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, 1998
Commission file number 0-23432
RIDGEWOOD ELECTRIC POWER TRUST III
(Exact Name of Registrant as Specified in Its Charter)
Delaware 22-3264565
(State or Other Jurisdiction (I.R.S. Employer Identification No.)
of Incorporation or Organization)
c/o Ridgewood Power Corporation, 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
April 9, 1999 was $39,034,440.
Exhibit Index is located on page 52.
<PAGE>
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, year 2000 remediation 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 of fuel 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 III, the Registrant hereunder (the "Trust"),
was organized as a Delaware business trust on December 6, 1993 to participate in
the development, construction and operation of independent power generating
facilities ("Independent Power Projects" or "Projects"). Ridgewood Energy
Holding Corporation ("Ridgewood Holding"), a Delaware corporation, is the
Corporate Trustee of the Trust.
The Trust sold whole and fractional shares of beneficial interest in the
Trust ("Investor Shares") at $100,000 per Investor Share, and terminated its
private placement offering on May 31, 1995, at which time it had raised
approximately $39.2 million. Net of Offering fees, commissions and expenses, the
Offering provided approximately $32.9 million of net funds available for
investments in the development and acquisition of Independent Power Projects and
associated expenses. The Trust has 943 record holders of Investor Shares (the
"Investors"). As described below in Item 1(c)(2), the Trust has invested
substantially all of its net funds in seven sets of Independent Power Projects.
The Trust is organized similarly to a limited partnership.
Ridgewood Power Corporation (the "Managing Shareholder"), a Delaware
corporation, is the Managing Shareholder of the Trust.
In general, the Managing Shareholder has the powers of a general partner of
a limited partnership. It has complete control of the day to day operation of
the Trust 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.
The Corporate Trustee acts on the instructions of the Managing Shareholder
and is not authorized to take independent discretionary action on behalf of the
Trust. See Item 10. Directors and Executive Officers of the Registrant below for
a further description of the management of the Trust.
The Trust made an election to be treated as a "business development
company" under the Investment Company Act of 1940, as amended ( the "1940 Act").
On February 14, 1994, the Trust notified the Securities and Exchange Commission
of such election and registered the Investor Shares under the Securities
Exchange Act of 1934, as amended (the "1934 Act"). On April 16, 1994, the
election and registration became effective.
(b) Financial Information about Industry Segments.
The Trust operates in only one industry segment: investing
in independent power generation.
(c) Narrative Description of Business.
(1) General Description.
The Trust was formed to participate in the development, construction and
operation of independent electric power projects that generate electricity for
sale to utilities and other users, and in some cases, to provide heat energy or
chilled water as well to users. The Trust also may invest in facilities related
to those projects.
Historically, producers of electric power in the United States consisted of
regulated utilities and of industrial users that produced electricity to satisfy
their own needs. The independent power industry in the United States was created
by federal legislation passed in response to the energy crises of the 1970s. The
Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), requires
utilities to purchase electric power from "Qualifying Facilities" (as defined in
PURPA), including "cogeneration facilities" and "small power producers," and
also exempts these Qualifying Facilities from most utility regulatory
requirements. Under PURPA, Projects that are Qualifying Facilities are generally
not subject to federal regulation, including the Public Utility Holding Company
Act of 1935, as amended, and state regulation. Furthermore, PURPA generally
requires electric utilities to purchase electricity produced by Qualifying
Facilities at 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). Utilities in past years
have done so under long-term power purchase contracts ("Power Contracts") which
typically are the crucial determinant of the Qualifying Facility's success.
The Trust has invested its funds in seven Projects or groups of Projects:
(i) a 5.7 megawatt cogeneration facility located in Byron, California (the
"Byron Project");
(ii) an 8.5 megawatt cogeneration facility located in Atwater, California
(the "San Joaquin Project");
(iii) a portfolio of what were 35 cogeneration facilities located in
California, New York, Massachusetts, Connecticut and Rhode Island, purchased
from Eastern Utilities Associates, Inc. (the "On-site
Cogeneration Projects");
(iv) an additional cogeneration project located at an airline food
preparation facility in Los Angeles, California (the "El Segundo Project");
(v) Ridgewood/AES Power Partners, L.P., a joint venture that operates 10
small cogeneration projects in New York and New Jersey;
(vi) a 13.8 megawatt
electric generation plant fueled by gas drawn from a sanitary landfill near
Providence, Rhode Island (the "Providence Project") and
(vii) a portfolio of seven power modules (each having a diesel engine and
electric generator mounted on a skid with necessary control and transformer
equipment) which are being marketed and operated by Hawthorne Power Systems,
Inc., Los Angeles, California (the "Hawthorne Equipment Project").
As discussed below, the Trust is a "business development company" under the
1940 Act. In accounting for its Projects, it 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 cash distributions are included, as revenue, when received.
Therefore, the recognition of revenue from Projects by the Trust is dependent
upon the timing of distributions from Projects by the Managing Shareholder. As
discussed below 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) San Joaquin Project.
On January 17, 1995, Ridgewood Electric Power Trust III (the "Trust") and
RW Central Valley, Inc., a newly formed California corporation which is wholly
owned by the Trust ("Central Valley"), acquired 100% of the existing partnership
interests of JRW Associates, L.P. ("JRW"), a California limited partnership
which owns and operates an approximately 8.53 megawatt electric cogeneration
facility located in the City of Atwater, Merced County, California. The
partnership interests were purchased from JRW Cogen, Inc. and NorCal Cogen,
Inc., two corporations which were affiliates of a privately held company. At the
closing, the JRW partnership agreement was amended and restated so that Central
Valley became the sole general partner of JRW with a 1% general partnership
interest and the Trust became the sole limited partner of JRW with a 99% limited
partnership interest. Central Valley and the Trust plan to cause JRW to continue
the operations of the Project in substantially the same manner as it has
operated in the past. The aggregate cash purchase price paid by Central Valley
and the Trust for 100% of the JRW partnership interests was $5,300,000.
