Limited Partnership is as follows:
Balance Sheet Information
(Unaudited)
September 20, 2002 December 31, 2001
------------------- -------------------
Current assets $ 1,643,719 $ 1,560,006
Non-current assets 2,209,768 2,366,793
------------------- -------------------
Total assets $3,853,487 $3,926,799
------------------- -------------------
Current liabilities $ 658,617 $ 644,757
Long-term debt --- 21,843
Equity 3,194,870 3,260,199
------------------- -------------------
Total liabilities and equity $3,853,487 $3,926,799
------------------- -------------------
Trust share $1,253,016 $2,527,395
------------------- -------------------
Effective September 20, 2002 the Trust sold its share in the B-3 Limited
Partnership, with a carrying value of $1,253,016, in return for an interest
bearing promissory note. The carrying value of the note at December 31, 2002 was
$1,207,195.
Statement of Operations Information
(Unaudited)
Period Ended For the Year Ended
------------ -----------------------
September 20, December 31, December 31,
2002 2001 2000
---------- ---------- ----------
Revenue ......... $4,477,725 $5,948,082 $5,856,071
Operating expense 4,343,054 5,889,936 5,525,722
---------- ---------- ----------
Net income ...... $ 134,671 $ 58,146 $ 330,349
---------- ---------- ----------
Trust share ..... $ 104,497 $ 43,459 $ 207,339
---------- ---------- ----------
On September 20, 2002, the Trust, sold 100% of its ownership interest in the B-3
Limited Partnership and the Pittsfield Investors Limited Partnership ("PILP"), a
facility which burns municipal solid waste, to EAC Operations, Inc., the other
limited partner of both entities. The acquisition agreement provides for the
sale of 100% of the Trust's ownership in the two partnerships in return for
$1,200,000 cash and $5,000,000 of interest bearing promissory notes. The notes
bear interest at a rate of 10% per annum, and will be repaid monthly over a 17
year term, of which the first two years of payments will consist of interest
only. The notes are collateralized by all the assets of the partnerships.
The purchase price for the B-3 Project was $3,400,000, of which $400,000 was
paid in cash at the time of closing. The purchase price for PILP was $2,800,000,
of which $800,000 was paid in cash at the time of closing. The Trust wrote off
its investment in PILP in 1998.
Recovery of interest and principal under the promissory notes is dependent
solely upon the operating results of the limited partnership investments sold.
Consequently, in accordance with SEC Staff Accounting Bulletin Topic 5E, the
Trust has not recorded a gain on the sale of its ownership interest. The cash
proceeds received were recorded as a reduction of its investment in the limited
partnership investments and interest and principal received under the promissory
note will continue to be recorded as a reduction of the note receivable balance
until the carrying value has been reduced to zero. In the event the divested
business incur operating losses in future periods, a corresponding reduction in
the note receivable will be recorded as a valuation allowance.
4. Note Receivable from Sale of Investment
On June 25, 1997, the Trust sold its entire interest in a chilled water facility
to subsidiaries of NRG Energy, Inc. ("NRG"). As part of the consideration, the
Trust received an 8% promissory note in the amount of $2,700,000 payable monthly
over six years. NRG payments are current on the promissory note, including
interest.
5. Line of Credit Facility, Letter of Credit and Restricted Cash
During the fourth quarter of 1997, the Trust and its principal bank executed a
revolving line of credit agreement, whereby the bank provided a three year
committed line of credit facility of $750,000. The credit facility was extended
until July 31, 2002. During the third quarter of 2002, the Trust extended its
revolving line of credit agreement with its principal bank through August 31,
2002 and subsequently finalized a further extension until July 31, 2003. The
extension provides the Trust with a committed line of credit of $550,000.
Outstanding borrowings bear interest at LIBOR plus 2.5% (3.882% and 4.376% at
December 31, 2002 and 2001, respectively). The amount outstanding under the line
of credit facility must be reduced to zero for a thirty-day period each year.
The credit agreement requires the Trust to provide 100% cash collateral for any
borrowings or letters of credit outstanding after September 30, 2002. There were
no outstanding borrowings at December 31, 2002 and 2001.
In August 2001, the Trust issued through its bank a standby letter of credit in
the amount of $504,000 to secure the gas purchases of the Monterey project. The
letter of credit expired in August 2002. The Trust used its credit facility and
a restricted certificate of deposit in the amount of $202,570 to collateralize
the letter of credit, which is presented as restricted cash on the Consolidated
Balance Sheets at December 31, 2001. In October 2002, the Trust increased the
amount of the certificate of deposit to $550,000.
6. Commitments
The Monterey project has a long-term operating ground lease. The lease is for a
term of thirty years.
