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, 2000
Commission file number 0-21304
RIDGEWOOD ELECTRIC POWER TRUST II
(Exact Name of Registrant as Specified in Its Charter)
Delaware 22-3206429
(State or Other Jurisdiction (I.R.S. Employer Identification No.)
of Incorporation or Organization)
c/o Ridgewood Power LLC, 947 Linwood Avenue,
Ridgewood, New Jersey 07450
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, including Area Code: (201) 447-9000
Securities Registered Pursuant to Section 12(b) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
Shares of Beneficial Interest (Title of Class)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
[ X ]
There is no market for the Shares. The aggregate capital contributions made
for the Registrant's voting Shares held by non-affiliates of the Registrant at
March 30, 2001 was $23,537,750.
Exhibit Index is located on Page 39.
PART I
Item 1. Business.
Forward-looking statement advisory
This Annual Report on Form 10-K, as with some other statements made by
the Trust from time to time, has forward-looking statements. These statements
discuss business trends and other matters relating to the Trust's future results
and the business climate and are found, among other places, at Items 1(c)(3),
1(c)(4), 1(c)(6)(ii) and 7. 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 Confidential Memorandum 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. Some of these cautionary factors that readers should
consider are described below at Item 1(c)(4) - Trends in the Electric Utility
and Independent Power Industries.
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.
Ridgewood Electric Power Trust II (the "Trust") was organized as a
Delaware business trust on November 20, 1992 to participate in the development,
construction and operation of independent power generating facilities
("Independent Power Projects" or "Projects"). Ridgewood Energy Holding
Corporation (Ridgewood Holding"), a Delaware corporation, is the Corporate
Trustee of the Trust.
The Trust sold shares of beneficial interest in the Trust ("Investor
Shares") in a private placement offering (the "Offering") which ended on January
31, 1994, at which time it had raised approximately $23.5 million. Net of
offering fees, commissions and expenses, the Offering provided approximately
$19.4 million of net funds available for investments in the development and
acquisition of Projects. The Trust has 483 record holders of Investor Shares
(the "Investors"). As described below in Item 1(c)(2), the Trust (and its
subsidiaries) owns equity interests in four Projects and a debt interest in
another.
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.
The Trust is organized similarly to a limited partnership. Ridgewood
Power LLC (the "Managing Shareholder"), a Delaware limited liability company, is
the Managing Shareholder of the Trust. For information about the merger of the
prior Managing Shareholder, Ridgewood Power Corporation, into Ridgewood Power
LLC, see Item 10(b) - Directors and Executive Officers of the Registrant -
Managing Shareholder.
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 and as to most acquisitions. The Managing Shareholder is
not regularly elected by the owners of the Investor Shares (the "Investors").
The Managing Shareholder and the Independent Trustees of the Trust meet together
as the Board of the Trust and take the actions that the 1940 Act requires a
board of directors to take for a business development company. The Board of the
Trust also provides general supervision and review of the Managing Shareholder,
but does not have the power to take action on its own. The Independent Trustees
do not have any management or administrative powers over the Trust or its
property other than as expressly authorized or required by the Declaration of
Trust of the Trust (the "Declaration") or the 1940 Act.
Ridgewood Holding is the Corporate Trustee of the Trust. The Corporate
Trustee acts on the instructions of the Managing Shareholder and is not
authorized to take independent discretionary action on behalf of the Trust. See
Item 10. - Directors and Executive Officers of the Registrant below for a
further description of the management of the Trust.
The following chart summarizes some of these relationships.
Robert E. Swanson and certain Swanson family trusts own 100% of the
equity of the following entities:
o Ridgewood Securities Corporation - Placement Agent ("Ridgewood Securities");
o Ridgewood Power Management, LLC - Operates the Trust's Projects and those of
the other six trusts ("RPM");
o Ridgewood Power LLC - Managing Shareholder of seven trusts ("Ridgewood
Power");
o Ridgewood Energy Holding Corporation - Corporate Trustee for all six trusts;
and
o Ridgewood Capital Management LLC - A marketing affiliate and manager of six
venture capital funds ("Ridgewood Capital")
Mr. Swanson has sole voting and investment power over the Swanson family
trusts and is the sole manager, chief executive officer of the above entities.
In addition, the Trust is affiliated with the following trusts
organized by the Managing Shareholder:
o Ridgewood Electric Power Trust I ("Power I");
o Ridgewood Electric Power Trust III ("Power III");
o Ridgewood Electric Power Trust IV ("Power IV");
o Ridgewood Electric Power Trust V ("Power V");
o The Ridgewood Power Growth Fund (the "Growth Fund"); and
o Ridgewood/Egypt Fund ("Egypt Fund")
(b) Financial Information about Industry Segments.
The Trust operates in only one industry segment: investing in independent
power generation and similar energy projects.
(c) Narrative Description of Business.
(1) General Description.
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.
The Trust has made equity investments totaling approximately $10.8
million in four Projects: (i) a waste-to-energy generating facility located in
Pittsfield, Massachusetts (the "Berkshire Project"); (ii) a municipal waste
transfer station located in Columbia County, New York, near the Berkshire
Project (the "Columbia Project"); (iii) a natural gas-fired cogeneration
facility located in Monterey County, California (the "Monterey Project") and
(iv) various diesel and natural gas-fueled engines used to power irrigation well
pumps in Ventura County, California (the "California Pumping Project").
The Trust also invested $3.5 million in a district cooling facility
located in downtown San Diego, California, that supplies chilled water for
office building central air conditioning systems (the "San Diego Project"). The
Trust sold its interest in the San Diego Project in June 1997 for $6.15 million
to a subsidiary of a Minnesota-based utility. A portion ($2.7 million) of the
sale price is represented by an 8% secured promissory note of the buyer payable
monthly through June 25, 2003.
In accounting for its Projects, the Trust treats each Project as a
portfolio investment that is not consolidated with the Trust's accounts.
Accordingly, the revenues and expenses of each Project are not reflected in the
Trust's financial statements and only distributions are included as revenue when
declared. Accordingly, the recognition of revenue from Projects by the Trust is
dependent upon the timing of a declaration of distributions from Projects by the
Managing Shareholder. As discussed below and at Item 5. Market for Registrant's
Common Equity and Related Stockholder Matters, distributions from Projects may
include both income and capital components.
(2) The Trust's Investments.
(i) Berkshire Project.
On January 4, 1994, the Trust made an approximately $2.3 million equity
investment in Pittsfield Investors Limited Partnership, which was formed to
acquire the Berkshire Project, including the assets and business of Pittsfield
Resource Recovery Facility, from Vicon Recovery Associates ("Vicon"), the
developer and former operator of the facility. The Berkshire Project is a waste
to energy plant located in Pittsfield, Massachusetts. The Berkshire Project,
which has been operating since 1981, burns municipal solid waste supplied by the
City of Pittsfield ("Pittsfield"), surrounding communities and other providers.
The Trust's partners in the Berkshire Project are subsidiaries of
Energy Answers Corporation ("EAC"). EAC made an equity investment of
approximately $1.3 million in the Berkshire Partnership and also serves as
manager and operator of the facility.
The investment structure afforded the Trust a preferred 15% annual
return on its investment plus a potential share of any additional cash flow.
More specifically, the Trust is entitled to an annual preferred distribution of
available cash flow, representing revenue from the Berkshire Project, (after
funding debt service, debt service reserves and operating and maintenance
expenses) in an amount equal to 15% of its investment. In the event that
distributions are insufficient to pay the 15% preferred distribution in any
given year, the shortfall will be payable out of distributions, if any, in
subsequent years. After the Trust has received its 15% preferred distribution in
any given year, EAC is entitled to an annual management fee for operating and
managing the facility in an amount equal to $300,000, escalating with inflation.
After these initial distributions have been made, the Trust is entitled to
receive an additional amount equal to 5% of its investment and then EAC is
entitled to receive an additional amount equal to 10% of the amount previously
distributed to it. Any remaining distributable cash flow for the year will be
shared equally by the Trust and EAC.
Ownership rights to the Berkshire project are held under a long term
lease purchase agreement and related non recourse industrial revenue bond
financing agreements among the Berkshire Project, Pittsfield's industrial
development authority and others.
Distributions from the Berkshire Project ceased in the third quarter of
1998 and have not resumed. In the third quarter of 1998, EAC informed the Trust
that significant and undisclosed cost overruns in the construction of an ash
handling system for the Berkshire Project had depleted the Project's funds,
including reserve funds for closure of a landfill and other cash reserves. EAC
believed that the Berkshire Project could not continue operations without
significant capital injections from its two limited partners, one of whom is the
Trust. EAC further advised the Trust that even if the Project were to continue
operations with additional contributed capital, distributions from Berkshire to
the Trust would cease for an indefinite period. This resulted in large part from
the 1998 closure of the Pittsfield landfill, which forced the Project to
transport ash to a distant landfill site. Accordingly, the Trust wrote down the
estimated fair value of the Project to zero as of December 31, 1998.
The Berkshire Project receives "tipping fees" paid by the waste
suppliers based on the number of tons of waste delivered to the facility.
Tipping fees paid by Pittsfield are determined under a long-term waste supply
agreement, which will remain in effect until November 2004, although the
agreement may be cancelled by either party in June 2002. Tipping fees paid by
other waste suppliers are based on the spot market (i.e., current market
prices). The facility generates additional revenue by selling steam produced
from the waste burning process to a nearby paper mill owned by Crane & Co., Inc.
("Crane") under a long-term contract which will remain in effect until November
2004. The Crane paper mill manufactures currency paper stock used to print
United States currency (as well as currency paper stock for other governments).
(ii) Columbia Project.
On August 31, 1994, the Trust entered into the B-3 Limited Partnership,
with affiliates of EAC, the same firm with which the Trust participates in the
Berkshire Project. The Trust made an investment of approximately $4 million into
the B-3 Limited Partnership to construct a municipal waste transfer station
located in Columbia County, New York.
The purpose of a transfer station like the Columbia Project is to
provide a facility where municipal waste collected from nearby towns by smaller,
short haul trucks can be transferred to larger, long haul trucks for more
efficient transportation of the waste to distant landfills. The primary
customers for the Columbia Project are local waste haulers who dispose of waste
at local landfills scheduled for closing under state and federal requirements.
During the construction period, the Trust received interest on its
investment at the rate of 12% per annum. The Columbia Project commenced
operations in January 1995. The Trust is entitled to receive a cumulative
priority return on the Trust investment of 18% per annum, with any shortfalls
being carried forward into subsequent years. Thereafter, EAC affiliates will be
entitled to receive a management fee of $175,000 escalating with inflation. Any
additional cash flow will be split 50/50 between the Trust and EAC affiliates.
Returns at the Columbia Project have been impaired by repeated
extensions of the closing deadlines for some local landfills. If waste can be
cheaply deposited at local landfills, there is less demand for consolidating the
waste for transfer to distant sites. See Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations for additional
information.
(iii) Monterey Project.
On January 9, 1995, the Trust purchased 100% of the equity interests in
the Monterey Project, which is a 5.5 megawatt cogeneration project located in
the City of Salinas, Monterey County, California. The Trust paid a cash purchase
price of approximately $3.8 million and contributed four engine/generator sets,
valued at $1.3 million, which were owned by the Trust and cost approximately
$1.6 million. 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, a New Jersey limited liability company ("RPM"). RPM is a
service company affiliated with the Managing Shareholder, as further described
at Item 10(g) - Directors and Executive Officers of the Registrant RPM.
The Monterey Project is a "Qualifying Facility" under the Public
Utility Regulatory Policies Act of 1978, as amended ("PURPA"), because it is a
cogeneration facility that meets PURPA standards. Historically, producers of
electric power in the United States consisted of regulated utilities serving
end-use retail customers and certain industrial users that produced electricity
to satisfy their own needs. The independent power industry in the United States
was created by federal legislation passed in response to the energy crises of
the 1970s. PURPA, among other things, requires utilities to purchase electric
power from Qualifying Facilities, including "cogeneration facilities" and "small
power producers," and also exempts these Qualifying Facilities from most federal
and state utility regulatory requirements. In addition, the price paid by
electric utilities under PURPA for electricity produced by Qualifying Facilities
is the utility's avoided cost of producing electricity (i.e., the incremental
costs the utility would otherwise face to generate electricity itself or
purchase electricity from another source). Pursuant to PURPA, and state
implementation of PURPA, many electric utilities have entered into long-term
Power Contracts with rates set by contract formula approved by state regulatory
commissions. The Monterey Project sells its output to PG&E under the Power
Contract with a capacity and energy payment determined pursuant to a contract
formula approved by the California Public Utilities Commission ("CPUC"). The
capacity and energy price paid by PG&E pursuant to the Power Contract was
determined pursuant to a contract formula approved by the California Public
Utilities Commission ("CPUC") with the energy payment originally based upon a
benchmark energy price adjusted for changes over time in a gas index; the so
called "Short Run Avoided Cost Methodology" or SRAC. Historically, the contract
formula rates in most Power Contracts have been significantly higher than the
rates the utility could obtain in a competitive market. In some areas of the
country this still may be true. However, beginning during the summer of 2000 in
California, where the Monterey Project is located, due to the electric energy
crisis, competitive market rates where significantly higher than the formula
rates contained in many Qualifying Facilities' Power Contract.