The San Joaquin Project, which is a Qualifying Facility, 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"). The Project's electricity
output is sold at a formula price set by the California Public Utilities
Commission that approximates the utility's avoided cost. Currently, the formula
consists of a fixed payment for the plant's capacity and a payment per unit of
energy delivered that is tied to 85% of the cost of natural gas, the fuel used
at the plant. The capacity payments vary seasonally and are significantly higher
during the April-October peak season. Thermal energy from the San Joaquin
Project is used to provide steam to an adjacent food processing company under
long term contracts that also terminate in 2020.
Until 1997, the plant only operated during the six month peak season during
peak hours. In 1997, the California Public Utilities Commission amended the rate
structure to allocate more of the capacity payments to operations during the
non-peak months from November to March. As a result, less of the capacity
payment could be earned during the peak season. The Trust approached the food
processor with a proposal to run the Project and provide steam year-round to the
processor. To do so, the Trust made approximately $750,000 of improvements to
the steam transfer system and the processor waived certain increases in the rent
for the Project site. The parties have negotiated modifications to the thermal
host contracts under which the Project rents its site from the food processor
and supplies it with steam for a net annual payment of $150,000 from the Project
to the food processor.
California is implementing a competitive power market beginning April
1, 1998 in which generators will eventually auction capacity and energy output
that is not committed for sale under long-term contracts. It is expected that
eventually the California Public Utilities Commission will change the payment
formula for many long-term contracts (including the San Joaquin Project's) to
use the auction prices for capacity and energy output. This would have effects
on the Project's revenues that are not predictable at this time but that might
result in a reduction in the prices paid by PG&E for electricity during off-peak
periods.
Distributions from the Project to the Trust for 1998 totalled $1,051,000 (a
17.3% annual return), down slightly from $1,152,000 in 1997. The decrease was
largely the result of increased operating costs from the move to 12 month
operation from nine months in 1997, and of a brief shutdown to install a new
boiler at JRW.
(ii) Byron Project.
Also in January 1995, the Trust caused the formation of Byron Power
Partners, L.P., a California limited partnership (the "Partnership") in which RW
Byron, Inc., a newly formed California corporation which is wholly owned by the
Trust ("Byron") owns a 1% general partner interest and the Trust owns a 99%
limited partnership interest. On January 17, 1995, the Partnership acquired
through a merger all of the assets and business of Altamont Cogeneration
Corporation ("Altamont") a California corporation which owns and operates an
approximately 5.7 megawatt electric cogeneration facility located near the city
of Byron, Alameda County, California. As a result of the merger, NorCal
Altamont, Inc., the parent of Altamont and an affiliate of a privately held
company, received a cash payment of $2,269,500 representing the purchase price
for the assets and businesses of Altamont acquired by the Partnership. The total
purchase price to the Trust was $3,138,000.
The Byron Project, like the San Joaquin Project, is fueled by natural gas
and sells its electricity output to Pacific Gas & Electric Company under
agreements substantially identical to those at the San Joaquin Project. The
Power Contracts also expire in 2020. The Project's heat output is used to
evaporate brine from oil and gas wells, with payments by the Project for the
site lease offsetting the thermal host's payments for heat.
The California Public Utilities Commission's changes to the rate structure
under the San Joaquin Power Contract, discussed above, had identical impact on
the Byron Project. No material capital improvements were needed for the Byron
Project to operate on a year-round schedule and like the San Joaquin Project it
began that schedule in April 1997.
Distributions to the Trust from the Byron Project in 1998 were $465,000 (a
15.5% annual return), down from $572,000 in 1997. The decrease was the result of
increased operating costs from the shift to 12 month operation from nine months
in 1997. See Item 7 - Management's Discussion and Analysis.
Please refer to the discussion of the San Joaquin Project for further
details on regulatory issues for the Byron Project.
(iii) On-site Cogeneration Projects
In September 1995, the Trust purchased the ownership interests in the
On-Site Cogeneration Projects, a portfolio of 35 "inside the fence" cogeneration
Projects owned by affiliates of Eastern Utilities Associates, Inc. ("EUA"), for
an aggregate purchase price of approximately $11.3 million. The Trust has
invested an additional $1.4 million for capital improvements in the Projects and
has expended additional amounts on remediation. The On-site Cogeneration
Projects use natural gas fired turbines or reciprocating engines to provide
electrical energy and/or heat for industrial uses or air conditioning purposes
under contracts with a variety of industrial customers. The On-site Cogeneration
Projects were located on 35 sites in California (18 sites), Connecticut (six
sites), Massachusetts (two sites), New York (eight sites) and Rhode Island (one
site). The purchase agreement provided that the acquisition would take place as
of September 30, 1995, and accordingly the Trust assumed the benefits and risks
of the On-site Cogeneration Projects accruing after that date. Distributions
from the On-site Cogeneration Projects began in 1996 and in 1998 totalled
$632,000 (a 15.2% annual return based on the investment after significant
writedowns), down from $1,424,000 in 1997.
Returns from the On-site Cogeneration Projects have deteriorated since
their purchase and beginning in the third quarter of 1997 the Trust has closed
the majority of the Projects for unprofitability or because of contract
expirations. As of March 1, 1999, only
12 of the Projects are still in operation. Because of closures and contract
expirations, the Trust has written down the value of its investment from $13.1
million to $4.2 million. See Note 3 to the Financial Statements for the details
of the writedowns. In the future, the Trust may decide to close additional
Projects because of contract expirations, unprofitability and other factors.