Future minimum lease payments as of December 31, 2002 are as follows:
Year Ended
December 31, Repayment
------------ ---------
2003 $ 12,396
2004 12,396
2005 12,396
2006 12,396
2007 12,396
Thereafter 165,280
Rent expense for each of the years ended December 31, 2002, 2001 and 2000 was
$12,396.
The Monterey project has a long-term agreement to purchase natural gas from its
supplier. The agreement expires in August 2006.
Future minimum purchases under the agreement as of December 31, 2002 are as
follows:
Year Ended
December 31, Purchases
------------ ---------
2003 $ 893,187
2004 893,187
2005 1,365,903
2006 910,602
7. Transactions with Managing Shareholder and Affiliates
The Trust entered into a management agreement with the managing shareholder,
under which the managing shareholder renders certain management, administrative
and advisory services and provides office space and other facilities to the
Trust. As compensation to the managing shareholder, the Trust pays to the
managing shareholder an annual management fee equal to 1.5% of the net asset
value of the Trust payable monthly upon the closing of the Trust. For the years
ended December 31, 2002 and 2001, the Trust paid management fees to the managing
shareholder of $117,058 and $177,337, respectively. During the period of April
1999 to December 2000, the managing shareholder waived the management fee to
which it was entitled.
Under the Declaration of Trust, the managing shareholder is entitled to receive
each year 1% of all distributions made by the Trust (other than those derived
from the disposition of Trust property) until the shareholders have been
distributed a cumulative amount equal to 15% per annum of their equity
contribution. Thereafter, the managing shareholder is entitled to receive 20% of
the distributions for the remainder of the year. The managing shareholder is
entitled to receive 1% of the proceeds from dispositions of Trust properties
until the shareholders have received cumulative distributions equal to their
original investment ("Payout"). After Payout, the managing shareholder is
entitled to receive 20% of all remaining distributions of the Trust.
Where permitted, in the event the managing shareholder or an affiliate performs
brokering services in respect of an investment acquisition or disposition
opportunity for the Trust, the managing shareholder or such affiliate may charge
the Trust a brokerage fee. Such fee may not exceed 2% of the gross proceeds of
any such acquisition or disposition. No such fees have been incurred through
December 31, 2002.
The managing shareholder owns 1.45 investor shares of the Trust with a cost of
$121,800. The Trust granted the managing shareholder a single Management Share
representing the managing shareholder's management rights and rights to
distributions of cash flow.
In 1996, under an Operating Agreement with the Trust, Ridgewood Management
provides management, purchasing, engineering, planning and administrative
services to the power generation projects operated by the Trust. Ridgewood
Management charges the project at its cost for these services and for the
allocable amount of certain overhead items. Allocations of costs are on the
basis of identifiable direct costs, time records or in proportion to amount
invested in projects managed by Ridgewood Management. During the year ended
December 31, 2002, 2001 and 2000, Ridgewood Management charged Sunnyside
Cogeneration Partners $132,810, $153,354 and $109,148, respectively, for
overhead items allocated in proportion to the amount invested in projects
managed. During the years ended December 31, 2002, 2001 and 2000, Ridgewood
Management charged the California Pumping Project $20,973, $77,103 and $70,118,
respectively, for overhead items allocated in proportion to the amount invested
in projects managed. Ridgewood Management also charged Sunnyside Cogeneration
Partners and the California Pumping Project for all of the direct operating and
non-operating expenses incurred during the periods.
At December 31, 2002 and 2001, the Trust had outstanding payables of $47,883 and
$182,215, respectively, to Ridgewood Management. From time to time, the Trust
records short-term payables and receivables from other affiliates in the
ordinary course of business. The amounts payable and receivable do not bear
interest.
8. Fair Value of Financial Instruments
At December 31, 2002 and 2001, the carrying value of the Trust's cash and cash
equivalents, trade receivables, and accounts payable and accrued expenses
approximates their fair value. The fair value of the letter of credit does not
differ materially from its carrying value.
9. Financial Information by Business Segment
The Trust's business segments were determined based on similarities in economic
characteristics and customer base. The Trust's principal business segments
consist of wholesale and retail.
Common services shared by the business segments are allocated on the basis of
identifiable direct costs, time records or in proportion to amount invested in
projects managed by Ridgewood Management.