The deregulation legislation in California passed in 1996 allowed
Qualifying Facilities to exercise a one-time option to elect to thereafter
receive energy payments based on the energy clearing price on the California
Power Exchange ("CalPx"), a short term day-ahead and day-of energy spot market,
which was created by the deregulation legislation. On September 1, 2000, the
Monterey Project exercised such option and switched from SRAC payment
methodology to the CalPx energy-clearing price. Thus, the energy payment earned
by the Project subsequent to the election was significantly higher than the
energy payment incorporated in the SRAC formula. However, subsequent events in
California, including certain orders issued by the Federal Energy Regulatory
Commission ("FERC") have caused the CalPx to suspend trading as of January 31,
2001 such that no CalPx "energy clearing price" currently exists. Therefore,
even though the Monterey Project is currently off-line (see below), the energy
price that PG&E would pay the Project if currently operating is unclear. See
Item 1(c)4 for further discussion regarding current issues raised by
California's electricity crises.
Currently, and as a result of the deregulation of the California energy
market, PG&E has allegedly suffered billions of dollars in losses during the
latter part of 2000 and to date in 2001 and is teetering on the brink of
bankruptcy. This has resulted in part because PG&E, like the other two
investor-owned electric utilities ("IOUs") in California, was required by the
1996 deregulation law to sell 50% of its fossil-fuel electric generation
resources located in California to unaffiliated third parties, although PG&E
sold more than such 50% amount. In addition, the law required that PG&E sell all
the electricity produced by its remaining electric generation resources to, and
purchase all of its electric energy needs from, the CalPx. During the early
years of deregulation, this framework worked well and was profitable for PG&E
because the wholesale price of electricity purchased from the CalPx was
substantially lower than the "frozen" retail price of electricity that PG&E
charged its end-use customers. The difference between the two prices was used by
PG&E to recoup stranded investments and pay dividends to its parent, PG&E
Corporation, which dividends were then invested in unregulated subsidiaries and
used for other corporate purposes. However, beginning in the summer of 2000, due
to explosive growth of power consumption in California, the lack of new electric
generation, water and fuel shortages, and other reasons, the situation changed
dramatically and the CalPx price for electricity was substantially higher than
the retail price that PG&E was permitted by law to charge. Therefore, the
difference between what PG&E paid for electricity and what it could resell such
electricity for resulted in huge losses. See, Section 4 - Trends in the Electric
Utility and Independent Power Industries.
Due to the California energy crisis, PG&E has been unable to pay in
full for electrical energy and capacity delivered in December 2000 and January
2001. Accordingly, the Monterey Project was unable to pay its natural gas
supplier for the gas delivered for that months. In late January, the gas
supplier requested assurance of payment before it would agree to provide natural
gas during February. Due to PG&E's financial 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. A number of other small cogeneration projects selling
electrical energy and capacity to California utilities have similar problems and
have shut down or expect to shut down their facilities shortly.
On February 1, 2000, PG&E made a partial payment equal to 15% of the
amount due for December 2000. On March 5, 2001, PG&E made another partial
payment equal to 15% of the amount due January 2001. Those amounts are
insufficient, after payroll costs are met, to cover the amount owed to the
natural gas supplier. PG&E effectively acknowledges that it owes the Project for
December and January by virtue of announcing and making a 15% partial payments.
On Tuesday, February 6, 2001, the Trust shut down the Monterey Project because
the supplier of natural gas terminated deliveries of natural gas as of that
date. The shut down will be for an indefinite time.
In addition to its failure to pay the full amount due for December 2000
and January 2001 deliveries, PG&E has indicated in letters to the Monterey
Project, as well as documents filed with the Securities and Exchange Commission,
that it is unable or unwilling to make future payments to Qualifying Facilities,
such as the Project. The Trust believes that PG&E's ability to pay for the
electrical energy and capacity it received or will receive in the future,
depends upon, among other things, positive action by the California governor and
legislature to fund approximately $12 billion of losses allegedly suffered by
California utilities during the last eight months. The Trust expects that any
such political solution may be accompanied by executive, legislative or
regulatory attempts to reduce unilaterally the amounts owed by PG&E to
Qualifying Facilities. In an effort to resolve the California crises, there have
been numerous proposals by the CPUC, as well as the legislature, to adjust
downward the prices paid by California utilities to Qualifying Facilities. The
Trust expects that any regulatory proceeding to set an energy price applicable
to Qualifying Facilities will be extremely protracted and that a legislative
solution, if one were to be enacted and approved by the governor, is likely to
be arbitrary and significantly below the avoided cost of the energy to PG&E.
PG&E has attempted to justify its non-payment by invoking the "force
majeure" provisions of the Power Contract. In essence, PG&E argues that it is
excused from its payment obligations because its failure to pay is the result of
the California Public Utilities Commission actions in failing to increase its
rates to retail customers and is beyond its control. The Trust disagrees and
believes that PG&E has breached the contract. The Project, along with the Byron
and San Joaquin Projects owned by Power III, filed a lawsuit on February 6, 2001
against PG&E to that effect and are seeking damages equal to lost net revenues
for the remaining term of the Power Contract. By this lawsuit the Trust seeks to
have the Power Contract with PG&E declared null and void so that the Project
will be able to sell its electric power on the open market to third party
purchasers who will be able to pay currently for such electric power. The Trust
expects that it will be able purchase natural gas if it is free from the PG&E
contract and able to sell to credit worthy purchasers. The Trust is seeking an
accelerated determination by the California court. The Trust is hopeful that an
accelerated determination by the court is a possibility considering the power
emergency in California, which may get worse as warm weather approaches and
power demand increases dramatically. Finally, PG&E currently has a proceeding
pending before the Federal Energy Regulatory Commission ("FERC") alleging that
the Monterey Project previously breached the Power Contract because it allegedly
failed to meet federal standards for being a Qualifying Facility. If that
proceeding before the Commission were determined adversely to the Monterey
Project, its ability to recover damages in the recently filed lawsuit against
PG&E may be compromised. Also, in an attempt to get the Project back on-line
quickly, on March 8, 2001, the Managing Shareholder, on behalf of the Trust and
Power III, filed with FERC a "Request For Emergency Relief and Extension of
Waiver of Qualifying Facility Regulations" in which the Managing Shareholder
likewise seeks an order from FERC permitting Qualifying Facilities to sell to
third parties.
See Item 1(a)(3) - Project Operations, Item 1(a)(4) - Developments in
the Power Industry, and Item 3 - Legal Proceedings below for additional
information concerning the potential effect of California's electric energy
crises and the litigation proceedings against PG&E.
(iv) California Pumping Project
In March 1995, the Trust purchased 100% of the equity interests in the
California Pumping Project, which is an irrigation service Project located in
Ventura County, California, for a cash purchase price of approximately $732,000.
The Trust has made additional investments of $220,000 to purchase additional
engines and expand the Project. The California Pumping Project provides power
equivalent to approximately 3 megawatts. The California Pumping Project has been
operating since 1992 and uses diesel and natural gas fired reciprocating engines
to provide power for irrigation wells, which furnish water for orchards of lemon
and other citrus trees. The power is purchased by local farmers and farmers'
co-operatives. Until recently, the price charged to the farmers represented a
discount from the equivalent price the customers would have paid to purchase
electric power. However, due to the dramatic increase in energy costs in
California resulting from the state's deregulation attempt and the dramatic
increase in the cost of natural gas and diesel fuel, it was apparent that the
California Pumping Project could not sustain a discounted price to the farmers.
As a result, the California Pumping Project wrote to all of the farmers under
contract with it and informed them that effective February 1, 2001, the flat
percentage discount for electric power was being eliminated and a fuel-surcharge
was being implemented in which the actual fuel costs would be passed on in full
to the farmers. In addition, the California Pumping Project also offered to
remove its engines if any farmer so requested as a result of the price increase
and fuel pass-through. To date, no farmer has so requested.
Until October 1998, the Trust had a management contract with the prior
operator of the Project. In October 1998, the Trust and the operator terminated
the management agreement and the Project paid the operator $105,840 to reimburse
it for installation costs advanced by the operator. RPM has operated the project
since that time and the Trust reimburses it for its costs and expenses.
Power IV owns a package of similar engines located on different sites
and operated under identical terms by the same operator. The engines operate
independently of each other and revenues and expenses for each Trust are
segregated from those of the other.
(v) San Diego Project.
The Trust acquired its interest in the San Diego Project on March 21,
1994, when it made an investment of approximately $2.3 million to acquire an 80%
interest in the Project. The Trust made additional capital contributions,
totaling approximately $1.2 million, to the Project to fund working capital and
to purchase various leased equipment.
On June 25, 1997 the Trust sold its entire interest in its San Diego
Project to subsidiaries of NRG Energy, Inc. of Minneapolis, Minnesota ("NRG").
The San Diego Project is a district cooling system located in downtown San
Diego, California, that generated and supplied chilled water through sub-street
piping to approximately 10 large office buildings. The sale took the form of a
sale of all of the Trust's limited partnership interest in the limited
partnership that owned the Project and its interest in the general partner. The
sale price was $6,200,000, of which $3,500,000 was paid in cash at the closing.
The remaining $2,700,000 was paid by delivery of a secured, purchase money
promissory note of the principal NRG subsidiary purchasing the Project. The note
bears interest at 8% per year and is payable in equal monthly installments of
principal and interest through its maturity on June 25, 2003. The note is
secured by the partnership interests sold by the Trust to the NRG subsidiaries.
NRG and its subsidiaries participating in the transaction were not
affiliated with and had no material relationships with the Trust, its Managing
Shareholder or their affiliates, directors, officers or associates of their
directors and officers. The sales price and the terms of the acquisition were
determined in arm's length negotiations between the Managing Shareholder of the
Trust and NRG.
(3) Project Operations.
The Monterey Project's revenue from its Power Contract consists of two
components, energy payments and capacity payments. Energy payments are based on
a facility's net electric output, with payment rates usually indexed to the fuel
costs of the purchasing utility or to general inflation indices. Capacity
payments are based on either a facility's net electric output or its available
capacity. Capacity payment rates vary over the term of a Power Contract
according to various schedules.
The Berkshire Project obtains waste for fuel under a long term contract
providing it with revenues from tipping fees, which are subject to the default
risks of dealing with municipalities and small trash haulers, and sells steam to
Crane under a long-term contract. The Columbia Project obtains its revenues from
spot and contract sales of transfer station services which are dependent upon
the volume of waste delivered to it and which are sensitive to the prices of
alternative disposal methods and local economic activity.
The California Pumping Project sells its power to the farmers on whose
land its engines are situated under contracts terminable at any time on 60 days'
prior notice to the Trust. Although the Trust thus is at risk if many customers
concurrently terminate contracts, as might happen if an electric utility or
other supplier were to offer substantially discounted rates, the Trust believes
that it is currently a competitive supplier and that alternate customers can be
secured in the event contracts are terminated.
The major costs of a Project while in operation will be debt service
(if applicable), fuel, taxes, maintenance and operating labor. The ability to
reduce operating interruptions and to have a Project's capacity available at
times of peak demand are critical to the profitability of a Project.
Accordingly, skilled management is a major factor in the Trust's business. The
Berkshire and Columbia Projects are managed by EAC, which has a subordinated
equity or an income interest in the Projects, which may create an additional
incentive for the manager. The Trust monitors their performance using RPM
personnel and outside consultants.
Electricity produced by a Project is delivered to the purchaser through
transmission lines that are built to interconnect with the utility's existing
power grid. Steam produced by the Berkshire Project is conveyed directly to the
user by pipeline and the energy produced by the engines in the California
Pumping Project is applied directly to pumps.
The overall demand for electrical energy is somewhat seasonal, with
demand usually peaking in the summertime as a result of the increased use of air
conditioning. Greenhouse demand for hot water from the Monterey Project peaks in
the winter and spring months. The impact of fluctuations in the demand or supply
of electrical or thermal products generated upon the revenues of any particular
Project is usually dependent on the terms of the Power Contract pursuant to
which the energy is purchased.
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 Qualifying
Facility under PURPA, it is imperative that the Monterey Project continue to
satisfy PURPA cogeneration requirements as to the amount of thermal products
generated. See Item 1(c)(6) - Regulatory Matters, for an explanation of these
requirements. Therefore, since the Monterey Project has only two customers (the
electric energy purchaser and the thermal products purchaser), loss of either of
these customers would have a material adverse effect on the Monterey Project.
From time to time since 1992 PG&E has questioned whether the Monterey
Project is delivering sufficient thermal energy to the greenhouse customer to
meet PURPA efficiency requirements for Qualifying Facility status and has
installed metering devices to provide data. These inquiries are in large part
based on data from the monitoring program that PG&E undertakes as required by
the CPUC for data on thermal deliveries.
In February 1999, PG&E notified the Trust that it had concluded that
the Monterey Project had not met those efficiency requirements by an unspecified
amount and on April 1, 1999 it brought legal proceedings in California state
court against the Trust's subsidiary that owns the Project, as described at Item
3 - Legal Proceedings. The complaint only requested that the Project refund the
gas price discounts received from 1991 to 1998, but an adverse decision might
affect subsequent years and might also serve as the basis for refund to PG&E by
the Monterey Project of certain payments made by PG&E as a result of the
Monterey Project's status as a Qualifying Facility and an action to invalidate
the Power Contract.