The On-Site Cogeneration Projects have been divided for financial reporting
purposes into four groups. The Massachusetts Projects include a project located
at a textile manufacturer in Fall River, Massachusetts (a 3.5 Megawatt turbine
with backup diesel engines) and a project at a housing complex in Worcester,
Massachusetts (.25 Megawatts). The Trust has successfully resolved contract
interpretation disputes with the textile manufacturer and the Massachusetts
Projects remain profitable. The Rhode Island Project, which was sold in December
1997, was located at a textile manufacturer in Centerdale, Rhode Island and had
a rated capacity of 4.2 Megawatts from three natural-gas- fired engines. The
host was obligated under an equipment lease and maintenance agreement to make
payments of approximately $900,000 per year to the Trust, and according to
projections supplied by EUA, the Project should have earned cash flow of
$800,000 per year. The host manufacturer for several years had been
significantly in arrears in its payments and made only sporadic payments to the
Trust. The Project's operations were suspended in October 1996, and were only
briefly resumed in spring 1997 after the host made a few payments. In May 1997
the host's primary lender threatened to place the host textile manufacturer into
bankruptcy, which would have terminated the host's contract with the Trust.
After protracted negotiations, the Trust sold the Project to the lender in
December 1997 for $900,000 and the Trust recorded a loss of $2,752,000.
The Coca-Cola Project is located at a bottling plant of Coca-Cola Bottling
Company of New York at Elmsford, New York and has a rated capacity of 1.3
Megawatts with a .6 Megawatt standby diesel generator set. The Project is
profitable but is not meeting projections because the bottling plant's demand
for heat has decreased and because of design defects in the Project which make
it incapable of avoiding a large portion of the bottling plant's charges from
the local utility.
The remaining 31 On-site Cogeneration Projects, all of which are or were
natural-gas-fueled, were located in California and New York and had an aggregate
rated capacity of 5.5 Megawatts. In 1996, the Trust discontinued operation of
and wrote off four small On-Site Cogeneration Projects in this group with a
total rated capacity of .24 Megawatts of electricity, which had book values
totalling $113,000. The discontinued Projects had produced nominal cash flow or
losses. In 1997 the Trust discontinued operation of and wrote off 15 additional
Projects with a rated capacity of 2.1 Megawatts in this group, for a total of
$4.8 million. After further review in 1998, the Trust wrote down the value of
the remaining 12 Projects by an additional $4.1 million. The Trust received an
arbitration award of $2.6 million against EUA for misrepresentations made by EUA
as to the condition of certain of the On-Site Cogeneration Projects and other
misrepresentations, as described at Item 3 - Legal Proceedings.
In purchasing the On-site Cogeneration Projects, the Managing Shareholder
concluded that the costs of engaging third party managers to operate many
smaller Projects would significantly reduce total returns to the Trust. The
Managing Shareholder, after reviewing the alternatives, elected to create an
in-house management capability as a means of limiting costs, acquiring valuable
operating and industry knowledge and increasing efficiency. It accordingly
organized an affiliate, Ridgewood Power Management Company. Management
responsibility for the On-site Cogeneration Projects was substantially
transferred to the Managing Shareholder and Ridgewood Power Management Company
at the end of 1995.
In January 1999 five of the remaining 12 Projects in this group, all
located on Long Island in New York State, were transferred to Ridgewood/AES
Power Partners, L.P. ("Ridgewood AES"), as described in the following
paragraphs.
(iv) Ridgewood/AES Power Partners, LLC.
Instead of operating eight of the smallest On-Site Cogeneration Projects
located in New York and Connecticut itself or through RPMCo, the Trust engaged
AES-NJ Cogen, Inc., a small operator of cogeneration plants in that area ("AES")
that is not affiliated with the Trust to operate them under contract. In
September 1997 the Trust and AES created a joint venture, Ridgewood AES, to
develop additional small cogeneration projects in the New York metropolitan
area. The Trust supplies capital and AES supplies development services. AES
receives a operating and maintenance fee of 1.1 cents per kilowatt-hour of
electricity produced and is responsible for routine maintenance; the Trust is
entitled to all distributions until it receives a preferred, non-cumulative
annual return of 16% on its capital investment, and then any further
distributions are shared equally with AES. At December 31, 1998 Ridgewood AES
owned five cogeneration projects at hotels and hospitals in New York and New
Jersey. Distributions from Ridgewood AES to the Trust in 1998 were $34,000 and
were $4,000 in 1997. At December 31, 1998 the Trust's total investment was
$472,000.
In January 1999 the Trust transferred five small cogeneration projects to
Ridgewood AES. Those projects had previously been operated by AES under contract
with the Trust.
(v) Ridgewood El Segundo, LLC
In April 1998 the Trust purchased an additional cogeneration project
located at a food preparation facility for the Los Angeles International Airport
from a private developer. The project is located within one mile of an On-Site
Cogeneration Project also owned by the Trust at the Airport. The total
investment was $692,000 at December 31, 1998. No distributions were made in 1998
from the Project to the Trust.
(vi) Providence Project
The Trust and Ridgewood Electric Power Trust IV, a similar program
organized by the Managing Shareholder ("Ridgewood Power IV"), acquired in April
1996 all of the equity interest in the Providence State Landfill Power Plant,
located near Providence, Rhode Island. The Trust invested $7.1 million in the
Project and Ridgewood Power IV supplied the remainder of the $20 million
investment in the Project. The acquisition cost was approximately $15.5 million
(including a $3 million partial prepayment of Project debt as a condition of
obtaining the lenders' consents and transaction costs)and the remainder of the
investment by the programs represents funds applied to operating reserves,
working capital and reserves for capital improvements and expansion. The Project
is encumbered by $5.4 million of debt maturing in installments through 2004. In
1997, as described below, capital improvements were completed and the Trust's
total investment in the Project increased to $7,504,000. At December 31, 1998,
intercompany transfers had reduced that amount to $7,310,000.