The financial data for business segments are as follows:
Wholesale
----------------------------------------
2002 2001 2000
----------- ----------- -----------
Revenue ............... $ 2,122,189 $ 1,498,420 $ 2,824,854
Depreciation and
amortization ........ 245,718 245,813 247,122
Operating income (loss) 442,677 (794,616) 145,486
Total assets .......... 3,838,577 4,026,379 4,907,958
Capital expenditures .. -- 6,617 1,533
Retail
---------------------------------
2002 2001 2000
--------- --------- ---------
Revenue ............... $ 952,925 $ 875,976 $ 705,726
Depreciation and
amortization ........ 102,944 100,396 100,571
Operating income (loss) 17,289 15,544 (170,239)
Total assets .......... 321,862 488,289 619,759
Capital expenditures .. 22,432 -- --
Corporate
------------------------------------------
2002 2001 2000
------------ ------------ ------------
Revenue ............ $ -- $ -- $ --
Depreciation and
amortization ..... -- -- --
Operating loss ..... (533,833) (324,482) (66,344)
Total assets ....... 3,400,566 3,701,487 4,067,812
Capital expenditures -- -- --
Total
-------------------------------------------
2002 2001 2000
------------ ----------- ------------
Revenue ............ $ 3,075,114 $ 2,374,396 $ 3,530,580
Depreciation and
amortization ..... 348,662 346,209 347,693
Operating loss ..... (73,867) (1,103,554) (91,097)
Total assets ..... 7,561,005 8,216,155 9,595,529
Capital expenditures 22,432 6,617 1,533
10. Pacific Gas and Electric Company Financial Crisis
Due to financial difficulties, PG&E did not pay in full for electrical energy
and capacity delivered by the Monterey Project in December 2000 and January
2001. Accordingly, the Monterey Project was unable to pay its natural gas
supplier for the gas delivered for those months. In late January of 2001, the
gas supplier requested assurance of payment before it would agree to provide
natural gas during February. Due to PG&E's financial crises and its inability to
pay, the Monterey Project was unable on its own to provide an acceptable
assurance or to pay the arrears and, as a result, the supplier refused to
provide natural gas beyond February 6, 2001 and the Trust shut down the Monterey
Project. Many QFs under contract with PG&E suffered the same fate and were
temporarily forced to shut operations because of PG&E's failure to pay for
energy and capacity delivered. On April 6, 2001, as a result of its financial
problems, PG&E filed for protection under the U.S. Bankruptcy laws.
In April 2001, the Monterey Project entered into an agreement with a financial
institution whereby it sold, irrevocably and without recourse, its undivided
interest in all eligible trade accounts receivables for December 2000 and
January 2001. Costs associated with the sale of receivables of $127,130 and
$244,169 for 2001 and 2000, respectively, primarily related to the discount and
loss on sale, are included in provision for bad debt expense in the Consolidated
Statements of Operations.
In August 2001, PG&E and the Monterey Project entered into an amendment to the
electric power sales contract for a term of five years, which would effectively
replace, for such 5 year term, the variable formula for determining the energy
price with a fixed energy price. Also in August 2001, the Monterey Project
entered into a five year fixed price natural gas supply agreement with Coral
Energy Services, Inc., a subsidiary of Shell Oil.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
(a) General.
Ridgewood Power Corporation was incorporated in February 1991 as a
Delaware corporation for the primary purpose of acting as a managing shareholder
of business trusts and as a managing general partner of limited partnerships. It
organized the Trust and acted as managing shareholder until April 1999. On or
about April 21, 1999 it was merged into the current Managing Shareholder,
Ridgewood Power LLC. In December of 2002, Ridgewood Power, LLC changed its name
to Ridgewood Renewable Power, LLC. Robert E. Swanson is the controlling member,
sole manager and President of the Managing Shareholder. All of the equity in the
Managing Shareholder is owned by Mr. Swanson or by family trusts. Mr. Swanson
has the power on behalf of those trusts to vote or dispose of the membership
equity interests owned by them.
The Managing Shareholder has also organized the Other Power Trusts as
Delaware business trusts or other Delaware limited liability companies.
Ridgewood Renewable Power LLC is the managing shareholder of the Other Power
Trusts and the manager of the Ridgewood LLCs. The business objectives of these
trusts and LLCs are similar to those of the Trust.
A number of other companies are affiliates of Mr. Swanson and the
Managing Shareholder. Each of these also was organized as a corporation that was
wholly-owned by Mr. Swanson. In April 1999, most of them were merged into
limited liability companies with similar names and Mr. Swanson became the sole
manager and controlling owner of each limited liability company.
The Managing Shareholder is an affiliate of Ridgewood Energy
Corporation ("Ridgewood Energy"), which has organized and operated 48 limited
partnership funds and one business trust over the last 17 years (of which 25
have terminated) and which had total capital contributions in excess of $190
million. The programs operated by Ridgewood Energy have invested in oil and
natural gas drilling and completion and other related activities. Other
affiliates of the Managing Shareholder include Ridgewood Securities Corporation
("Ridgewood Securities"), an NASD member which has been the placement agent for
the private placement offerings of the six trusts sponsored by the Managing
Shareholder and the funds sponsored by Ridgewood Energy; Ridgewood Capital
Management LLC ("Ridgewood Capital"), which assists in offerings made by the
Managing Shareholder and which is the sponsor of six privately offered venture
capital funds (the Ridgewood Capital Venture Partners, Ridgewood Capital Venture
Partners II and Ridgewood Capital Venture Partners III funds); Ridgewood Power
VI LLC ("Power VI"), which is a managing shareholder of the Growth Fund, and
RPM. Each of these companies is controlled by Robert E. Swanson, who is their
sole director or manager.