The Trust has vigorously defended the lawsuit. In February 2000, the
parties agreed that the lawsuit in the State of California would be dismissed
without prejudice and the matter transferred before FERC. The evidence obtained
in the state proceeding could be used in the FERC proceeding. In late 2000, PG&E
filed a petition at FERC seeking, among other things, a revocation of the
Monterey Project's Qualifying Facility status and a refund of what PG&E claims
are overpayments made by PG&E to the Project. After an exhaustive investigation,
the Trust believes that the Monterey Project has met and continues to meet the
PURPA requirements and that PG&E is relying on an incorrect legal theory and
incorrect data. In particular, the Trust believes that PG&E has chosen the wrong
location for metering and computing efficiency standards. That location is
materially different from the location at which efficiency was measured from the
inception of the Project and is located at a point where efficiency measurements
necessarily would be materially lower. The Trust also believes that the
utility's gas meter was out of adjustment during 1998. During 2000, the Trust
incurred significant legal fees in defending this proceeding and preparing for
action before FERC. All of the required and permitted filings have been prepared
and submitted to FERC by both Parties and the Trust expects that legal expenses
for 2001 applicable to this matter will be significantly less than 2000. FERC
has not rendered a decision in the matter, however, and when FERC rules the
non-prevailing party may seek rehearing of, or appeal, the FERC decision; thus
causing legal fees to increase significantly. The legal expenses are being paid
by the Trust's subsidiary that owns the Monterey Project and accordingly they do
not appear on the Trust's financial statements.
If it is determined that the Monterey Project did not meet PURPA and
California efficiency standards, it would be required to refund the discount to
PG&E for the period of non-compliance. Depending on the results of the FERC
proceeding, if it were determined that the Monterey Project did not comply for a
substantial period of time, the possible refund could be extremely large. It is
also possible that the Power Contract could be invalidated, which might make the
Project uneconomic to operate, but given the need for electric generation in
California and the relative economic price of the Monterey Project's electric
generation, PG&E may ultimately decide to retain the Power Contract. See Item
1(c)(4) - Trends in the Electric Utility and Independent Power Industries for
further information.
Major customers of Projects that accounted for more than 10% of annual
distributions to the Trust from operating sources in each of the last three
fiscal years are:
Calendar year
2000 1999 1998
Pacific Gas & Electric Co. 44.5% 0.0%* 54.0%
Crane & Co., Inc. 0.0% 0.0% 18.0%
* All of the $326,000 of net cash flow earned by the Monterey Project in 1999
was retained to defray legal expenses.
The Columbia and California Pumping Projects have many customers. No
one customer accounted for 10% or more of the total received by the Trust during
the year.
The technology involved in conventional power plant construction and
operations as well as electric and heat energy transfers and sales is widely
known throughout the world. There are usually a variety of vendors seeking to
supply the necessary equipment for any Project. So far as the Trust is aware,
there are no limitations or restrictions on the availability of any of the
components, which would be necessary to complete construction and commence
operations of any Project. Generally, working capital requirements are not a
significant item in the independent power industry. The cost of maintaining
adequate supplies of fuel sources is usually the most significant factor in
determining working capital needs.
Hydrocarbon fuels, such as natural gas, coal and fuel oil, have been
generally available in recent years for use by Independent Power Projects,
although there have been serious supply impairments for both oil and natural gas
at times during the last 20 years. Market prices for natural gas, oil and, to a
lesser extent, coal have fluctuated significantly over the last few years and
have increased significantly during 2000. Such increase in natural gas prices
may directly inhibit the development of Projects because of the anticipated
effects on Project profitability and may deter lenders to Projects or result in
higher costs of financing. The Berkshire Project uses municipal wastes as fuel
and the Columbia Project charges on the basis of volume of waste. The
availability of spot waste (waste delivered otherwise than under contract)
depends on the costs of other disposal alternatives.
In order to commence operations, most Projects require a variety of
permits, including zoning and environmental permits. Inability to obtain such
permits will likely mean that a Project will not be able to commence operations,
and even if obtained, such permits must usually be kept in force in order for
the Project to continue its operations.
Compliance with environmental laws is also a material factor in the
independent power industry. The Trust believes that capital expenditures for and
other costs of environmental protection have not materially disadvantaged its
activities relative to other competitors and will not do so in the future. The
Trust currently does not anticipate that it will have to make material
additional investments for environmental compliance. The process of preparing
the new Title V applications for air pollution licensing of existing facilities,
however, is protracted and requires modest additional expenditures for
consultants. If future environmental standards require that a Project spend
increased amounts for compliance, such increased expenditures could have an
adverse effect on the Trust to the extent it is a holder of such Project's
equity securities. See Item 1(c)(6) - Business - Narrative Description of
Business - Regulatory Matters.
(4) Trends in the Electric Utility and Independent Power Industries
In September 1996, California enacted Assembly Bill 1890 ("AB 1890"),
which totally restructured California's existing monopolistic electric utility
industry into a market-based competitive industry. Among other things, AB 1890
required that California's investor-owned utilities ("IOUs") sell 50% of their
fossil-fueled electric generation assets to unaffiliated third parties. The
money received for these assets was used, among other purposes, to reduce
stranded investments. The IOUs, however, were permitted to retain certain
generation assets, including generation from Qualifying Facilities, certain
hydroelectric generation facilities, fossil-fueled generation not sold, and
nuclear generation facilities ("IOU Retained Generation"). In addition, AB 1890
created the CalPx, a day-ahead and day-of energy spot market, and required that
the IOUs sell all of the electric generation from their IOU Retained Generation
to, and purchase all of their electric supply needs from, the CalPx. In
addition, the rates that the IOUs were permitted to charge their retail end-use
customers were frozen at certain levels until the end of the transition period,
which for PG&E was anticipated to end in approximately 2003.
From the passage of AB 1890 until approximately the summer of 2000, the
framework instituted by AB 1890 worked well in that the wholesale price for
electricity purchased from the CalPx by PG&E and the other IOUs was
significantly lower than the frozen retail rates that PG&E was permitted to
charge to retail customers. The resulting "profit" made by PG&E was used, among
other things, to recoup PG&E's stranded investments and to pay dividends to
PG&E's corporate parent, PG&E Corporation ("PG&E Corp."). PG&E Corp. then used
such funds to invest in unregulated assets as well as for other general
corporate purposes. However, during the summer of 2000 the situation changed
dramatically. The CalPx wholesale price of electricity increased significantly
due in large part to California's explosive growth in power consumption,
environmental regulation, natural gas shortages, the failure of the state to add
any significant electric generation facilities for over a decade, and the lack
of available electric energy from other areas of the West. PG&E was now
purchasing its electric generation needs at wholesale prices significantly above
the frozen retail rates it was permitted by AB 1890 to charge to retail
customers. As a result, PG&E has incurred substantial losses and, as described
above, has suspended payments to Qualifying Facilities, as well as to the CalPx
and other creditors. Unless some resolution is worked out, PG&E may ultimately
declare bankruptcy. In such event, the Power Contract with PG&E would be subject
to modification or rejection and given the situation in California there can be
no assurance that PG&E will not declare bankruptcy.
There have been numerous proposals and actions taken by a variety of
parties in California in an attempt to find a reasonable and workable solution
to the electric crises. For example, FERC removed the requirement that the IOUs
purchase all of their electricity needs from the CalPx. In addition, a wholesale
rate soft cap or "breakpoint" of $150 Mwh has been imposed by FERC, however,
most believe it is a short-term measure as such cap may provide a disincentive
to the construction of new power plants and transmission facilities. Although
the market cap is a short-term solution, there is a reasonable probability that
such wholesale rate caps may be continued for an indefinite period of time. The
CalPx was unable to institute and operate under the $150 Mwh breakpoint and, as
a result of this and certain other FERC orders, suspended trading as of January
31, 2001.
The IOUs in California have also sought to remedy the problems by
seeking regulatory and legal relief from the losses they have incurred. PG&E and
Southern California Edison Company ("SCE") each petitioned the CPUC seeking
relief from the retail rate freeze and an increase of approximately 30% in
retail rates. The CPUC approved only a 10% increase, significantly less than
requested and far below what was necessary for PG&E and SCE to remain solvent.
PG&E and SCE have also instituted separate court actions seeking to have the
court rule that the high wholesale power costs they have incurred in obtaining
power for their retail load must by law be allowed to be passed through to
retail rate payers.
In addition, the CPUC gave IOUs permission to enter into long-term
bilateral power contracts with independent energy producers ("IPPs"). However,
due to PG&E's failure to make payments to the CalPx for past energy deliveries,
which in turn meant that the CalPx could not pay such IPPs, many large IPPs were
reluctant to make further energy deliveries to the CalPx or directly to PG&E
without being paid for past deliveries and receiving assurances of future
payments. PG&E could do neither and during the later part of 2000 and early
2001, such IPPs were ordered either by the Secretary of the United States
Department of Energy or by the federal courts to continuing selling power. These
orders essentially required the IPPs to sell to the CalPx, prior to its
suspension of trading, the California Independent System Operator, which is
still operating, but primarily to the California Department of Water Resources
("DWR"), a state agency that has been purchasing power at wholesale from IPPs
(but not from Qualifying Facilities) and reselling it to the IOUs at prices that
approximate the IOUs retail rate authorization, which is significantly lower
that the wholesale price. As a result, the California DWR is losing substantial
sums of money such that approximately every month the California legislature has
to appropriate more funds for the DWR to continue purchasing. None of those
orders forcing electric sales, however, applied to Qualifying Facilities.
Finally, the California legislature has been considering certain
proposals to substitute an arbitrarily derived price for the energy price to be
paid to Qualifying Facilities. Any regulatory proceeding to set an energy price
applicable to Qualifying Facilities will be extremely protracted and a
legislative solution, if one were to be enacted and approved by the governor, is
likely to be arbitrary and below the avoided cost of the energy to the IOUs.
Because federal law requires that Qualifying Facilities be paid at least the
avoided cost to IOUs of obtaining the same amount of energy from a marginal
supplier, if the energy price set by California is less than that avoided cost,
Qualifying Facilities will have the right to sue for the correct avoided cost
price in federal court or before the FERC. Such proceedings could also be
protracted and expensive unless the FERC acts on its own or other generators
bring a proceeding before the Commission or a court.
Prior to the summer of 2000, many IOUs were attempting to purchase and
terminate the Power Contracts of Qualifying Facilities because, historically,
the electric rates paid to Qualifying Facilities have been significant higher
than wholesale power rates. Currently, however, the rates paid to Qualifying
Facilities by California IOUs are lower than current wholesale power rates and,
if the legislation proposed to substitute a legislatively derived energy price
is enacted and survives legal challenges, Qualifying Facilities will be an
attractive generating asset for California's IOUs.
Finally, the Power Contracts are subject to modification or rejection
in the event that the utility purchaser enters bankruptcy. There can be no
assurance that the utility purchaser will not declare bankruptcy.
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 purchased at market prices and because the Projects 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. However, if the Power Contract were to be
terminated now, the shortage of electric generation in California would allow
the Trust to market the electric energy and capacity from the Monterey Project.
In such event, the Trust believes that in the near term, until additional
generation resources are completed and brought on-line, it could sell its output
in California profitably, although for a variety of factors, including the
volatility of natural gas prices, unexpected legislation and litigation, there
is no guarantee that it may be able to do so if the Power Contract were to be
terminated.
The Berkshire Project's contract to supply steam terminates in 2004,
although it may be terminated in June 2002 by the Project or Crane. Because it
is normally inefficient to transport steam over long distances, the Trust
believes that so long as the cost of suitable municipal waste does not
substantially increase or the costs of alternate fuels does not decrease far
below current levels, the Berkshire Project should be able to renew its contract
at a price comparable to or lower than the cost to Crane & Co. of running its
own boilers or using a new cogeneration facility. There is no assurance that the
Project can do so or that the customer will be financially capable of doing so.
The Columbia and California Pumping Projects do not have long-term
contracts with any of their customers and are thus exposed to short and
long-term market fluctuations.
(5) Competition
The Monterey Project is not currently subject to competition because it
has entered into long-term agreements to sell its output at specified prices.
However, the Monterey Project could be subject to future competition to market
its electricity output if its Power Contract expires or is terminated because of
a default or failure to pay by the purchasing utility or other purchaser; due to
bankruptcy or insolvency of the purchaser; because of the failure of a Project
to comply with the terms of the Power Contract; regulatory changes; or other
reasons. The Monterey Project would then face competition to market its capacity
and energy output. However, the Trust believes that in the near term, until
additional generation resources are completed and brought on-line, it could sell
its output in California profitably, although for a variety of factors,
including the volatility of natural gas prices, unexpected legislation and
litigation, there is no guarantee that it may be able to do so. The Berkshire
Project may face competition after 2002 from fuel suppliers offering alternative
means of providing energy and from other cogeneration or waste-to-energy
providers.
There are a large number of participants in the independent power
industry. Several large corporations specialize in developing, building and
operating Independent Power Projects. Equipment manufacturers, including many of
the largest corporations in the world, provide equipment and planning services
and provide capital through finance affiliates. Many regulated utilities are
preparing for a competitive market, and a significant number of them already
have organized subsidiaries or affiliates to participate in unregulated
activities such as planning, development, construction and operating services or
in owning exempt wholesale generators or up to 50% of Independent Power
Projects. In addition, there are many smaller firms whose businesses are
conducted primarily on a regional or local basis. Many of these companies focus
on limited segments of the cogeneration and independent power industry and do
not provide a wide range of products and services. There is significant
competition among non-utility producers, subsidiaries of utilities and utilities
themselves in developing and operating energy-producing projects and in
marketing the power produced by such projects.