The Project burns methane gas (the major component of natural gas)
generated by the decomposition of garbage in the landfill as fuel for a 13.8
Megawatt capacity electric generation plant. The facility has been in operation
since 1990 and has a Power Contract for 12.0 Megawatts with New England Power
Company with a 22 year term remaining.
The Project leases the right to use the landfill site from the Rhode Island
Resource Recovery Corporation, a state agency, for a royalty of 15% of net
Project revenues (increasing to 15% to 18% in 2006) until 2020. The Project in
turn subleases those rights to Central Gas Limited Partnership ("Gasco"). Gasco,
which is not affiliated with the Trust, operates and maintains the piping system
and other facilities to collect the methane gas from the Landfill and supply it
to the Project. Gasco pays a fixed rent, computed on the basis of the Project's
generating capacity, to the Project under the sublease, and the Project in turn
buys its fuel from Gasco at a formula price per kilowatt-hour generated by the
Project.
Since the Trust purchased the Project in April 1996, average output from
the existing eight engine-generator sets has risen by approximately 25% from 9.2
Megawatts in the first three months of 1996 to 12.2 Megawatts in December 1996
and 11.5 Megawatts in 1997. Since August 1997, monthly sales have approached or
equalled the 12.0 Megawatt maximum under the Power Contract. In order to
increase output to the maximum and to allow engines to be rotated off-line for
preventative maintenance, an additional engine and generator set were installed
at the Project in spring 1997. Although this increased nominal Project capacity
by approximately 1/8, the actual benefit is the ability to have one engine
off-line at any time for maintenance and still produce the entire 12.0 Megawatts
that can be sold under the existing Power Contract. Distributions from the
Project for 1998 to the Trust totalled $547,000 (a 7.5% annual return) down from
$923,000 for 1997. The decrease is primarily the result of increased
expenditures in 1998 for regularly scheduled overhauls and preventive
maintenance of engines.
(vii) Hawthorne Equipment
In January 1999 the Trust agreed to purchase for $2,361,000 seven
Caterpillar unified power modules (consisting of a diesel engine and a linked
generator on a single skid, with control equipment) for delivery in June 1999. A
deposit of $590,000 was paid in February 1999. The purchase is being made
through Hawthorne Power Systems, Inc. of Los Angeles, California, which is a
dealer of Caterpillar power systems and which also maintains a rental fleet of
similar power modules. Hawthorne will market the Trust's modules along with its
own fleet for emergency, temporary or peak power supplies for industrial and
commercial customers, both domestic and international, and will maintain the
modules. Hawthorne will charge the Trust its customary fees, not in excess of
those applicable to its own fleet, for marketing and maintenance and all profit
or loss after payment of those fees and taxes will be for the account of the
Trust.
Except for possible additional investments through Ridgewood AES, the Trust
does not expect to make further investments.
(3) Project Operation.
Revenue from the San Joaquin, Byron and Providence Projects primarily comes
from Power Contracts with the local electric utilities. The pricing provisions
of these Power Contracts have two components, energy payments and capacity
payments. Energy payments are based on a facility's net electric output, with
payment rates usually indexed to the fuel costs of the purchasing utility or to
general inflation indices. Capacity payments are based on either a facility's
net electric output or its available capacity. Capacity payment rates vary over
the term of a Power Contract according to various schedules. Until April 1997,
approximately 90% of the capacity payment for the Byron and San Joaquin Projects
was allocated to the peak demand months of April through October, and
accordingly it was most economic to operate the Projects only in those months
and to close them for the remainder of the year. In 1997, the California Public
Utilities Commission reduced the allocations to the peak months to approximately
78%. This would cause a significant decrease in Project income if six-month
operations were continued. Accordingly, effective April 1, 1997, the Byron and
San Joaquin Projects were operated on a year-round schedule. The Trust believes
that substantially all of the incremental costs of full-year operation will be
recovered from the energy payments. In 1997, the change resulted in material
increases in the Projects' income. The allocation of capacity payments to peak
and non-peak months may be changed at any time by action of the California
Public Utilities Commission, based on its own review or petitions by purchasing
utilities, and any change may materially and adversely affect the two Projects.
The Power Contracts permit the purchasing utility to dispatch the facility
(i.e., direct it to deliver a reduced level of electric output) in certain
circumstances. In such cases, payments under the Power Contract are structured
so that, even when dispatching occurs, the facility continues to receive
capacity payments (which are intended to cover fixed costs and which often
provide substantially all of the facility's profits, if any) while it receives
reduced energy payments (which primarily cover the variable operating,
maintenance and fuel costs associated with operating the facility at lower or
higher levels).
The On-site Cogeneration, El Segundo and Ridgewood/AES Projects are
"inside-the-fence" cogeneration facilities that are located on the sites of host
businesses or organizations and that sell both their electrical output and their
heat output to their hosts. The long-term contracts with the hosts generally
provide that the Trust is compensated on a "shared savings" basis, under which
the net cost of the output is compared to the cost of purchasing the energy from
utility suppliers under a predetermined formula and the Trust is paid a
percentage of the computed savings. The Trust's return is thus linked to the
reliability and efficiency of its operations as well as the cost of alternate
sources.
The 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 Trust, through the Managing Shareholder, operates most of its Projects,
and Project operating costs have been wholly borne by the Trust as operating
expenses and have not been borne by the Managing Shareholder. Based on its
experience with the Trust's Projects and its experience managing other similar
investment programs, the Managing Shareholder believes that contracting with
third persons for the management of operating Projects in many cases is not in
the best interests of the Trust because of the fragmentation of responsibility,
the need for extensive oversight of the managers, the loss in some cases of
economies of scale, the difficulty in some areas of obtaining qualified managers
and the generally high cost of management contracts. These factors would be
particularly burdensome in the case of the inside-the-fence Projects, many of
which are small and located at multiple sites. Further, the use of third persons
to manage Projects deprives the Trust and other programs of management
experience and hands-on knowledge that otherwise would be acquired by the
Managing Shareholder or Affiliates.