Set forth below is certain information concerning Mr. Swanson and other
executive officers of the Managing Shareholder.
Robert E. Swanson, age 56, has also served as President of the Trust
since its inception in 1991 and as President of RPM, the Other Power Trusts and
Ridgewood LLCs, since their respective inceptions. Mr. Swanson has been
President and registered principal of Ridgewood Securities and became the
Chairman of the Board of Ridgewood Capital on its organization in 1998. He also
is Chairman of the Board of the Ridgewood Capital Venture Partners I, II, III
and IV venture capital funds (collectively "Ridgewood Venture Funds"). In
addition, he has been President and sole stockholder of Ridgewood Energy since
its inception in October 1982. Prior to forming Ridgewood Energy in 1982, Mr.
Swanson was a tax partner at the former New York and Los Angeles law firm of
Fulop & Hardee and an officer in the Trust and Investment Division of Morgan
Guaranty Trust Company. His specialty is in personal tax and financial planning,
including income, estate and gift tax. Mr. Swanson is a member of the New York
State and New Jersey bars, the Association of the Bar of the City of New York
and the New York State Bar Association. He is a graduate of Amherst College and
Fordham University Law School.
Robert L. Gold, age 44, has served as Executive Vice President of the
Managing Shareholder, RPM, the Trust, the Other Power Trusts and the Ridgewood
LLCs since their respective inceptions.. He has been President of Ridgewood
Capital since its organization in 1998. As such, he is President of the
Ridgewood Venture Funds. He has served as Vice President and General Counsel of
Ridgewood Securities Corporation since he joined the firm in December 1987. Mr.
Gold has also served as Executive Vice President of Ridgewood Energy since
October 1990. He served as Vice President of Ridgewood Energy from December 1987
through September 1990. For the two years prior to joining Ridgewood Energy and
Ridgewood Securities Corporation, Mr. Gold was a corporate attorney in the law
firm of Cleary, Gottlieb, Steen & Hamilton in New York City where his experience
included mortgage finance, mergers and acquisitions, public offerings, tender
offers, and other business legal matters. Mr. Gold is a member of the New York
State bar. He is a graduate of Colgate University and New York University School
of Law.
Daniel V. Gulino, age 42, is Senior Vice President and General Counsel
of the Managing Shareholder, RPM, Ridgewood Capital, the Trust, Other Power
Trusts and Ridgewood LLCs. He began his legal career as an associate for Pitney,
Hardin, Kipp & Szuch, a large New Jersey law firm, where his experience included
corporate acquisitions and transactions. Prior to joining Ridgewood, Mr. Gulino
was in-house counsel for several large electric utilities, including GPU, Inc.,
Constellation Power Source, 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, 38, is the Vice President and Chief Financial
Officer of the Managing Shareholder, RPM, the Trust, Other Power Trusts and
Ridgewood LLCs. From February 1998 to April 2000, he was Vice President of
Finance of an affiliate of the Managing Shareholder. Prior to that time, he was
a senior manager at the predecessor accounting firm of PricewaterhouseCoopers
LLP. Mr. Naunton's professional qualifications include his certified public
accountant qualification in Pennsylvania, membership in the American Institute
of Certified Public Accountants and the Pennsylvania Institute of Certified
Public Accountants. He holds a Bachelor of Science degree in Business
Administration from Bucknell University (1986).
Mary Lou Olin, age 50, has served as Vice President of the Managing
Shareholder, RPM, Ridgewood Capital, the Trust, the Other Power Trusts, and
Ridgewood LLCs since their respective inceptions. She has also served as Vice
President of Ridgewood Energy since October 1984, when she joined the firm. Her
primary areas of responsibility are investor relations, communications and
administration. Prior to her employment at Ridgewood Energy, Ms. Olin was a
Regional Administrator at McGraw-Hill Training Systems where she was employed
for two years. Prior to that, she was employed by RCA Corporation. Ms. Olin has
a Bachelor of Arts degree from Queens College.
(b) Management Agreement.
The Trust has entered into a Management Agreement with the Managing
Shareholder detailing how the Managing Shareholder will render management,
administrative and investment advisory services to the Trust. Specifically, the
Managing Shareholder will perform (or arrange for the performance of) the
management and administrative services required for the operation of the Trust.
Among other services, it will administer the accounts and handle relations with
the Investors, provide the Trust with office space, equipment and facilities and
other services necessary for its operation, and conduct the Trust's relations
with custodians, depositories, accountants, attorneys, brokers and dealers,
corporate fiduciaries, insurers, banks and others, as required. The Managing
Shareholder will also be responsible for making investment and divestment
decisions, subject to the provisions of the Declaration.