The Trust is unable to accurately estimate the number of competitors
but believes that there are many competitors at all levels and in all sectors of
the industry. Many of those competitors, especially affiliates of utilities and
equipment manufacturers, may be far better capitalized than the Trust.
The Columbia Project, as described above, faces competition from a
national waste management company much larger than itself, from local landfill
operators (if their permits to receive waste are again extended) and possibly
from other local entrepreneurs. There are few barriers to entry in the waste
transfer and management industry. The California Pumping Project is subject to
competition from the local electric utility, which serves much of Southern
California and which offers electricity at discounted rates to operate electric
pumps rather than the natural gas-fueled pumps operated by the Project. As
deregulation of the electricity market proceeds in California, the Project will
also face competition from power marketers and independent generating companies.
Barriers to entry into the electric or gas-fueled irrigation pumping industry
are also low.
(6) Regulatory Matters.
Projects are subject to energy and environmental laws and regulations
at the federal, state and local levels in connection with development,
ownership, operation, geographical location, zoning and land use of a Project
and emissions and other substances produced by a Project. These energy and
environmental laws and regulations generally require that a wide variety of
permits and other approvals be obtained before the commencement of construction
or operation of an energy-producing facility and that the facility then operates
in compliance with such permits and approvals. Since the Trust operates as a
"business development company" under the 1940 Act, it is also subject to
provisions of that act pertaining to such companies.
(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. Qualifying Facilities 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, state laws regarding rate or
financial regulation. In order to be a Qualifying Facility, 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 Qualifying
Facilities 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 Qualifying Facilities are important to the Trust and its competitors.
The Trust believes that each of its Projects is a Qualifying Facility. If a
Project loses its Qualifying Facility status, the utility can reclaim payments
it made for the Project's non-qualifying output to the extent those payments are
in excess of current avoided costs or the Project's Power Contract can be
terminated by the electric utility.
(B) The 1992 Energy Act. The Comprehensive Energy Policy Act of 1992
(the "1992 Energy Act") empowered FERC to require electric utilities to make
available their transmission facilities to and wheel power for Independent Power
Projects under certain conditions and created an exemption for electric
utilities, electric utility holding companies and other independent power
producers from certain restrictions imposed by the Holding Company Act. Although
the Trust believes that the exemptive provisions of the 1992 Energy Act will not
materially and adversely affect its business plan, the 1992 Energy Act may
result in increased competition in the sale of electricity.
The 1992 Energy Act created the "exempt wholesale generator" category
for entities certified by FERC as being exclusively engaged in owning and
operating electric generation facilities producing electricity for resale.
Exempt wholesale generators remain subject to FERC regulation in all areas,
including rates, as well as state utility regulation, but electric utilities
that otherwise would be precluded by the Holding Company Act from owning
interests in exempt wholesale generators may do so. Exempt wholesale generators,
however, may not sell electricity to affiliated electric utilities without
express state approval that addresses issues of fairness to consumers and
utilities and of reliability.
(C) The Federal Power Act. The FPA grants FERC exclusive rate-making
jurisdiction over wholesale sales of electricity in interstate commerce. 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 Qualifying
Facilities 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 Qualifying Facilities 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-Qualifying
Facility 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-Qualifying
Facilities and, among other things, issuance of securities, related party
transactions and sale and transfer of assets. The actual scope of jurisdiction
over non-Qualifying Facilities 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.
Title V of the Clean Air Act Amendments added a new permitting
requirement for existing sources that requires all significant sources of air
pollution to submit new applications to state agencies. Title V implementation
by the states generally does not impose significant additional restrictions on
the Trust's Projects, other than requirements to continually monitor certain
emissions and document compliance. The permitting process is voluminous and
protracted and the costs of fees for Title V applications, of testing and of
engineering firms to prepare the necessary documentation have increased. The
Trust believes that all of its facilities, which require Title V compliance, are
or will be in compliance with such requirements.
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 "NPDES" permits for point sources
of discharges and by storm water permits. Under the Clean Water Act, NPDES
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 Qualifying Facility 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) The 1940 Act
Since its Shares are registered under the 1934 Act, the Trust is
required to file with the Commission certain periodic reports (such as Forms
10-K (annual report), 10-Q (quarterly report) and 8-K (current reports of
significant events)) and to be subject to the proxy rules and other regulatory
requirements of that act that are applicable to the Trust. The Trust has no
intention to and will not permit the creation of any form of a trading market in
the Shares in connection with this registration.
As a "business development company," the Trust is a closed-end company
(defined by the 1940 Act as a company that does not offer for sale or have
outstanding any redeemable security) that is regulated under the 1940 Act only
as a business development company. The act contains prohibitions and
restrictions on transactions between business development companies and their
affiliates as defined in that act, and requires that a majority of the board of
the company be persons other than "interested persons" as defined in the act.
The board of the Trust is comprised of Ridgewood Power and three individuals,
Ralph O. Hellmold, Jonathan C. Kaledin and Joseph Ferrante, Jr., who also serve
as independent trustees of Power III, and who are Independent Panel Members for
Power V but who are not otherwise affiliated with the Trust, Ridgewood Power or
any of their affiliates. See Item 10 - Directors and Executive Officers of the
Registrant.
Under the 1940 Act, Commission approval is required for certain
transactions involving certain closely affiliated persons of business
development companies, including many transactions with the Managing Shareholder
and the other investment programs sponsored by the Managing Shareholder. There
can be no assurance that such approval, if required, would be obtained. In
addition, a business development company may not change the nature of its
business so as to cease to be, or to withdraw its election as, a business
development company unless authorized to do so by at least a majority vote of
its outstanding voting securities.
The 1940 Act restricts the kind of investments a business development
company may make. A business development company may not acquire any asset other
than a "Qualifying Asset" unless, at the time the acquisition is made,
Qualifying Assets comprise at least 70% of the company's total assets by value.
The principal categories of Qualifying Assets that are relevant to the Trust's
activities are:
(A) Securities issued by "eligible portfolio companies" that are
purchased by the Trust from the issuer in a transaction not involving any public
offering (i.e., private placements of securities). An "eligible portfolio
company" (1) must be organized under the laws of the United States or a state
and have its principal place of business in the United States; (2) may not be an
investment company other than a small business investment company licensed by
the Small Business Administration and wholly-owned by the Trust and (3) may not
have issued any class of securities that may be used to obtain margin credit
from a broker or dealer in securities. The last requirement essentially excludes
all issuers that have securities listed on an exchange or quoted on the National
Association of Securities Dealers, Inc.'s national market system, along with
other companies designated by the Federal Reserve Board. Except for temporary
investments of the Trust's available funds, substantially all of the Trust's
investments are expected to be Qualifying Assets under this provision.
(B) Securities received in exchange for or distributed on or with
respect to securities described in paragraph (A) above, or on the exercise of
options, warrants or rights relating to those securities.
(C) Cash, cash items, U.S. Government securities or high quality debt
securities maturing not more than one year after the date of investment.
A business development company must make available "significant
managerial assistance" to the issuers of Qualifying Assets described in
paragraphs (A) and (B) above, which may include without limitation arrangements
by which the business development company (through its directors, officers or
employees) offers to provide (and, if accepted, provides) significant guidance
and counsel concerning the issuer's management, operation or business objectives
and policies.
A business development company also must be organized under the laws of
the United States or a state, have its principal place of business in the United
States and have as its purpose the making of investments in Qualifying Assets
described in paragraph (A) above.
The Managing Shareholder believes that it may no longer be necessary
for the Trust to continue its status as a business development company, because
of the Managing Shareholder's active involvement in operating Projects through
the Trust and other investment programs. Although the Managing Shareholder
believes it would be beneficial to the Trust to end the election and reduce
costs of legal compliance that do not contribute to income, the process of
withdrawing the business development company election requires a proxy
solicitation and a special vote of investors, which is also costly. Accordingly,
the Managing Shareholder does not intend at this time to request the Investors'
consent to withdrawing the business development company election. Any change in
the Trust's status will be effected only with the Investors' consent.
(iv) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not
limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are
subject to amendment or repeal. Future legislation and regulation is uncertain,
and could have material effects on the Trust.
(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 California 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 interest. Ownership rights to the property associated with the
Berkshire Project are held under a long-term lease-purchase agreement and
related non-recourse industrial revenue bond financing agreements among
Pittsfield's industrial development authority and others. Upon repayment of the
bonds and the satisfaction of other conditions, the partnership which operates
the facility and in which the Trust owns an interest, will have the option to
acquire the facility for nominal consideration. The other properties are not
subject to any mortgages, liens or encumbrances. All of the Projects are
described in further detail at Item 1(c)(2).
Square
Ownership Ground Approximate Footage of Description
Interests Lease Acreage Project(Actual of
Project Location in Land Expiration of Land or Projected) Project
Berkshire Pittsfield,
MA Leased 2004 5 30,000 Waste-to energy
Columbia Columbia,
NY Owned N/A 44 25,000 Municipal waste
Monterey Monterey,
CA Leased 2020 2 10,000 Gas-fired
California Ventura Cy, Leased N/A N/A N/A Natural gas
Pumping CA or engines powering
licensed irrigation pumps
Item 3. Legal Proceedings.
On April 1, 1999, PG&E sued the Trust's subsidiary that owns the
Monterey Project in the Superior Court of California for the City and County of
San Francisco. PG&E alleged that the Project did not meet federal and state
efficiency requirements and that accordingly the Project was not entitled to the
benefit of discounted natural gas fuel rates allowable to qualifying
cogeneration facilities. The lawsuit claimed an unspecified amount of damages.
The State lawsuit was dismissed without prejudice and by agreement of the
parties and the matter was brought by PG&E to the FERC by petition for a
determination. PG&E filed with FERC a petition seeking a revocation of the
Monterey Project's Qualifying Facility status and a refund of certain
overpayments PG&E claims it made to the Project, which were not justified due to
the Project's failure to maintain Qualifying Facility status. The FERC
proceeding generally involves a determination of the proper location for
metering and computing efficiency standards. The Trust believes that its
location of the meter is correct for determining such standards and that it will
succeed at FERC and retain its Qualifying Facility status and that no refunds
will be required. All of the required or permitted filings have been prepared
and submitted to the FERC and the parties are awaiting a decision. No other
activity on this matter is anticipated until such FERC decision.
As described above, on February 6, 2001, the Monterey Project, along
with the Byron and San Joaquin Projects owned by Power III, filed an action in
the Superior Court of California for the City and County of San Francisco
against PG&E seeking, among other things, that PG&E's failure to pay is a breach
of the Power Contract and not excused by the force majeure provisions of the
Power Contract. In addition, the suit seeks an expedited determination and
declaration that PG&E has breached the Power Contract, that it therefore null
and void and PG&E is liable for damages to the Trust including, but not limited
to, the lost net revenues for the remaining term of the Power Contract
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 $175,000 and to cooperate with the Project in the potential FERC
proceedings involving the Monterey Project and the Trust agreed to cooperate
with Waukesha-Pierce in releasing funds due from PG&E to Waukesha-Pierce.
Item 4. Submission of Matters to a Vote of Security Holders. The Trust did
not submit any matters to a vote of the Investors during the fourth quarter of
2000.
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 and the
Trust has no intention to make any public offering of 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 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 is considering the possibility of a
combination of the Trust and six other investment programs sponsored by the
Managing Shareholder 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, compliance with the "rollup" rules of the Securities and Exchange
Commission and other regulations, and a change in the federal income tax status
of the Trust from a partnership (which is not subject to tax) to a corporation.
The process of considering and effecting a combination, if the decision is made
to do so, will be very lengthy. There is no assurance that the Managing
Shareholder will recommend a combination, that the Investors of the Trust or
other programs will approve it, that economic conditions or the business results
of the participants will be favorable for a combination, that the combination
will be effected or that the economic results of a combination, if effected,
will be favorable to the Investors of the Trust or other programs.
(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 2000 and 1999:
Year ended Year ended
December 31, December 31,
2000 1999
Total distributions to Investors $ 706,925 $282,456
Distributions per Investor Share $ 3,003 $ 1,200
Distributions to Managing Shareholder $ 7,141 $ 2,853
The Trust suspended distributions in April 1999 to create a reserve at
the Monterey Project level for the costs of the Monterey Project legal
proceedings. The Managing Shareholder resumed limited quarterly distributions
from the Trust beginning in April 2000 and then discontinued them effective
January 1, 2001. The Trust's decision whether to make future distributions to
Investors and their timing will depend on, among other things, the net cash flow
of the Trust, the expenses of the legal proceedings for the Monterey Project and
retention of reasonable reserves as determined by the Trust to cover its
anticipated expenses. See Item 7 Management's Discussion and Analysis.
The Trust's cash flow comes primarily from distributions from Projects.