The Managing Shareholder accordingly has organized RPMCo to provide
operating management for facilities operated by its investment programs, and has
assigned day-to-day management of all of its Projects, other than 10 small
cogeneration Projects located in New York, New Jersey and Connecticut, to RPMCo.
See Item 10 -- Directors and Executive Officers of the Registrant and Item
13 -- Certain Relationships and Related Transactions for further information
regarding the Operation Agreement and RPMCo and for the cost reimbursements
received by RPMCo.
Electricity produced by a Project is typically delivered to the purchaser
through transmission lines which are built to interconnect with the utility's
existing power grid or, in the On-site Cogeneration Projects, by direct
connections.
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. 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: under the shared savings contracts, changes in demand
directly and proportionately affect the Trust's revenues.
Generally, revenues from the sales of electric energy from a cogeneration
facility will represent the most significant portion of the facility's total
revenue. However, to maintain their status as a Qualifying Facility under PURPA,
it is imperative that each cogeneration Project continue to satisfy PURPA
cogeneration requirements as to the amount of thermal products generated.
Therefore, since the Byron and San Joaquin cogeneration Projects have only two
customers (the electric energy purchaser and the thermal products purchaser),
and because it may be impractical to obtain replacement purchasers of either the
electrical or thermal output, loss of either of these customers would likely
have a material adverse effect on the Trust.
PG&E undertakes a monitoring program as required by the California
Public Utilities Commission for data on thermal deliveries at the Byron and San
Joaquin Projects. If a Project were to fail to meet PURPA standards, PG&E would
be able to exclude a proportionate part of its purchases of electricity from the
long-term power contract and pay at substantially lower spot rates for that part
of its purchases. This would require the Project to refund substantial amounts.
To date PG&E has not been able to establish any deficiency by the Projects and
the Trust believes that the San Joaquin and Byron Projects have consistently
exceeded PURPA requirements.
Customers of Projects that accounted for more than 10% of annual
distributions from operating sources to the Trust in each of the last three
fiscal years are:
<TABLE>
<CAPTION>
Calendar year
1998 1997 1996
<S> <C> <C> <C>
Pacific Gas & Electric Co. 56% 42.3% 34.3%
(San Joaquin & Byron Projects)
New England Electric System 20% 22.6% 16.0%
(Providence Project)
Globe Manufacturing Co. 12% 18.3% 18.7%
(Massachusetts Projects)
The Worcester Company 0% 6.9% 16.3%
(Rhode Island Project)
</TABLE>
Each inside-the-fence Project sells all of its output to a single customer
and termination of those contracts would end all revenue from a Project, unless
the engines and other equipment could be economically moved to and installed on
a new host's site. The Providence Project burns methane gas generated by the
decomposition of garbage, which causes that Project to be a "small power
production facility" under PURPA. This allows it to be a Qualifying Facility
without the need to sell thermal energy or to meet efficiency standards.
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. Such
fluctuations directly affect the profitability of Projects that use these fuels.
In general, cogeneration, due to its higher efficiency, tends to be
relatively more profitable as energy costs (including natural gas) increase and
relatively less profitable as such costs decrease. Projects which use natural
gas as a fuel source bear the risk of gas price fluctuations adversely affecting
their economics.
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.
Although the capital costs and other expenses of environmental protection may
constitute a significant portion of the costs of a Project, the Trust believes
that those costs as imposed by current laws and regulations have been and will
continue to be largely incorporated into the prices of its investments and that
it accordingly has adjusted its investment program so as to minimize material
adverse effects. 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
The Trust is somewhat insulated from recent deregulatory trends in the
electric industry because the San Joaquin, Byron and Providence Projects are
Qualifying Facilities with long-term formula-price Power Contracts. Each Power
Contract now provides for rates in excess of current short-term rates for
purchased power. There has been much speculation that in the course of
deregulating the electric power industry, federal or state regulators or
utilities would attempt to invalidate these power purchase contracts as a means
of throwing some of the costs of deregulation on the owners of independent power
plants.
To date, the Federal Energy Regulatory Commission and California
authorities have ruled that existing Power Contracts will not be affected by
their deregulation initiatives. The regulators have so far rejected the requests
of a few utilities to invalidate existing Power Contracts. Instead, most state
plans for deregulation of the electric power industry treat the value of
long-term Power Contracts that are above current and anticipated market prices
as "stranded costs" of the utilities. The utilities are to be allowed to recover
those costs during a transition period. This is typically done by imposing a
transition fee or surcharge on rates that is paid to the utility. This
alternative is being implemented in California. In some states, utilities are
being encouraged or ordered to issue bonds or other financial instruments to
retire stranded cost assets or contracts, supported by transition charges.
No action has yet been taken by federal or state legislators to date to
impair Independent Power Projects' existing power sales contracts, and there are
federal constitutional provisions restricting actions to impair existing
contracts. There can not be any assurance, however, that the rapid changes
occurring in the industry and the economy as a whole would not cause regulators
or legislative bodies to attempt to change the regulatory structure in ways
harmful to Independent Power Projects or to attempt to impair existing
contracts. In particular, some regulatory agencies have urged utilities to
construe Power Contracts strictly and to police Independent Power Projects
compliance with those Power Contracts vigorously. See the discussion of the San
Joaquin Project, above, for regulatory requirements in California for utility
monitoring of Power Contracts and potential effects on the San Joaquin and Byron
Projects.
Predicting the consequences of any legislative or regulatory action is
inherently speculative and the effects of any action proposed or effected in the
future may harm or help the Trust. Because of the consistent position of the
regulatory authorities to date and the other factors discussed here, the Trust
believes that so long as it performs its obligations under the Power Contracts,
it will be entitled to the benefits of the contracts.