The Managing Shareholder will be obligated to pay the compensation of
the personnel and all administrative and service expenses necessary to perform
the foregoing obligations. The Trust will pay all other expenses of the Trust,
including transaction expenses, valuation costs, expenses of preparing and
printing periodic reports for Investors and the Commission, postage for Trust
mailings, Commission fees, interest, taxes, legal, accounting and consulting
fees, litigation expenses and other expenses properly payable by the Trust. The
Trust will reimburse the Managing Shareholder for all such Trust expenses paid
by it.
As compensation for the Managing Shareholder's performance under the
Management Agreement, the Trust is obligated to pay the Managing Shareholder an
annual management fee described below at Item 13 -- Certain Relationships and
Related Transactions.
Each Investor consented to the terms and conditions of the initial
Management Agreement by subscribing to acquire Investor Shares in the Trust. The
Management Agreement is subject to amendment by the parties with the approval of
a majority in interest of the Investors.
(c) Executive Officers of the Trust.
Pursuant to the Declaration, the Managing Shareholder has appointed
officers of the Trust to act on behalf of the Trust and sign documents on behalf
of the Trust as authorized by the Managing Shareholder. Mr. Swanson has been
named the President of the Trust and the other executive officers of the Trust
are identical to those of the Managing Shareholder.
The officers have the duties and powers usually applicable to similar
officers of a Delaware business corporation in carrying out Trust business.
Officers act under the supervision and control of the Managing Shareholder,
which is entitled to remove any officer at any time. Unless otherwise specified
by the Managing Shareholder, the President of the Trust has full power to act on
behalf of the Trust. The Managing Shareholder expects that most actions taken in
the name of the Trust will be taken by Mr. Swanson and the other principal
officers in their capacities as officers of the Trust under the direction of the
Managing Shareholder rather than as officers of the Managing Shareholder.
(d) Corporate Trustee
The Corporate Trustee of the Trust is Ridgewood Holding. Legal title to
Trust Property is now and in the future will be in the name of the Trust, if
possible, or Ridgewood Holding as trustee. Ridgewood Holding is also a trustee
of the Other Power Funds and of an oil and gas business trust sponsored by
Ridgewood Energy and is expected to be a trustee of other similar entities that
may be organized by the Managing Shareholder and Ridgewood Energy. The
President, sole director and sole stockholder of Ridgewood Holding is Robert E.
Swanson; its other executive officers are identical to those of the Managing
Shareholder. See -- Managing Shareholder. The principal office of Ridgewood
Holding is at 1105 North Market Street, Suite 1300, Wilmington, Delaware 19899.
The Trust has relied and will continue to rely on the Managing
Shareholder and engineering, legal, investment banking and other professional
consultants (as needed) and to monitor and report to the Trust concerning the
operations of Projects in which it invests, to review proposals for additional
development or financing, and to represent the Trust's interests. The Trust will
rely on such persons to review proposals to sell its interests in Projects in
the future.
(e) Section 16(a) Beneficial Ownership Reporting Compliance
To the knowledge of the Trust, there were no violations of the
reporting requirements of section 16(a) of the 1934 Act by officers and
directors of the Trust in the last fiscal year.
(f) RPM.
As discussed above at Item 1 - Business, RPM has assumed day-to-day
management responsibility for the Monterey Project, effective January 1, 1996
and operating responsibility for the Pumping Project in October 1998 and had
assumed certain responsibilities for the San Diego Project in early 1997 until
its sale. Like the Managing Shareholder, RPM is controlled by Robert E. Swanson.
It has entered into an "Operation Agreement" with certain of the Trust's
subsidiaries, effective January 1, 1996, under which RPM, under the supervision
of the Managing Shareholder, provides the management, purchasing, engineering,
planning and administrative services for those Projects that were previously
furnished by employees of the Trust or by unaffiliated professionals or
consultants and that were borne by the Trust or Projects as operating expenses.
To the extent that those services were provided by the Managing Shareholder and
related directly to the operation of the Project, RPM charges the Trust at its
cost for these services and for the Trust's allocable amount of certain overhead
items. RPM shares space and facilities with the Managing Shareholder and its
Affiliates. To the extent that common expenses can be reasonably allocated to
RPM, the Managing Shareholder may, but is not required to, charge RPM at cost
for the allocated amounts and such allocated amounts will be borne by the Trust
and other programs. Common expenses that are not so allocated are borne by the
Managing Shareholder.
The Managing Shareholder does not charge RPM for the full amount of
rent, utility supplies and office expenses allocable to RPM. As a result, RPM's
charges for its services to the Trust are likely to be materially less than its
economic costs and the costs of engaging comparable third persons as managers.
RPM will not receive any compensation in excess of its costs.