Those distributions are from cash flow of the Projects, which includes income of
Projects plus funds representing depreciation and amortization charges taken by
the Projects. Nevertheless, because the Projects are not consolidated with the
Trust for accounting purposes, all funds received from Projects are considered
to be revenue to the Trust for accounting purposes. Occasionally, distributions
may also include funds derived from operating or debt service reserves or other
non-cash charges against earnings. Investors should be aware that the Trust is
organized to return net cash flow rather than accounting income to Investors.
Item 6. Selected Financial Data.
The following data is qualified in its entirety by the financial statements
presented elsewhere in this Annual Report on Form 10-K.
Supplemental Information Schedule
Selected Financial Data As of and for the years ended December 31,
(amounts in $) 2000 1999 1998 1997 1996
Total Fund Information:
Net revenue from
operating projects $ 556,079 $ 131,859 $ 953,576 $1,715,860 $2,371,208
Net income (loss) 594,935 94,608(1,704,811) 3,591,765 1,907,401
Net assets
(shareholders' equity) 11,822,573 11,941,704 12,132,405 15,263,754 16,353,759
Investments in Project
development and power
generation limited
partnerships 10,751,582 10,274,790 10,594,402 12,733,179 16,116,582
Note receivable 1,283,327 1,729,181 2,140,866 0 0
Total assets 12,135,310 12,544,818 12,747,675 15,432,434 16,466,241
Per Investor Share:
Project Revenues $ 2,362 $ 560 $ 4,051 $ 7,289 $10,074
Expenses 500 849 12,129 3,415 1,705
Net income (loss) 2,528 402 (7,243) 15,260 8,371
Net asset value 50,581 51,082 51,884 65,054 69,639
Distributions per
Investor Share $3,003 $ 1,200 $ 6,000 $19,692 $ 8,849
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 elsewhere
herein. The Trust's financial statements are prepared under generally accepted
accounting principles applicable to business development companies. Accordingly,
the Trust carries its investment in the Projects it owns at fair value and does
not consolidate its financial statements with the financial statements of the
Projects.
Revenue is recorded by the Trust as cash distributions are declared by
the Projects. Trust revenues may fluctuate from period to period depending on
the operating cash flow generated by the Projects and the amount of cash
retained to fund capital expenditures. Dollar amounts in this discussion are
generally rounded to the nearest $1,000.
Outlook
The U.S. electricity markets are being restructured and there is a
trend away from regulated electricity systems towards deregulated, competitive
market structures. California, where the Trust's Monterey Project operates, has
passed new legislation that permits utility customers to choose their
electricity supplier in a competitive electricity market. The Monterey Project
is a "Qualifing Facility" as defined under the Public Utility Regulatory
Policies Act of 1978 and currently sells its electric output to a utility under
a long-term contract expiring in 2021. During the term of the contract, the
utility may or may not attempt to buy out the contract prior to expiration. At
the end of the 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 California 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.
Results of Operations
Year ended December 31, 2000 compared to year ended December 31, 1999
Total revenue increased 141.7% to $713,000 in 2000 compared to $295,000
in 1999, due to increased income from power generation.
Project 2000 1999
--------- --------
Monterey ............... $247,000 $ --
Columbia ............... 300,000 100,000
California Pumping ..... 9,000 32,000
-------- --------
Total .................. $556,000 132,000
-------- --------
The increase in income from the Monterey Project was attributable to an
increase in revenue due to the Project's election to switch the pricing of its
electricity sales from a cost based price to a market based price in the third
quarter of 2000.
The increase in income from the Columbia Project was due to both an
increase in the volume of waste received by the project as well as increase in
the tipping fee per ton of waste received.
Total expenses decreased $82,000 (41.0%) to $118,000 in 2000 from
$200,000 in 1999 primarily due to a reduction in the management fee of $56,000.
This decrease was a result of the Manager Shareholder waiving its management fee
beginning in April 1999. Interest expense decreased from $27,000 in 1999 to
$9,000 in 2000 as a result of lower average outstanding borrowings under its
line of credit agreement. Other 2000 Trust expenses were comparable to 1999.
Year ended December 31, 1999 compared to year ended December 31, 1998
Total revenue decreased 74.3% to $295,000 in 1999 compared to
$1,150,000 in 1998, due to lower income from power generation. As summarized
below, income from power generation projects decreased 86.2% to $132,000 in 1999
compared to $954,000 in 1998:
Project 1999 1998
--------- --------
Monterey ............... $ -- $515,000
Berkshire .............. -- 176,000
Columbia ............... 100,000 250,000
California Pumping ..... 32,000 13,000
-------- --------
Total .................. $132,000 $954,000
-------- --------
The decline from the Monterey Project was attributable to the Project's
increased legal costs associated with the litigation with Pacific Gas &
Electric.
The decline in revenue at Berkshire was a result of distributions from
the project ceasing in the third quarter of 1998. In the third quarter of 1998,
the manager of Berkshire informed the Trust that significant cost overruns in
the construction of an ash handling system for the Berkshire project had
depleted Berkshire's funds, including reserve funds for closure of a landfill
and other reserves. The project manager believed that Berkshire could not
continue long-term operations without significant capital injections from its
two limited partners, one of whom is the Trust. The project manager further
advised the Trust that distributions from Berkshire to the Trust would cease.
The Trust's managing shareholder requested detailed additional information and a
revised operating plan from the project manager and conducted on-site reviews by
its financial and engineering personnel. The Trust has reviewed the short-term
and long-term viability of the Berkshire project and wrote down the carrying
value of the investment from $2,347,000 to zero.
Distributions from the California Pumping Project increased from
$13,000 in 1998 to $32,000 in 1999. The increase was a result of increased
demand for water pumping due to the absence of the extraordinary rainfall that
occurred in California in the first half of 1998. In addition, 1998 results were
negatively impacted by the cost of terminating the operating agreement with the
third party manager. The Trust paid $106,000 to the third party manager to
terminate the operating agreement. However, the increased revenue in 1999 and
absence of the 1998 contract termination cost were partially offset by increased
costs caused by rising fuel prices.
Although 1999 operating results at the Columbia Project were consistent
with 1998 results, cash received from the project decreased to $100,000 in 1999
from $250,000 in 1998 because the project manager reduced distributions to
increase the project's cash reserves.
Total expenses decreased $2,655,000 (93.0%) to $200,000 in 1999
compared to $2,855,000 in 1998, primarily due to the absence of a $2,347,000
writedown of the Berkshire Project in 1998. In addition, the management fee
decreased from $382,000 in 1998 to $56,000 in 1999 because the Manager
Shareholder waived its management fee beginning in April 1999. Interest expense
increased from $7,000 in 1998 to $27,000 in 1999 as a result of higher average
outstanding borrowings under its line of credit agreement. All other 1999 Trust
expenses were comparable to 1998.
Liquidity and Capital Resources
During 2000, the Trust's operating activities generated $666,000 of
cash compared to $723,000 of cash during 1999. The change is primarily
attributable to increased working capital requirements at the Monterey project
due to higher fuel prices. Cash distributions to shareholders increased to
$714,000 in 2000 from $285,000 in 1999. The Trust ceased making distributions to
shareholders in the second quarter of 1999 and resumed making them in the second
quarter of 2000. Then, in the first quarter of 2001, the Trust again ceased
making distributions to shareholders.
In 1997, the Trust and Fleet Bank, N.A. (the "Bank") entered into a
revolving line of credit agreement, whereby the Bank provides a three-year
committed line of credit facility of $750,000. The credit line was extended
until March 2001. Outstanding borrowings bear interest at the Bank's prime rate
or, at the Trust's choice, at LIBOR plus 2.5%. The credit agreement requires the
Trust to maintain a ratio of total debt to tangible net worth of no more than 1
to 1 and a minimum debt service coverage ratio of 2 to 1. The credit facility
was obtained in order to allow the Trust to operate using a minimum amount of
cash, maximize the amount invested in Projects and maximize cash distributions
to shareholders. The Trust borrowed $300,000 in 1998 and an additional $100,000
in 1999. The Trust repaid the outstanding borrowings in March 2000.
Obligations of the Trust are generally limited to payment of Project
operating expenses, payment of a management fee to the Managing Shareholder,
payments for certain accounting and legal services to third persons and
distributions to shareholders. Accordingly, the Trust has not found it necessary
to retain a material amount of working capital.
The Trust anticipates that during 2001 its cash flow from operations
will meet its 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, 2000
Expected Maturity Date
2003
(U.S. $)
Note receivable from NRG $ 1,283,000
Interest rate 8%
Expected Maturity Date
2001
(U.S. $)
Bank Deposits and Certificates of Deposit $ 90,000
Average interest rate 5.6%
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Balance Sheet at December 31, 2000 and 1999 F-3
Statement of Operations For the Three Years
Ended December 31, 2000 F-4
Statement of Changes in Shareholders' Equity For
the Three Years Ended December 31, 2000 F-5
Statement of Cash Flows For the Three Years
Ended December 31, 2000 F-6
Notes to Financial Statements F-7 to F-13
All schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
The financial statements are presented in accordance with generally
accepted accounting principles and Securities and Exchange Commission rules and
regulations applicable to business investment companies, which require the
Trust's investments in Projects to be presented on the cash method, rather than
on the equity method.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
Neither the Trust nor the Managing Shareholder has had an independent
accountant resign or decline to continue providing services since their
respective inceptions and neither has dismissed an independent accountant during
that period. During that period of time no new independent accountant has been
engaged by the Trust or the Managing Shareholder, and the Managing Shareholder's
current accountants, PricewaterhouseCoopers LLP, have been engaged by the Trust.
PART III
Item 10. Directors and Executive Officers of the Registrant.
(a) General.
As Managing Shareholder of the Trust, Ridgewood Power LLC has direct
and exclusive discretion in management and control of the affairs of the Trust
(subject to the general supervision and review of the Independent Trustees and
the Managing Shareholder acting together as the Board of the Trust). The
Managing Shareholder will be entitled to resign as Managing Shareholder of the
Trust only (i) with cause (which cause does not include the fact or
determination that continued service would be unprofitable to the Managing
Shareholder) or (ii) without cause with the consent of a majority in interest of
the Investors. It may be removed from its capacity as Managing Shareholder as
provided in the Declaration.
Ridgewood Holding, which was incorporated in April 1992, is the
Corporate Trustee of the Trust.
(b) Managing Shareholder.
Ridgewood Power Corporation was incorporated in February 1991 as a
Delaware corporation for the primary purpose of acting as a managing shareholder
of business trusts and as a managing general partner of limited partnerships
which are organized to participate in the development, construction and
ownership of Independent Power Projects. It organized the Trust and acted as
managing shareholder until April 1999. On or about April 21, 1999 it was merged
into the current Managing Shareholder, Ridgewood Power LLC. Ridgewood Power LLC
was organized in early April 1999 and has no business other than acting as the
successor to Ridgewood Power Corporation.
Robert E. Swanson has been the President, sole director and sole
stockholder of Ridgewood Power Corporation since its inception in February 1991
and is now the controlling member, sole manager and President of the Managing
Shareholder. All of the equity in the Managing Shareholder is or will be owned
by Mr. Swanson or by family trusts. Mr. Swanson has the power on behalf of those
trusts to vote or dispose of the membership equity interests owned by them.
The Managing Shareholder has also organized Power I, Power III, Power
IV, Power V, the Growth Fund and the Egypt Fund as Delaware business trusts to
participate in the independent power industry. Ridgewood Power LLC is now also
their managing shareholder. The business objectives of these six trusts are
similar to those of the Trust.
A number of other companies are affiliates of Mr. Swanson and the
Managing Shareholder. Each of these also was organized as a corporation that was
wholly-owned by Mr. Swanson. In April 1999, most of them were merged into
limited liability companies with similar names and Mr. Swanson became the sole
manager and controlling owner of each limited liability company. For
convenience, the remainder of this Memorandum will discuss each limited
liability company and its corporate predecessor as a single entity.
The Managing Shareholder is an affiliate of Ridgewood Energy
Corporation ("Ridgewood Energy"), which has organized and operated 48 limited
partnership funds and one business trust over the last 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 54, has also served as President of the Trust
since its inception in 1991 and as President of RPM, Power I, Power III, Power
IV, Power V and the Growth Fund, 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
and III venture capital 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 42, has served as Executive Vice President of the
Managing Shareholder, RPM, the Trust, Power I, Power III, Power IV, Power V, the
Growth Fund, and the Egypt Fund since their respective inceptions, with primary
responsibility for marketing and acquisitions. He has been President of
Ridgewood Capital since its organization in 1998. As such, he is President of
the Ridgewood Capital Venture Partners I, II and III funds. He has served as
Vice President and General Counsel of Ridgewood Securities Corporation since he
joined the firm in December 1987. Mr. Gold has also served as Executive Vice
President of Ridgewood Energy since October 1990. He served as Vice President of
Ridgewood Energy from December 1987 through September 1990. For the two years
prior to joining Ridgewood Energy and Ridgewood Securities Corporation, Mr. Gold
was a corporate attorney in the law firm of Cleary, Gottlieb, Steen & Hamilton
in New York City where his experience included mortgage finance, mergers and
acquisitions, public offerings, tender offers, and other business legal matters.
Mr. Gold is a member of the New York State bar. He is a graduate of Colgate
University and New York University School of Law.
Martin V. Quinn, age 53, has been the Executive Vice President and
Chief Operating Officer of Ridgewood Power since April 2000. Before that, he had
assumed the duties of Chief Financial Officer of Ridgewood Power in November
1996 under a consulting arrangement. In April 1997, he became a Senior Vice
President and Chief Financial Officer of Ridgewood Power and the Fund.