In recent years, many electric utilities have attempted to exploit all
possible means of terminating Power Contracts with independent power projects,
including requests to regulatory agencies and alleging violations of even
immaterial terms of the Power Contracts as justification for terminating those
contracts. An affiliate of the Trust, Ridgewood Electric Power Trust II, is
facing litigation from Pacific Gas and Electric Company challenging the status
of that trust's Monterey Project, a sister project to the Byron and San Joaquin
Projects. No action against the Trust's Projects is anticipated at this time. If
such an attempt were to be made, the Trust might face material costs in
contesting those utility actions. Other utilities have from time to time made
offers to purchase and terminate Power Contracts for lump sums. No such offer
has been suggested or made to the Trust, although the Trust is considering
making such an offer to Pacific Gas & Electric.
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 Contracts for the San Joaquin, Byron and Providence
Projects expire in 2020 or those contracts terminate for other reasons, those
Projects under currently anticipated conditions would be free to sell their
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 Projects could then sell their
output or do so profitably. Because the San Joaquin and Byron Projects are
fueled by natural gas purchased at market prices and because those Projects are
relatively small-scale, they might have cost disadvantages in competing against
larger competitors that would enjoy economies of scale. While the Providence
Project is not subject to natural gas price fluctuations and it may benefit from
environmental requirements for utilities to purchase power from environmentally
favorable sources, the supply of fuel gas from the landfill is not assured, and
it may also have diseconomies of small scale. The Trust is unable to anticipate
whether thermal sales from cogeneration from the San Joaquin and Byron Projects
or environmental subsidies at the Providence Project would offset any possible
cost disadvantages in electric generation or gas supply deficiencies or whether
in fact the Projects would have cost disadvantages after the contracts end. It
is thus impossible to predict the profitability of those Projects after
termination of the Power Contracts.
The remaining On-site Cogeneration Projects and the Ridgewood AES and El
Segundo Projects, which have "shared savings" contracts, are exposed to the
changes in the electric industry that are being caused by wholesale and retail
deregulation, as explained below. To date, these deregulation efforts have not
had material adverse effects on these Projects, but there is the potential for
some impact on revenues in 1998 and later years.
(5) Competition
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.
Competition to market its energy products is generally not a factor in the
current operations of the Trust since the major Projects in which it invests and
proposes to invest have entered into long-term agreements to sell their output
at specified prices. However, a particular Project could be subject to future
competition to market its energy products if its Power Contract expires or is
terminated because of a default or failure to pay by the purchasing utility or
other purchaser due to bankruptcy or insolvency of the purchaser or because of
the failure of a Project to comply with the terms of the Power Contract;
regulatory changes; loss of a cogeneration facility's status as a Qualifying
Facility due to failure to meet minimum steam output requirements; or other
reasons. It is impossible at this time to estimate the level of marketing
competition that the Trust would face in any such event.
(i) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not
limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are
subject to amendment or repeal. Future legislation and regulation is uncertain,
and could have material effects on the Trust.
(6) Regulatory Matters.
Projects are subject to energy and environmental laws and regulations at
the federal, state and local levels in connection with development, ownership,
operation, geographical location, zoning and land use of a Project and emissions
and other substances produced by a Project. These energy and environmental laws
and regulations generally require that a wide variety of permits and other
approvals be obtained before the commencement of construction or operation of an
energy-producing facility and that the facility then operate in compliance with
such permits and approvals. 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.
(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 (including
the Providence Project), 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. Recent federal
legislation has eliminated the maximum size requirement for solar, wind, waste
and geothermal small power production facilities (but not for hydroelectric or
biomass) for a fixed period of time.
In addition, PURPA requires electric utilities to purchase electricity
generated by Qualifying Facilities at a price equal to the purchasing utility's
full "avoided cost" and to sell back up power to Qualifying Facilities on a non
discriminatory basis. Avoided costs are defined by PURPA as the "incremental
costs to the electric utility of electric energy or capacity or both which, but
for the purchase from the Qualifying Facility or Qualifying Facilities, such
utility would generate itself or purchase from another source." Finally, PURPA
requires electric utilities to interconnect with Qualifying Facilities and
provide back-up power, which benefits the On-Site Cogeneration Projects. While
public utilities are not required by PURPA to enter into long-term Power
Contracts to meet their obligations to purchase from Qualifying Facilities,
PURPA helped to create a regulatory environment in which it had become more
common for such contracts to be negotiated until recent years.
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 the Byron, San Joaquin and Providence Projects, which
sell electricity to public utilities, and the On-Site Cogeneration, Ridgewood
AES and El Segundo Projects, which do not normally sell electricity but which
are interconnected with the local electric utilities, are Qualifying Facilities.
Maintaining the Qualified Facility status of an electric generating Project that
sells power to utilities is of utmost importance to the Trust. Such status may
be lost if a Project does not meet the operational requirements of PURPA, such
as minimum operating efficiency standards and minimum use of thermal energy by
customers of a cogeneration Project. The Trust endeavors to comply with these
requirements, but there can be no assurance that a Project will maintain its
Qualified Facility status. 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 (which are
generally substantially below the Power Contract rates) or the Project's Power
Contract can be terminated by the electric utility. In California, the state
regulator has authorized a comprehensive monitoring system under which electric
utilities continuously meter a Project's performance. Many California utilities,
including PG&E, the utility that purchases the San Joaquin and Byron Projects'
electric output, aggressively use this data to press for termination of
Qualifying Facility status, and there is an ongoing risk that the utility will
assert that the Project does not qualify for any given year. The Trust believes
that those Projects have qualified and will continue to qualify. The On- site
Cogeneration Projects do not sell material amounts electricity to utilities or
off-site customers; therefore, they need not be Qualifying Facilities so long as
state requirements or market forces assure the ability of the On-Site
Cogeneration Projects and similar Projects to interconnect for back-up power.