Allocations of costs are made either on the basis of identifiable
direct costs, time records or in proportion to each program's investments in
Projects managed by RPM; all allocations are made in a manner consistent with
generally accepted accounting principles.
RPM does not provide any services related to the administration of the
Trust, such as investment, accounting, tax, investor communication or regulatory
services, nor will it participate in identifying, acquiring or disposing of
Projects. RPM does not have the power to act in the Trust's name or to bind the
Trust, which will be exercised by the Managing Shareholder or the Trust's
officers, although it may be authorized to act on behalf of the subsidiaries
that own Projects.
The Operation Agreement does not have a fixed term and is terminable by
RPM, by the Managing Shareholder or by vote of a majority of interest of
Investors, on 60 days' prior notice. The Operation Agreement may be amended by
agreement of the Managing Shareholder and RPM; however, no amendment that
materially increases the obligations of the Trust or that materially decreases
the obligations of RPM shall become effective until at least 45 days after
notice of the amendment, together with the text thereof, has been given to all
Investors.
The executive officers of RPM are the same as those of the Managing
Shareholder set forth above.
Item 11. Executive Compensation.
The Managing Shareholder compensates its officers without additional
payments by the Trust. The Trust will reimburse RPM at cost for services
provided by RPM's employees. Information as to the fees payable to the Managing
Shareholder and certain affiliates is contained at Item 13 - Certain
Relationships and Related Transactions.
Ridgewood Holding, the Corporate Trustee of the Trust, is not entitled
to compensation for serving in such capacity, but is entitled to be reimbursed
for Trust expenses incurred by it, which are properly reimbursable under the
Declaration.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The Trust sold 235.3775 Investor Shares (approximately $23.5 million of
gross proceeds) of beneficial interest in the Trust pursuant to a private
placement offering under Rule 506 of Regulation D under the Securities Act. The
offering closed on January 31, 1994. Further details concerning the offering are
set forth above at Item 1 -- Business.
The Managing Shareholder purchased for cash of $121,800 in the offering
1.45 Investor Shares (.6 of 1% of the outstanding Investor Shares). The Managing
Shareholder was issued one Management Share in the Trust representing the
beneficial interests and management rights of the Managing Shareholder in its
capacity as such (excluding its interest in the Trust attributable to Investor
Shares it acquired in the offering). Additional information concerning the
management rights of the Managing Shareholder is at Item 1 - Business and at
Item 10 -- Directors and Executive Officers of the Registrant. Its beneficial
interest in cash distributions of the Trust and its allocable share of the
Trust's net profits and net losses and other items attributable to the
Management Share are described in further detail below at Item 13 - Certain
Relationships and Related Transactions.
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable
reserves which the Trust deems necessary to cover anticipated Trust expenses, is
to be distributed to the Investors and the Managing Shareholder (collectively,
the "Shareholders"), from time to time as the Trust deems appropriate. Prior to
Payout (the point at which Investors have received cumulative distributions
equal to the amount of their capital contributions), each year all distributions
from the Trust, other than distributions of the revenues from dispositions of
Trust Property, are to be allocated 99% to the Investors and 1% to the Managing
Shareholder until Investors have been distributed during the year an amount
equal to 15% of their total capital contributions (a "15% Priority
Distribution"), and thereafter all remaining distributions from the Trust during
the year, other than distributions of the revenues from dispositions of Trust
Property, are to be allocated 80% to Investors and 20% to the Managing
Shareholder. Revenues from dispositions of Trust Property are to be distributed
99% to Investors and 1% to the Managing Shareholder until Payout. In all cases,
after Payout, Investors are to be allocated 80% of all distributions and the
Managing Shareholder 20%.
For any fiscal period, the Trust's net profits, if any, other than
those derived from dispositions of Trust Property, are allocated 99% to the
Investors and 1% to the Managing Shareholder until the profits so allocated
offset (1) the aggregate 15% Priority Distribution to all Investors and (2) any
net losses from prior periods that had been allocated to the Shareholders. Any
remaining net profits, other than those derived from dispositions of Trust
Property, are allocated 80% to the Investors and 20% to the Managing
Shareholder. If the Trust realizes net losses for the period, the losses are
allocated 80% to the Investors and 20% to the Managing Shareholder until the
losses so allocated offset any net profits from prior periods allocated to the
Shareholders. Any remaining net losses are allocated 99% to the Investors and 1%
to the Managing Shareholder. Revenues from dispositions of Trust Property are
allocated in the same manner as distributions from such dispositions. Amounts
allocated to the Investors are apportioned among them in proportion to their
capital contributions.
On liquidation of the Trust, the remaining assets of the Trust after
discharge of its obligations, including any loans owed by the Trust to the
Shareholders, will be distributed, first, 99% to the Investors and the remaining
1% to the Managing Shareholder, until Payout, and any remainder will be
distributed to the Shareholders in proportion to their capital accounts.