Mr. Quinn has over 30 years of experience in financial management and
corporate mergers and acquisitions, gained with major, publicly traded companies
and an international accounting firm. He formerly served as Vice President of
Finance and Chief Financial Officer of NORSTAR Energy, an energy services
company, from February 1994 until June 1996. From 1991 to March 1993, Mr. Quinn
was employed by Brown-Forman Corporation, a diversified consumer products
company and distiller, where he was Vice President-Corporate Development. From
1981 to 1991, Mr. Quinn held various officer-level positions with NERCO, Inc., a
mining and natural resource company, including Vice President- Controller and
Chief Accounting Officer for his last six years and Vice President-Corporate
Development. Mr. Quinn's professional qualifications include his certified
public accountant qualification in New York State, membership in the American
Institute of Certified Public Accountants, six years of experience with the
international accounting firm of PricewaterhouseCoopers, LLP, and a Bachelor of
Science degree in Accounting and Finance from the University of Scranton (1969).
Daniel V. Gulino, age 40, has been Senior Vice President and General
Counsel of the Managing Shareholder since August 2000. He began his legal career
as an associate for Pitney, Hardin, Kipp & Szuch, a large New Jersey law firm,
where his experience included corporate acquisitions and transactions. Prior to
joining Ridgewood, Mr. Gulino was in-house counsel for several large electric
utilities, including GPU, Inc., Constellation Power Source, and PPL Resources,
Inc., where he specialized in non-utility generation projects, independent power
and power marketing transactions. Mr. Gulino also has experience with the
electric and natural gas purchasing of industrial organizations, having worked
as in-house counsel for Alumax, Inc. (now part of Alcoa) where he was
responsible for, among other things, Alumax's electric and natural gas
purchasing program. Mr. Gulino is a member of the New Jersey State Bar and
Pennsylvania State Bar. He is a graduate of Fairleigh Dickinson University and
Rutgers University School of Law - Newark.
Christopher I. Naunton, 36, has been the Vice President and Chief
Financial Officer of the Managing Shareholder since April 2000. From February
1998 to April 2000, he was Vice President of Finance of an affiliate of the
Managing Shareholder. Prior to that time, he was a senior manager at the
predecessor accounting firm of PricewaterhouseCoopers LLP. Mr. Naunton's
professional qualifications include his certified public accountant
qualification in Pennsylvania, membership in the American Institute of Certified
Public Accountants and a Bachelor of Science degree in Business Administration
from Bucknell University (1986).
Mary Lou Olin, age 48, has served as Vice President of the Managing
Shareholder, RPM, Ridgewood Capital, the Trust, Power I, Power III, Power IV,
Power V, the Growth Fund, and the Egypt Fund since their respective inceptions.
She has also served as Vice President of Ridgewood Energy since October 1984,
when she joined the firm. Her primary areas of responsibility are investor
relations, communications and administration. Prior to her employment at
Ridgewood Energy, Ms. Olin was a Regional Administrator at McGraw-Hill Training
Systems where she was employed for two years. Prior to that, she was employed by
RCA Corporation. Ms. Olin has a Bachelor of Arts degree from Queens College.
(c) Management Agreement.
The Trust has entered into a Management Agreement with the Managing
Shareholder detailing how the Managing Shareholder will render management,
administrative and investment advisory services to the Trust. Specifically, the
Managing Shareholder will perform (or arrange for the performance of) the
management and administrative services required for the operation of the Trust.
Among other services, it will administer the accounts and handle relations with
the Investors, provide the Trust with office space, equipment and facilities and
other services necessary for its operation and conduct the Trust's relations
with custodians, depositories, accountants, attorneys, brokers and dealers,
corporate fiduciaries, insurers, banks and others, as required. The Managing
Shareholder will also be responsible for making investment and divestment
decisions, subject to the provisions of the Declaration.
The Managing Shareholder will be obligated to pay the compensation of
the personnel and all administrative and service expenses necessary to perform
the foregoing obligations. The Trust will pay all other expenses of the Trust,
including transaction expenses, valuation costs, expenses of preparing and
printing periodic reports for Investors and the Commission, postage for Trust
mailings, Commission fees, interest, taxes, legal, accounting and consulting
fees, litigation expenses and other expenses properly payable by the Trust. The
Trust will reimburse the Managing Shareholder for all such Trust expenses paid
by it.
As compensation for the Managing Shareholder's performance under the
Management Agreement, the Trust is obligated to pay the Managing Shareholder an
annual management fee described below at Item 13 -- Certain Relationships and
Related Transactions.
The Board of the Trust (including Independent Trustees) have approved
the initial Management Agreement and its renewals. 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 will remain in
effect year to year thereafter as long as it is approved at least annually by
(i) either the Board of the Trust or a majority in interest of the Investors and
(ii) a majority of the Independent Trustees. The agreement is subject to
termination at any time on 60 days' prior notice by the Board, a majority in
interest of the Investors or the Managing Shareholder. The agreement is subject
to amendment by the parties with the approval of (i) either the Board or a
majority in interest of the Investors and (ii) a majority of the Independent
Trustees.
(d) Executive Officers of the Trust.
Pursuant to the Declaration, the Managing Shareholder has appointed
officers of the Trust to act on behalf of the Trust and sign documents on behalf
of the Trust as authorized by the Managing Shareholder. Mr. Swanson has been
named the President of the Trust and the other executive officers of the Trust
are identical to those of the Managing Shareholder.
The officers have the duties and powers usually applicable to similar
officers of a Delaware business corporation in carrying out Trust business.
Officers act under the supervision and control of the Managing Shareholder,
which is entitled to remove any officer at any time. Unless otherwise specified
by the Managing Shareholder, the President of the Trust has full power to act on
behalf of the Trust. The Managing Shareholder expects that most actions taken in
the name of the Trust will be taken by Mr. Swanson and the other principal
officers in their capacities as officers of the Trust under the direction of the
Managing Shareholder rather than as officers of the Managing Shareholder.
(e) The Trustees.
The 1940 Act requires the Independent Trustees to be individuals who
are not "interested persons" of the Trust as defined under the 1940 Act
(generally, persons who are not affiliated with the Trust or with affiliates of
the Trust). There must always be at least two Independent Trustees; a larger
number may be specified by the Board from time to time. Each Independent Trustee
has an indefinite term. Vacancies in the authorized number of Independent
Trustees will be filled by vote of the remaining Board members so long as there
is at least one Independent Trustee; otherwise, the Managing Shareholder must
call a special meeting of Investors to elect Independent Trustees. Vacancies
must be filled within 90 days. An Independent Trustee may resign effective on
the designation of a successor and may be removed for cause by at least
two-thirds of the remaining Board members or with or without cause by action of
the holders of at least two-thirds of Shares held by Investors. Under the
Declaration, the Independent Trustees are authorized to act only where their
consent is required under the 1940 Act and to exercise a general power to review
and oversee the Managing Shareholder's other actions. They are under a fiduciary
duty similar to that of corporate directors to act in the Trust's best interest
and are entitled to compel action by the Managing Shareholder to carry out that
duty, if necessary, but ordinarily they have no duty to manage or direct the
management of the Trust outside their enumerated responsibilities.
The Independent Trustees of the Trust are Ralph O. Hellmold, Jonathan
C. Kaledin and Joseph Ferrante, Jr. Set forth below is certain information
concerning the Independent Trustees, who also serve as independent trustees of
Ridgewood Power III and as independent panel members of Ridgewood Power V. Both
are independent power programs sponsored by Ridgewood Power. Independent panel
members must approve transactions between their program and the Managing
Shareholder or companies affiliated with the Managing Shareholder, but have no
other responsibilities. Neither Mr. Hellmold nor Mr. Kaledin nor Mr. Ferrante is
otherwise affiliated with the Trust, any of the Trust's officers or agents, the
Managing Shareholder, any other Trustee, any affiliates of the Managing
Shareholder and any other Trustees, or any director, officer or agent of any of
the foregoing.
Ralph O. Hellmold, age 60, is Chairman of The Private Investment
Banking Company ("PIBC") and President of Hellmold Associates, Inc., both of
which are financial advisory firms that assist companies raise capital, divest
or acquire businesses or restructure corporate organizations. Other financial
advisory services provided by PIBC and Hellmold Associates, Inc. include mergers
and acquisitions advice, valuations, fairness opinions and expert witness
testimony. In addition to working with troubled companies or their creditors,
Hellmold Associates, Inc. also acts as general partner of funds that invest in
the securities of financially distressed companies.
From 1987 to 1990, when he formed Hellmold Associates, Inc., Mr.
Hellmold was a Managing Director at Prudential-Bache Capital Funding, where he
served as co-head of the Corporate Finance Group, co-head of the Investment
Banking Committee and head of the Financial Restructuring Group. From 1974 to
1987, Mr. Hellmold was a partner at Lehman Brothers and its successors, where he
worked in the General Corporate Finance Group and co-founded the Financial
Restructuring Group. Prior thereto, he was a research analyst at Lehman Brothers
and at Francis I. du Pont & Company. He received his undergraduate degree magna
cum laude from Harvard College and an M.I.A. from Columbia University. He is a
Chartered Financial Analyst and a member of the New York Society of Security
Analysts. Mr. Hellmold is the holder of one- half share in each of Power I and
Power II, a shareholder of one-half Share in the Trust and a limited partner or
shareholder in numerous limited partnerships and a business trust sponsored by
Ridgewood Energy to invest in oil and gas development and related businesses.
Mr. Hellmold is a director of Core Materials Corporation, Columbus, Ohio and of
International Aircraft Investors, Torrance, California.
Jonathan C. Kaledin, age 43, has been New York Regional Counsel of The
Nature Conservancy, the international land conservation organization, since
September 1995. From 1990 to June 1995, he was the Executive Director of the
National Water Funding Council ("NWFC"), an advocacy and public affairs
organization representing municipalities, businesses, financial institutions and
others on the financial aspects of clean water infrastructure projects required
by the federal Clean Water Act and the federal Safe Drinking Water Act.. Prior
to running the NWFC, Mr. Kaledin practiced law in both the private and public
sectors, specializing in environmental and real estate matters. Mr. Kaledin
received his undergraduate degree magna cum laude from Harvard College and a law
degree from New York University.
The Independent Trustees and the Managing Shareholder expanded the
number of Independent Trustees to three in January 2000 and elected Joseph
Ferrante, Jr. as the additional Independent Trustee. Mr. Ferrante, age 56, has
been a lawyer in private practice in Ridgewood, New Jersey for more than five
years specializing in business and taxation matters. He received a Juris Doctor
degree in law from the George Washington University and his undergraduate degree
from the Johns Hopkins University. He advises a large number of start-up and
entrepreneurial companies.
The Corporate Trustee of the Trust is Ridgewood Holding. Legal title to
Trust Property is now and in the future will be in the name of the Trust, if
possible, or Ridgewood Holding as trustee. Ridgewood Holding is also a trustee
of Power I, Power III, Power IV, Power V, the Growth Fund, the Egypt Fund, and
of an oil and gas business trust sponsored by Ridgewood Energy and is expected
to be a trustee of other similar entities that may be organized by the Managing
Shareholder and Ridgewood Energy. The President, sole director and sole
stockholder of Ridgewood Holding is Robert E. Swanson; its other executive
officers are identical to those of the Managing Shareholder. See -- Managing
Shareholder. The principal office of Ridgewood Holding is at 1105 North Market
Street, Suite 1300, Wilmington, Delaware 19899.
The Trustees are not liable to persons other than Shareholders for the
obligations of the Trust.
The Trust has relied and will continue to rely on the Managing
Shareholder and engineering, legal, investment banking and other professional
consultants (as needed) and to monitor and report to the Trust concerning the
operations of Projects in which it invests, to review proposals for additional
development or financing, and to represent the Trust's interests. The Trust will
rely on such persons to review proposals to sell its interests in Projects in
the future.
(f) Section 16(a) Beneficial Ownership Reporting Compliance
To the knowledge of the Trust, there were no violations of the
reporting requirements of section 16(a) of the 1934 Act by officers and
directors of the Trust in the last fiscal year.
(g) RPM.
As discussed above at Item 1 - Business, RPM has assumed day-to-day
management responsibility for the Monterey Project, effective January 1, 1996
and operating responsibility for the California 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.
Initially, the Managing Shareholder does not anticipate charging RPM
for the full amount of rent, utility supplies and office expenses allocable to
RPM. As a result, both initially and on an ongoing basis the Managing
Shareholder believes that RPM's charges for its services to the Trust are likely
to be materially less than its economic costs and the costs of engaging
comparable third persons as managers. RPM will not receive any compensation in
excess of its costs.
Allocations of costs will be made either on the basis of identifiable
direct costs, time records or in proportion to each program's investments in
Projects managed by RPM; and allocations will be made in a manner consistent
with generally accepted accounting principles.
RPM will not provide any services related to the administration of the
Trust, such as investment, accounting, tax, investor communication or regulatory
services, nor will it participate in identifying, acquiring or disposing of
Projects. RPM will not have the power to act in the Trust's name or to bind the
Trust, which will be exercised by the Managing Shareholder or the Trust's
officers, although it may be authorized to act on behalf of the subsidiaries
that own Projects.