(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 act may result in
increased competition in the sale of electricity.
The 1992 Energy Act created the "exempt wholesale generator" category for
entities certified by FERC as being exclusively engaged in owning and operating
electric generation facilities producing electricity for resale. Exempt
wholesale generators remain subject to FERC regulation in all areas, including
rates, as well as state utility regulation, but electric utilities that
otherwise would be precluded by the Holding Company Act from owning interests in
exempt wholesale generators may do so. Exempt wholesale generators, however, may
not sell electricity to affiliated electric utilities without express state
approval that addresses issues of fairness to consumers and utilities and of
reliability.
(C) The Federal Power Act. The FPA grants FERC exclusive rate-making
jurisdiction over wholesale sales of electricity in interstate commerce. The FPA
provides FERC with ongoing as well as initial jurisdiction, enabling FERC to
revoke or modify previously approved rates. Such rates may be based on a
cost-of- service approach or determined through competitive bidding or
negotiation. While Qualifying Facilities under PURPA are exempt from the
rate-making and certain other provisions of the FPA, non-Qualifying Facilities
are subject to the FPA and to FERC rate-making jurisdiction.
Companies whose facilities are subject to regulation by FERC under the FPA
because they do not meet the requirements of PURPA may be limited in
negotiations with power purchasers. However, since such projects would not be
bound by PURPA's heat energy use requirement for cogeneration facilities, they
may have greater latitude in site selection and facility size. If any of the
Trust's electric power Projects that sell to utilties failed to be a Qualifying
Facility, it would have to comply with the FPA.
(D) Fuel Use Act. Larger Projects may also be subject to the Fuel Use Act, which
limits the ability of power producers to burn natural gas in new generation
facilities unless such facilities are also coal-capable within the meaning of
the Fuel Use Act. The Trust believes that the Byron and San Joaquin Projects are
coal-capable and thus qualify for exemption from the Fuel Use Act.
(E) State Regulation. State public utility regulatory commissions have broad
jurisdiction over Independent Power Projects which are not 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
which comply with federal, state and local requirements, which sometimes result
in extensive negotiations with regulatory agencies. Meeting the requirements of
each jurisdiction with authority over a Project may require extensive
modifications to existing Projects.
In September 1998 the Environmental Protection Agency ("EPA") brought
administrative proceedings against the Providence Project for violations of
training, recordkeeping and signage requirements. The alleged violations and the
proceedings are described at Item 3 - Legal Proceedings, below.
The Clean Air Act Amendments of 1990 contain provisions which regulate the
amount of sulfur dioxide and oxides of nitrogen which may be emitted by a
Project. These emissions may be a cause of "acid rain." Qualifying Facilities
are currently exempt from the acid rain control program of the Clean Air Act
Amendments. However, non-Qualifying Facility Projects will require "allowances"
to emit sulfur dioxide after the year 2000. Under the Amendments, these
allowances may be purchased from utility companies then emitting sulfur dioxide
or from the Environmental Protection Agency ("EPA"). Further, an Independent
Power Project subject to the requirements has a priority over utilities in
obtaining allowances directly from the EPA if (a) it is a new facility or unit
used to generate electricity; (b) 80% or more of its output is sold at
wholesale; (c) it does not generate electricity sold to affiliates (as
determined under the Holding Company Act) of the owner or operator (unless the
affiliate cannot provide allowances in certain cases) and (d) it is non-recourse
project-financed. The market price of an allowance cannot be predicted with
certainty at this time. In recent years, supply of allowances has tended to
exceed demand, primarily because of improved control technologies and the
increased use of natural gas.
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 will be in compliance with Title V requirements with only
minor modifications such as the installation of an additional catalytic
converter on some engines.
In July 1997 the Environmental Protection Agency adopted more stringent
standards for levels of ozone and small particulate matter (particles less than
25 microns in diameter) in geographic areas. These new standards may cause some
areas in which Projects are located to be classified as non-attainment areas. If
so, states will be required to impose additional requirements for industries to
reduce emissions. It is uncertain whether or how any reductions would be applied
to small facilities such as the Trust's Projects. If reductions were required,
the Trust might have to make significant capital investments to install new
control technology or might have to reduce operations. In addition, many eastern
states, including Massachusetts and New York, have organized in the Ozone
Transport Assessment Group to require further restrictions on emissions of
nitrogen oxides. The Environmental Protection Agency is considering the Group's
recommendations as well as other proposals to reduce emissions of nitrogen
oxides and other ozone- forming chemicals. If adopted, new regulations could
required the Trust to install additional equipment to reduce those emissions or
to change operations. Nitrogen oxide reductions can be difficult to achieve with
add-on equipment and often require decreases in operating efficiency, both of
which could cause material cost to the Trust. It is not possible at this time to
estimate whether or not any potential regulatory changes would materially affect
the Trust.
The Clean Air Act Amendments empower states to impose annual operating
permit fees of at least $25 per ton of regulated pollutants emitted up to
$100,000 per pollutant. To date, no state in which the Trust operates has done
so. If a state were to do so, such fees might have a material effect on the
Trust's costs of generation, in light of the relatively small size of the
Trust's facilities as opposed to large utility generation plants that might
benefit from the cap on fees.
The Trust's Projects must comply with many federal and state laws and
regulations governing wastewater and stormwater discharges from the Projects.
These are generally enforced by states under "NPDES" permits for point sources
of discharges and by stormwater 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 groundwaters or streams.
In 1998, the Trust's Projects will become 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 will 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.
Based on current trends, the Managing Shareholder expects that
environmental and land use regulation will become more stringent. The Trust and
the Managing Shareholder have developed limited expertise and experience in
obtaining necessary licenses, permits and approvals. The Trust will 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.