In 2002 and 2001, as stated at Item 5 - Market for Registrant's Common
Equity and Related Stockholder Matters, as well as in prior years, the Trust
made distributions to the Managing Shareholder (which is a member of the Board
of the Trust) as stated at Item 5 - Market for Registrant's Common Equity and
Related Stockholder Matters. In addition, the Trust and its subsidiaries paid
fees and reimbursements to the Managing Shareholder and its affiliates as
follows:
2002 2001 2000 1999 1998
Managing
Shareholder $117,058 $177,727 $ -0- $55,607 $381,594
RPM Cost
Reimbursements 2,862,273 2,955,915 3,032,954 2,841,952 1,470,207
The management fee, payable monthly under the Management Agreement at the
annual rate of 2.5% of the Trust's net asset value, began on the date the first
Project was acquired and compensates the Managing Shareholder for certain
management, administrative and advisory services for the Trust. Under the
Declaration of Trust, the annual rate fell to 1.5% per year beginning February
1, 1999. Beginning April, 1999, the Managing Shareholder waived the fee.
Effective January 1, 2001, it resumed payment of the management fee at the 1.5%
of net asset value annual rate.
In addition to the foregoing, the Trust reimbursed the Managing
Shareholder at cost for expenses and fees of unaffiliated persons engaged by the
Managing Shareholder for Trust business and in years before 1996 for payroll and
other costs of operation of the Monterey and Pumping Projects. In 1996 and 1997,
these reimbursements were paid to RPM. The reimbursements to RPM, which do not
exceed its actual costs and allocable overhead, are described at Item 10(g) -
Directors and Executive Officers of the Registrant -- RPM.
Other information in response to this item is reported in response to
Item 11 -- Executive Compensation, which information is incorporated by
reference into this Item 13.
Item 14. Control and Procedures
Within the 90 days prior to the filing date of this Report, the Trust's
Chief Executive Officer and Chief Financial Officer conducted an evaluation of
the effectiveness and design of the Trust's disclosure controls and procedures
pursuant to Rule 13a-15 of the Securities Exchange Act of 1934 (the "Exchange
Act"). Based upon that evaluation, the Chief Executive Officer and Chief
Financial Officer each concluded that the disclosure controls and procedures
were effective, with the exception of the matter noted below.
During the 2002 annual financial reporting process, management has
identified deficiencies in the Trust's ability to process and summarize
financial information of certain individual projects and equity investees on a
timely basis. Management is establishing a project plan to address this
deficiency in 2003.
There have been no significant changes in the internal controls or in
other factors that could significantly affect these controls subsequent to the
date that they completed their evaluation.
The term "disclosure controls and procedures" is defined in Rule
13a-14(c) of the Exchange Act as "controls and other procedures designed to
ensure that information required to be disclosed by the issuer in the reports
files or submits under the Exchange Act is recorded, processed, summarized and
reported, within the time periods specified in the [Securities and Exchange]
Commission's rules and forms." The Trust's disclosure controls and procedures
are designed to ensure that material information relating to the consolidated
subsidiaries is accumulated and communicated to management, including the Chief
Executive Officer and Chief Financial Officer, as appropriate to allow timely
decisions regarding the required disclosures.
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Financial Statements.
See the Index to Financial Statements in Item 8 hereof.
(b) Reports on Form 8-K.
No Forms 8-K were filed with the Commission by the Registrant during the
quarter ending December 31, 2002.
(c) Exhibits
3A. Certificate of Trust of the Registrant, is incorporated by reference
to Exhibit 3A to the Registrant's Registration Statement on Form 10
filed with the Commission on February 27, 1993.
3B. Amended and Restated Declaration of Trust of the Registrant, is
incorporated by reference to Exhibit 4 to the Quarterly Report on
Form 10Q of the Registrant for the quarter ended September 30, 1993.
10A. Management Agreement dated as of January 4, 1993 between the
Registrant and Ridgewood Power Corporation, is incorporated by
reference to Exhibit 10 to the Registrant's Registration Statement
on Form 10 filed with the Commission on February 27, 1993.
10B. Limited Partnership Agreement of Pittsfield Investors Limited
Partnership (without exhibits), is incorporated by reference to
Exhibit 2(i) to the Form 8-K of Registrant filed with the Commission
on January 19, 1994.
10C. Asset Purchase Agreement between EAC Systems, Inc. and Vicon
Recovery Associates ("Vicon") dated as of December 23, 1992 (the
"Asset Purchase Agreement") (without exhibits), is incorporated by
reference to Exhibit 2(ii) to the Form 8-K of Registrant filed with
the Commission on January 19, 1994.
10D. First Amendment of Asset Purchase Agreement dated as of December 30,
1993 (without exhibits), is incorporated by reference to Exhibit
2(ii) to the Form 8-K of Registrant filed with the Commission on
January 19, 1994.