The Operation Agreement does not have a fixed term and is terminable by
RPM, by the Managing Shareholder or by vote of a majority of interest of
Investors, on 60 days' prior notice. The Operation Agreement may be amended by
agreement of the Managing Shareholder and RPM; however, no amendment that
materially increases the obligations of the Trust or that materially decreases
the obligations of RPM shall become effective until at least 45 days after
notice of the amendment, together with the text thereof, has been given to all
Investors.
The executive officers of RPM are Mr. Swanson (President), Mr. Gold
(Executive Vice President), Mr. Quinn (Executive Vice President and Chief
Operating Officer), Mr. Gulino (Senior Vice President and General Counsel), Mr.
Naunton (Vice President and Chief Financial Officer) and Ms. Olin (Vice
President).
Item 11. Executive Compensation.
Through 1995, the executive officers of the Trust and the Managing
Shareholder were compensated by Ridgewood Energy. The Trust was not charged for
their compensation; the Managing Shareholder remitted a portion of the fees paid
to it by the Trust to reimburse Ridgewood Energy for employment costs incurred
on the Managing Shareholder's business. Beginning in 1996, the Managing
Shareholder compensates these persons without additional payments by the Trust
and will be reimbursed by Ridgewood Energy for costs related to Ridgewood
Energy's business. The Trust reimburses RPM at allocable cost for services
provided by RPM's employees; no such reimbursement per employee exceeded $60,000
in 2000 or 1999. Information as to the fees payable to the Managing Shareholder
and certain affiliates is contained at Item 13 -- Certain Relationships and
Related Transactions.
As compensation for services rendered to the Trust, pursuant to the
Declaration, each Independent Trustee is entitled to be paid by the Trust the
sum of $5,000 annually and to be reimbursed for all reasonable out-of-pocket
expenses relating to attendance at Board meetings or otherwise performing his
duties to the Trust. The Board of the Trust is entitled to review the
compensation payable to the Independent Trustees annually and increase or
decrease it as the Board sees reasonable. The Trust is not entitled to pay the
Independent Trustees compensation for consulting services rendered to the Trust
outside the scope of their duties to the Trust without prior Board approval.
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 in the offering 1.45
Investor Shares (.6 of 1% of the outstanding Investor Shares). Ralph O.
Hellmold, an Independent Trustee of the Trust, purchased for cash in the
offering one-half of a full Investor Share. By virtue of their purchases of
Investor Shares, the Managing Shareholder and Mr. Hellmold are entitled to the
same ratable interest in the Trust as all other purchasers of Investor Shares.
No other Trustees or executive officers of the Trust acquired Investor Shares in
the Trust's offering.
The Managing Shareholder was issued one Management Share in the Trust
representing the beneficial interests and management rights of the Managing
Shareholder in its capacity as 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 2000 and 1999, 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:
2000 1999 1998 1997 1996
Managing
Shareholder $ -0- 55,607 381,594 401,085 328,952
RPM Cost
Reimbursements $ 3,032,954 2,841,952 1,470,207 1,610,806 1,207,252
The investment fee equaled 2% of the proceeds of the offering of Investor
Shares and was payable for the Managing Shareholder's services in investigating
and evaluating investment opportunities and effecting investment transactions.
The placement agent fee (1% of the offering proceeds) and sales commissions were
also paid from proceeds of the offering, as was the organizational, distribution
and offering fee (5% of offering proceeds) for legal, accounting, consulting,
filing, printing, distribution, selling, closing and organization costs of the
offering.
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 California Pumping Projects. In
1996 and 1997, these reimbursements were paid to RPM. The reimbursements to RPM,
which do not exceed its actual costs and allocable overhead, are described at
Item 10(g) - Directors and Executive Officers of the Registrant -- RPM.
Other information in response to this item is reported in response to
Item 11 -- Executive Compensation, which information is incorporated by
reference into this Item 13.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Financial Statements.
See the Index to 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, 2000.
(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.
21. Subsidiaries of the Registrant. Page 66
24. Powers of Attorney Page 67
27. Financial Data Schedule Page 69
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.
Signature Title Date
RIDGEWOOD ELECTRIC POWER TRUST II (Registrant)
By: /s/Robert E. Swanson President and Chief March 30, 2001
Robert E. Swanson Executive Officer
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 and Chief March 30, 2001
Robert E. Swanson Executive Officer
By: /s/Christopher I. Naunton Vice President and March 30, 2001
Christopher I. Naunton Chief Financial Officer
RIDGEWOOD POWER LLC Managing Shareholder March 30, 2001
By: /s/Robert E. Swanson President
Robert E. Swanson
/s/Robert E. Swanson * Independent Trustee March 30, 2001
Ralph O. Hellmold
/s/Robert E. Swanson * Independent Trustee March 30, 2001
Jonathan C. Kaledin
/s/Robert E. Swanson * Independent Trustee March 30, 2001
Joseph Ferrante, Jr.
* Robert E. Swanson, as attorney-in-fact for the Independent Trustee
Ridgewood Electric Power Trust II
Financial Statements
December 31, 2000, 1999 and 1998
Report of Independent Accountants
To the Shareholders and Trustees of
Ridgewood Electric Power Trust II:
In our opinion, the accompanying balance sheets and the statements of
operations, changes in shareholders' equity and of cash flows present fairly, in
all material respects, the financial position of Ridgewood Electric Power Trust
II (the "Trust") at December 31, 2000 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States of America. These financial statements are the
responsibility of the Trust's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
As explained in Note 2, the financial statements include investments valued at
$10,751,582 and $10,274,790 (91% and 86% of shareholders' equity, respectively)
as of December 31, 2000 and 1999, respectively, whose values have been estimated
by management in the absence of readily ascertainable market values. We have
reviewed the procedures used by management in arriving at their estimate of
value and have inspected underlying documentation, and, in the circumstances, we
believe the procedures are reasonable and the documentation appropriate.
However, because of the inherent uncertainty of valuation, those estimated
values may differ significantly from the values that would have been used had a
ready market for those investments existed, and the differences could be
material to the financial statements.
PricewaterhouseCoopers LLP
New York, NY
March 23, 2001
Ridgewood Electric Power Trust II
Balance Sheet
- --------------------------------------------------------------------------------
December 31,
----------------------------
2000 1999
------------ ------------
Assets:
Investments in power generation projects ... $ 10,751,582 $ 10,274,790
Cash and cash equivalents .................. 89,829 537,541
Notes receivable from sale of investment ... 1,283,327 1,729,181
Due from affiliates ........................ 6,174 --
Other assets ............................... 4,398 3,306
------------ ------------
Total assets ............................. $ 12,135,310 $ 12,544,818
------------ ------------
Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses ...... $ 41,972 $ 49,923
Borrowings under line of credit facility ... -- 400,000
Due to affiliates .......................... 270,765 153,191
------------ ------------
Total liabilities ........................ 312,737 603,114
------------ ------------
Commitments and contingencies
Shareholders' equity:
Shareholders' equity (235.3775
shares issued and outstanding)
11,905,591 12,023,530
Managing shareholder's accumulated deficit . (83,018) (81,826)
------------ ------------
Total shareholders' equity ............... 11,822,573 11,941,704
------------ ------------
Total liabilities and shareholders' equity $ 12,135,310 $ 12,544,818
------------ ------------
See accompanying notes to financial statements.
Ridgewood Electric Power Trust II
Statement of Operations
- --------------------------------------------------------------------------------
Year Ended December 31,
---------------------------------------
2000 1999 1998
----------- ----------- -----------
Revenue:
Income from power generation projects $ 556,079 $ 131,859 $ 953,576
Other income ........................ 22,416 -- --
Interest income ..................... 134,135 162,686 196,480
----------- ----------- -----------
Total revenue ...................... 712,630 294,545 1,150,056
----------- ----------- -----------
Expenses:
Writedown of investment in Pittsfield
Investors Limited Partnership ...... -- -- 2,347,330
Management fee ...................... -- 55,607 381,594
Accounting and legal fees ........... 66,342 52,721 75,111
Interest ............................ 9,063 27,378 7,081
Miscellaneous ....................... 42,290 64,231 43,751
----------- ----------- -----------
Total expenses ..................... 117,695 199,937 2,854,867
----------- ----------- -----------
Net income (loss) .................. $ 594,935 $ 94,608 $(1,704,811)
----------- ----------- -----------
See accompanying notes to financial statements.
Ridgewood Electric Power Trust II
Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 2000, 1999 and 1998
- --------------------------------------------------------------------------------
Managing
Shareholders Shareholder Total
------------- ------------ ------------
Shareholders' equity,
January 1, 1998 .... $ 15,312,360 $ (48,606) $ 15,263,754
Cash distributions .. (1,412,273) (14,265) (1,426,538)
Net income .......... (1,687,763) (17,048) (1,704,811)
------------ ------------ ------------
Shareholders' equity,
December 31, 1998 .. 12,212,324 (79,919) 12,132,405
Cash distributions .. (282,456) (2,853) (285,309)
Net loss ............ 93,662 946 94,608
------------ ------------ ------------
Shareholders' equity,
December 31, 1999 .. 12,023,530 (81,826) 11,941,704
Cash distributions .. (706,925) (7,141) (714,066)
Net income .......... 588,986 5,949 594,935
------------ ------------ ------------
Shareholders' equity,
December 31, 2000 .. $ 11,905,591 $ (83,018) $ 11,822,573
------------ ------------ ------------
See accompanying notes to financial statements.
Ridgewood Electric Power Trust II
Statement of Cash Flows
- --------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
Cash flows from operating
activities:
Net income (loss) ................ $ 594,935 $ 94,608 $(1,704,811)
----------- ----------- -----------
Adjustments to reconcile
net income (loss) to cash
flows from operating
activities
Writedown of investment in
Pittsfield Investors Limited
Partnership ..................... -- -- 2,347,330
Proceeds from note receivable .... 445,854 411,685 380,135
Investments in power
generation projects ............. (476,792) -- (208,553)
Return of investments in
power generation projects ....... -- 319,612 --
Changes in assets and liabilities:
(Increase) decrease in other
assets ......................... (1,092) 282 (1,152)
(Increase) decrease in due
from affiliates ................ (6,174) 8,819 (8,819)
(Decrease) increase in accounts
payable and accrued expenses ... (7,951) (50,974) 68,711
Increase (decrease) in due
to affiliates .................. 117,574 (61,182) 77,879
----------- ----------- -----------
Total adjustments ................ 71,419 628,242 2,655,531
----------- ----------- -----------
Net cash provided by
operating activities ............ 666,354 722,850 950,720
----------- ----------- -----------
Cash flows from financing
activities:
Borrowings under line of
credit facility ................. -- 550,000 300,000
Repayments under line of
credit facility ................. (400,000) (450,000) --
Cash distributions to
shareholders .................... (714,066) (285,309) (1,426,538)
----------- ----------- -----------
Net cash used in
financing activities ............ (1,114,066) (185,309) (1,126,538)
----------- ----------- -----------
Net (decrease) increase
in cash and cash equivalents .... (447,712) 537,541 (175,818)
Cash and cash equivalents,
beginning of year ............... 537,541 -- 175,818
----------- ----------- -----------
Cash and cash equivalents,
end of year ..................... $ 89,829 $ 537,541 $ --
----------- ----------- -----------
See accompanying notes to financial statements.
Ridgewood Electric Power Trust II
Notes to 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.
"Business Development Company" election
Effective April 29, 1993, the Trust elected to be treated as a "Business
Development Company" under the Investment Company Act of 1940 and
registered its shares under the Securities Exchange Act of 1934.
2. Summary of Significant Accounting Policies
Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from the
estimates.
Investments in power generation projects
The Trust holds investments in power generation projects which are stated
at fair value. Due to the illiquid nature of the investments, the fair
values of the investments are assumed to equal cost, unless current
available information provides a basis for adjusting the carrying value of
the investments.
Revenue recognition
Income from investments is recorded when distributions are declared.
Interest income is recorded as earned.
Cash and cash equivalents
The Trust considers all highly liquid investments with maturities when
purchased of three months or less as cash and cash equivalents.
Income taxes
No provision is made for income taxes in the accompanying 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 Trusts.
3. Investments in Power Generation Projects
The Trust had the following investments in power generation and other
projects:
December 31,
-------------------------
2000 1999
----------- -----------
B-3 Limited Partnership ............. $ 4,001,843 $ 4,001,843
Sunnyside Cogeneration Partners, L.P. 5,500,597 5,170,812
California Pumping Project .......... 1,249,142 1,102,135
----------- -----------
$10,751,582 $10,274,790
----------- -----------
The Trust's distribution income from the projects was as follows:
For the Year Ended December 31,
------------------------------
2000 1999 1998
-------- -------- --------
Pittsfield Investors Limited Partnership $ -- $ -- $175,725
B-3 Limited Partnership ................ 300,014 100,000 250,000
Sunnyside Cogeneration Partners, L.P. .. 247,303 -- 515,403
California Pumping Project ............. 8,762 31,859 12,448
-------- -------- --------
$556,079 $131,859 $953,576
-------- -------- --------
Pittsfield Investors Limited Partnership (known as the Berkshire project)
On January 4, 1994, the Trust made a limited partnership investment in this
partnership, which was formed to acquire an operating facility, located in
Pittsfield, Massachusetts. The facility, which has been operating since
1981, burns municipal solid waste supplied by the City of Pittsfield and
surrounding communities. The facility has a long-term supply agreement with
the City of Pittsfield, which expires in November 2004, under which the
City makes payments to the facility for receiving the waste. The facility
generates additional revenue by selling steam produced from the waste
burning process to a nearby paper mill under a long-term contract, which
also expires in November 2004.
In exchange for its investment, the Trust is entitled to receive annually a
preferred distribution from available cash from the facility equal to 15%
of its investment. In the event that in any given year available net cash
flow from the project does not at least equal the amount of the preferred
minimum return, the amount of such shortfall is payable on a priority basis
out of any available net cash flow in subsequent years. The Trust may also
be entitled to receive additional distributions from any net cash flow in
excess of the 15% return on its investment. The aggregate cost of the
Trust's investment in the partnership was $2,347,330. The Trust received
distributions of $175,725 from the project for the year ended December 31,
1998.
In 1998, the City of Pittsfield closed the nearby landfill to which the
project had sent the ash residue from the burning of the municipal solid
waste. The additional cost of transporting the ash to other landfills has
significantly reduced the cash flows generated by the project. Although the
project manager is actively seeking ways to enhance the project's revenue,
the ability of the project to make distributions to the Trust in the future
is questionable. Accordingly, in 1998 the Trust recorded a writedown of
$2,347,330 to reduce the estimated fair value of the project to zero.
B-3 Limited Partnership (known as the Columbia project)
On August 31, 1994, the Trust made a limited partnership investment in this
partnership, which was formed to construct and operate a municipal waste
transfer station, located in Columbia County, New York. The project
commenced operations in January 1995.
In exchange for its investment, the Trust is entitled to receive annually a
preferred distribution of available net cash flow from the facility equal
to 18% of its investment. In the event that in any given year available net
cash flow from the project does not at least equal the amount of the
preferred minimum return, the amount of such shortfall is payable on a
priority basis out of any available net cash flow in subsequent years. The
Trust may also be entitled to receive additional distributions from any net
cash flow in excess of the 18% return on its investment. The aggregate cost
of the Trust's investment in the partnership was $4,001,843. The Trust
received distributions of $300,014, $100,000 and $250,000 from the project
for the years ended December 31, 2000, 1999, and 1998, respectively.
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. Electricity is sold to the Pacific Gas and Electric Company
("PG&E") under a long term contract expiring in 2020. The aggregate cost of
the Trust's investment at December 31, 2000 and 1999 was $5,500,597 and
$5,170,812, respectively. The Trust received distributions of $247,303 and
$515,403 from the project for the years ended December 31, 2000 and 1998,
respectively.
On April 1, 1999, PG&E sued the Trust's subsidiary that owns the Monterey
project in the Superior Court of California for the City and County of San
Francisco. PG&E alleged that the Project did not meet federal and state
efficiency requirements and that accordingly the Project was not entitled
to the benefit of discounted natural gas fuel rates allowable to qualifying
cogeneration facilities. The lawsuit claimed an unspecified amount of
damages. The State lawsuit was dismissed without prejudice and by agreement
of the parties and the matter was brought by PG&E to the Federal Energy
Regulatory Commission ("FERC") by petition for a determination. PG&E filed
with FERC a petition seeking a revocation of the Monterey project's
Qualifying Facility status and a refund of certain overpayments PG&E claims
it made to the Project, which were not justified due to the Project's
failure to maintain Qualifying Facility status. The FERC proceeding
generally involves a determination of the proper location for metering and
computing efficiency standards. The Trust believes that its location of the
meter is correct for determining such standards and that it will succeed at
FERC and retain its Qualifying Facility status and that no refunds will be
required. All of the required or permitted filings have been prepared and
submitted to the FERC and the parties are awaiting a decision. No other
activity on this matter is anticipated until such FERC decision.
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 $175,000 and to
cooperate with the Project in the potential FERC proceedings involving the
Monterey project and the Trust agreed to cooperate with Waukesha-Pierce in
releasing funds due from PG&E to Waukesha-Pierce. The settlement has not
yet been completed as the funds due from PG&E to Waukesha-Pierce have not
yet been released by PG&E.
California Pumping Project
On March 31, 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. Prior
to September 30, 1998, the project was operated by a third party manager
and the Trust received a distribution of $0.02 per equivalent kilowatt up
to 3,000 running hours per year and $0.01 per equivalent kilowatt for each
additional running hour per year. On October 1, 1998, the Trust terminated
the operating agreement with the third party manager and Ridgewood Power
Management LLC ("Ridgewood Management", formerly Ridgewood Power Management
Corporation), an affiliate of the managing shareholder, began operating the
project. The project paid $105,840 to the third party manager to terminate
the operating agreement. The total investment in the project at December
31, 2000 and 1999 was $1,249,142 and $1,102,135, respectively, and the
project has an equivalent of 3 megawatts of power. The operator pays for
fuel, maintenance, repair and replacement. The Trust received distributions
of $8,762, $31,859 and $12,448 from the project for the years ended
December 31, 2000, 1999 and 1998, respectively.
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. of Minneapolis, Minnesota. As
part of the consideration, the Trust received an 8% promissory note in the
amount of $2,700,000 payable monthly over six years.
5. Line of Credit Facility
During the fourth quarter of 1997, the Trust and its principal bank
executed a revolving line of credit agreement, whereby the bank will
provide a three year committed line of credit facility of $750,000. In
December 2000, the credit facility was extended until March 5, 2001. At
December 31, 1999, borrowings under this credit facility equaled $400,000.
The balance outstanding at December 31, 1999 was repaid on March 6, 2000.
Outstanding borrowings bear interest at LIBOR plus 2.5% (9.07% and 7.81% at
December 31, 2000 and 1999, respectively). The amount outstanding under the
line of credit facility must be reduced to zero for a thirty day period
each year. The credit agreement will require the Trust to maintain a ratio
of total debt to tangible net worth of no more than 1 to 1 and a minimum
debt service coverage ratio of 2 to 1.
6. Transactions with Managing Shareholder and Affiliates
The Trust entered into a management agreement with the managing
shareholder, under which the managing shareholder renders certain
management, administrative and advisory services and provides office space
and other facilities to the Trust. As compensation to the managing
shareholder, the Trust paid to the managing shareholder an annual
management fee equal to 2.5% of the net asset value of the Trust payable
monthly upon the closing of the Trust. Under the terms of the management
agreement, the annual management fee decreased to 1.5% of the net asset
value of the Trust effective February 1, 1999. For the years ended December
31, 1999 and 1998, the Trust paid management fees to the managing
shareholder of $55,607 and $381,594, respectively. Beginning in April 1999,
the managing shareholder waived the management fee to which it is 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, 2000.
The managing shareholder owns 1.45 shares of the Trust with a cost of
$121,800.
In 1996, under an Operating Agreement with the Trust, Ridgewood Management
provides management, purchasing, engineering, planning and administrative
services to the power generation project operated by the Trust. Ridgewood
Management charges the project at its cost for these services and for the
allocable amount of certain overhead items. Allocations of costs are on the
basis of identifiable direct costs, time records or in proportion to amount
invested in projects managed by Ridgewood Management. During the year ended
December 31, 2000, 1999 and 1998, Ridgewood Management charged Sunnyside
Cogeneration Partners $109,148, $150,711 and $119,823, respectively, for
overhead items allocated in proportion to the amount invested in projects
managed. During the years ended December 31, 2000 and 1999 and the three
month period ended December 31, 1998, Ridgewood Management charged the
California Pumping Project $70,118, $75,818 and $25,973, 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.
7. Subsequent Event - Pacific Gas and Electric Company Financial Crisis
All energy generated by the Monterey project is sold to PG&E under a power
contract. Currently, and as a result of the deregulation of the California
energy market, PG&E has allegedly suffered billions of dollars in losses
during the later part of 2000 and to date in 2001. Due to the California
energy crisis, PG&E has been unable to pay in full for electrical energy
and capacity delivered 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, the gas supplier requested
assurance of payment before it would agree to provide natural gas during
February. Due to PG&E's financial crisis and its inability to pay, the
Monterey project was unable on its own to provide an acceptable assurance
or to pay the arrears and, as a result, the supplier refused to provide
natural gas beyond February 6, 2001.
On February 1, 2000, PG&E made a partial payment equal to approximately 15%
of the amount due for December 2000. On March 5, 2001, PG&E made another
partial payment equal to approximately 15% of the amount due January 2001.
Those amounts are insufficient, after payroll costs are met, to cover the
amount owed to the natural gas supplier. PG&E effectively acknowledges that
it owes the project for December and January by virtue of announcing and
making a 15% partial payments. On February 6, 2001, the Trust shut down the
Monterey project because the supplier of natural gas terminated deliveries
of natural gas as of that date. The shut down will be for an indefinite
time.
In addition to its failure to pay the full amount due for December 2000 and
January 2001 deliveries, PG&E has indicated in letters to the Monterey
project, as well as documents filed with the Securities and Exchange
Commission, that it is unable or unwilling to make future payments to
Qualifying Facilities, such as the project. The Trust believes that PG&E's
ability to pay for the electrical energy and capacity it received or will
receive in the future, depends upon, among other things, positive action by
the California governor and legislature to fund approximately $12 billion
of losses allegedly suffered by California utilities during the last eight
months. The Trust expects that any such political solution may be
accompanied by executive, legislative or regulatory attempts to reduce
unilaterally the amounts owed by PG&E to Qualifying Facilities. In an
effort to resolve the California crisis, there have been numerous proposals
by the California Public Utilities Commission ("CPUC"), as well as the
legislature, to adjust downward the prices paid by California utilities to
Qualifying Facilities. The Trust expects that any regulatory proceeding to
set an energy price applicable to Qualifying Facilities will be extremely
protracted and that a legislative solution, if one were to be enacted and
approved by the governor, is likely to be arbitrary and significantly below
the avoided cost of the energy to PG&E.
PG&E has attempted to justify its non-payment by invoking the "force
majeure" provisions of the power contract. In essence, PG&E argues that it
is excused from its payment obligations because its failure to pay is the
result of the CPUC actions in failing to increase its rates to retail
customers and is beyond its control. The Trust disagrees and believes that
PG&E has breached the contract. The Monterey project, along with the Byron
and San Joaquin projects owned by Ridgewood Electric Power Trust III
("Trust III"), filed a lawsuit on February 6, 2001 against PG&E to that
effect and are seeking damages equal to lost net revenues for the remaining
term of the power contract. By this lawsuit the Trust seeks to have the
power contract with PG&E declared null and void so that the Monterey
project will be able to sell its electric power on the open market to third
party purchasers who will be able to pay currently for such electric power.
The Trust expects that it will be able purchase natural gas if it is free
from the PG&E contract and able to sell to credit worthy purchasers. The
Trust is seeking an accelerated determination by the California court. The
Trust is hopeful that an accelerated determination by the court is a
possibility considering the power emergency in California, which may get
worse as warm weather approaches and power demand increases. Also, in an
attempt to get the project back on-line quickly, on March 8, 2001, the
managing shareholder, on behalf of the Trust and Trust III, filed with FERC
a "Request For Emergency Relief and Extension of Waiver of Qualifying
Facility Regulations" in which the managing shareholder likewise seeks an
order from FERC permitting Qualifying Facilities to sell to third parties.
Until the Monterey project can restart profitably, it will remain shut
down, it will incur payroll and shutdown costs and it will not earn
revenue. For the reasons described above, the Trust cannot estimate when it
will restart the Monterey project or what its short-term and long-term
prospects may be. At this time, the Trust does not believe that a long-term
impairment of the Monterey Project's value has occurred.
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, Ralph O.
Hellmold, appoints Robert E. Swanson and Martin V. Quinn, and each of them, as
his true and lawful attorneys-in-fact with full power to act and do all things
necessary, advisable or appropriate, in their discretion, to execute on his
behalf as an Independent Trustee of Ridgewood Electric Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form 10-K for the year
ended December 31, 2000 for each of the above-named trusts, and all amendments
or documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 24th day of March, 2001, at Carlsbad, California.
/s/Ralph O. Hellmold
Ralph O. Hellmold
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, Jonathan C.
Kaledin, appoints Robert E. Swanson and Martin V. Quinn, and each of them, as
his true and lawful attorneys-in-fact with full power to act and do all things
necessary, advisable or appropriate, in their discretion, to execute on his
behalf as an Independent Trustee of Ridgewood Electric Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form 10-K for the year
ended December 31, 2000 for each of the above-named trusts, and all amendments
or documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 24th day of March, 2001, at Carlsbad, California
/s/Jonathan C. Kaledin
Jonathan C. Kaledin
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the undersigned, Joseph Ferrante,
Jr., appoints Robert E. Swanson and Martin V. Quinn, and each of them, as his
true and lawful attorneys-in-fact with full power to act and do all things
necessary, advisable or appropriate, in their discretion, to execute on his
behalf as an Independent Trustee of Ridgewood Electric Power Trust II and of
Ridgewood Electric Power Trust III, the Annual Reports on Form 10-K for the year
ended December 31, 2000 for each of the above-named trusts, and all amendments
or documents relating thereto.
IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 24th day of March, 2001, at Carlsbad, California
/s/ Joseph Ferrante, Jr.
Joseph Ferrante, Jr.