10E. Lease dated as of September 1, 1979 between the City of Pittsfield,
Massachusetts (acting by and through its Industrial Development
Financing Authority), is incorporated by reference to Exhibit 2(iv)
to the Form 8-K of Registrant filed with the Commission on January
19, 1994.
10F. Amended and Restated Solid Waste Disposal and Resource Recovery
Agreement dated August 6, 1979 by and among the City of Pittsfield,
Vicon and others (together with amendments dated October 26, 1984,
July 28, 1989 and December 29, 1993), is incorporated by reference
to Exhibit 2(v) to the Form 8-K of Registrant filed with the
Commission on January 19, 1994.
10G. Steam Purchase Agreement by and between Crane & Co., Inc. and Vicon
dated as of February 1, 1979 (with amendments), is incorporated by
reference to Exhibit 2(vi) to the Form 8-K of Registrant filed with
the Commission on January 19, 1994.
The Registrant is no longer a party to former Exhibits 10H through 10M
because of its sale of the San Diego Project. See Exhibits 10P-R.
10N. Acquisition Agreement dated as of January 9, 1995 among Sunnyside
Cogen, Inc., and NorCal Sunnyside Inc., as Sellers, and RW Monterey,
Inc. and Ridgewood Electric Power Trust II, as Purchasers, is
incorporated by reference to Exhibit 2(i) to the Form 8K of
Registrant filed with the Commission on February 16, 1995.
10O. Acquisition Agreement, dated as of March 31, 1995, by and among the
Trust and its subsidiary, Pump Services Corporation, as purchasers
and Donald C. Stewart, Union Energy Corp. and Donald A. Sherman as
sellers. Incorporated by reference to Exhibit 10O to the Annual
Report on Form 10-K of the Registrant for the year ended December
31, 1995.
10P. Partnership Interest Purchase Agreement, dated as of June 25,
1997, by and among the Trust, RSD Power Corp., NRG San Diego,
Inc., and NRG del Coronado, Inc. Incorporated by reference to
Exhibit 2.A. of the Current Report on Form 8-K of the
Registrant, dated June 25, 1997. Exhibits and schedules are
omitted, and a list of the omitted documents is found at page
20 of the agreement. The Registrant agrees to furnish
supplementally a copy of any omitted exhibit or schedule to
the Partnership Interest Purchase Agreement to the Commission
upon request.
10Q. Purchase Money Promissory Note. Incorporated by reference to
Exhibit 2.B. of the Current Report on Form 8-K of the
Registrant, dated June 25, 1997.
10R. Security and Pledge Agreement, dated as of June 25, 1997, by and
among the Trust, RSD Power Corp., NRG San Diego, Inc., and NRG del
Coronado, Inc. Incorporated by reference to Exhibit 2.C. of the
Current Report on Form 8-K of the Registrant, dated June 25, 1997.
10S. Master Sale Agreement, dated August 8, 2001, by and between
Sunnyside Cogeneration Partners, L.P. and Coral Energy
Resources, L.P. (the terms of the actual transaction are
subject to confidentiality provisions).
10T. Acquisition Agreement, dated September 20, 2002, by and
between the Trust and EAC Operations, Inc.
99.1. Certifications under Section 906 of the Sarbanes-Oxley Act.
The Registrant agrees to furnish supplementally a copy of any omitted exhibit or
schedule to agreements filed as exhibits to the Commission upon request.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
RIDGEWOOD ELECTRIC POWER TRUST II (Registrant)
By:/s/ Robert E. Swanson President April 16, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated
By:/s/ Robert E. Swanson President April 16, 2003
Robert E. Swanson
By:/s/ Christopher Naunton Vice President and April 16, 2003
Christopher Naunton Chief Financial Officer
RIDGEWOOD POWER LLC Managing Shareholder April 16, 2003
By:/s/ Robert E. Swanson President
Robert E. Swanson
CERTIFICATION PURSUANT TO RULE 13A-14 UNDER
THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Robert E. Swanson, Chief Executive Officer of Ridgewood Electric Power Trust
II ("registrant"), certify that:
1. I have reviewed this annual report on Form 10-K of the registrant;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and senior management:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and
6. The registrant's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: April 16, 2003
/s/ Robert E. Swanson
Robert E. Swanson
Chief Executive Officer
CERTIFICATION PURSUANT TO RULE 13A-14 UNDER
THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Christopher I. Naunton, Chief Financial Officer of Ridgewood Electric Power
Trust II ("registrant"), certify that:
1. I have reviewed this annual report on Form 10-K of the registrant;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and senior management:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and
6. The registrant's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: April 16, 2003
/s/ Christopher I. Naunton
Christopher I. Naunton
Chief Financial Officer