On February 14, 1994, the Trust notified the Securities and Exchange
Commission (the "Commission") of its election to be a "business development
company" and registered its Shares under the 1934 Act. On April 16, 1994, the
election and registration became effective. 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 the
Managing Shareholder and two individuals, Ralph O. Hellmold and Jonathan C.
Kaledin, who also serve as independent trustees of the Trust and who serve as
independent trustees of Ridgewood Electric Power II, and are independent panel
members of Ridgewood Electric Power Trust V, each of which is a similar
investment program organized by the Managing Shareholder,, but who are not
otherwise affiliated with the Trust, the Managing Shareholder 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.
(D) Financial Information about Foreign and Domestic Operations
and Export Sales.
The Trust has invested in Projects located in California,
Connecticut, Massachusetts, New York and Rhode Island and has no
foreign operations.
(E) Employees.
The Projects are operated by RPMCo and accordingly the Trust has no
employees. The persons described below at Item 10. Directors and executive
officers of the Managing Shareholder and RPMCo serve as executive officers of
the Trust and have the duties and powers usually applicable to similar officers
of a Delaware corporation in carrying out the Trust business.
Item 2. Properties.
Pursuant to the Management Agreement between the Trust and the Managing
Shareholder (described at Item 10(c)), the Managing Shareholder provides the
Trust with office space at the Managing Shareholder's principal office at The
Ridgewood Commons, 947 Linwood Avenue, Ridgewood, New Jersey 07450.
The following table shows the material properties (relating to Projects)
owned or leased by the Trust's subsidiaries or partnerships in which the Trust
has an interest. The On-site Cogeneration Projects are located on the hosts'
sites and generally do not occupy material amounts of space. All of the Projects
are described in further detail at Item 1(c)(2).
Approximate
Approx- Square Descrip-
Ownership Ground imate Footage of tion
Interests Lease Acreage Project (Actual of
Project Location in Land Expiration of Land or Projected) Project
Byron Byron, Leased 2021 2 28,000 Gas-fired
California cogeneration
facility
San Joaquin Atwater, Leased 2021 1 25,000 Gas-fired
California cogeneration
facility
On-Site 7 sites Leased various n/a n/a Inside-the-
Cogen- in CA, or fence,
eration CT, MA, licensed gas-fired
and NY or diesel-
fueled
cogeneration
engines and
generators
Providence Providence, Leased 2020 4 10,000 Landfill
Rhode Island gas-fired
generation
facility
Ridgewood 10 sites in Licensed various n/a n/a Inside-the-
AES NY and NJ fence, gas-
fired
cogeneration
engines and
generators
Ridgewood Los Angeles, Licensed n/a n/a Inside-the-
El Segundo CA fence, gas-
fired
cogeneration
facility
Item 3. Legal Proceedings.
In December 1996 the Trust's subsidiaries that own the on-site cogeneration
projects brought an arbitration proceeding against EUA before the American
Arbitration Association in Boston, Massachusetts as provided in the acquisition
agreement, claiming that EUA had breached its representations in the acquisition
agreement and had also defrauded the Trust through misrepresentations, improper
billing practices, fraud and violations of state fair trade practice laws. In
October 1998, the arbitrators awarded the Trust damages of approximately
$2,605,000 on certain of its claims of misrepresentation and awarded
approximately $395,000 to EUA for alleged unpaid management services thereon. In
November 1998, EUA made a payment of $2,210,000 to the Trust to liquidate the
claims. After deducting costs associated with the arbitration proceeding, the
Trust recognized income of $1,265,000.
The arbitration panel also awarded the Trust its attorneys' fees and
expenses incurred in prosecuting its case in chief, which the Trust computed at
approximately $997,000, and awarded EUA its attorneys' fees and expenses
incurred in prosecuting its counterclaim. The panel is expected to rule by the
end of April 1999 on objections raised by each party to the others' fees and
expenses and to make a final award. EUA has also refused to pay interest at 12%
per year awarded by the panel on the Trust's award from September 1995 to
November 1998 until a final ruling by the panel.
The Trust has brought a motion in the United States District Court for the
District of Massachusetts to confirm the award, which will await the final
ruling of the panel on the attorneys' fees and expenses. The Trust has not
recorded any potential recovery on fees, expenses and interest pending a final
ruling or payment.
In September 1998 the Region I office of the U.S. Environmental Protection
Agency (the "EPA") filed an administrative proceeding against Ridgewood
Providence Power Partners, L.P. ("RPPP"), a subsidiary of the Trust, seeking to
recover civil penalties of up to $190,000 for alleged violations of operational
recordkeeping and training requirements at the Providence Project. RPPP answered
and the matter has been referred to an alternative dispute resolution procedure
within the EPA. In the course of discussions with the EPA and through the
alternative dispute resolution procedure, EPA has offered to reduce the penalty
to $88,750. Further, EPA is discussing with RPPP a proposal to offset a portion
of the penalty by crediting RPPP with certain environmental audit and
remediation expenditures, over and above those required by law, that the Trust
and other Ridgewood Power Trusts may agree to make. RPPP expects to resolve this
matter in the second quarter of 1999 and does not anticipate that it will have
to make further material capital expenditures to remedy the items identified by
the EPA or that this proceeding will have a material adverse impact on it. The
Trust does not anticipate that it will be liable or will have to fund the costs
of this proceeding. Costs of defense and settlement will be paid by the Project.
On December 31, 1998 the Trust, through subsidiaries, filed a legal
complaint in the Superior Court of California for Monterey County against
Waukesha-Pierce, Inc. and subsidiaries, alleging that the subsidiaries had not
disclosed the existence of an obligation of the Monterey Project to Pacific Gas
and Electric Company and therefore breached a warranty in the acquisition
agreement. The claim was for approximately $273,000 plus interest and expenses.
Waukesha-Pierce, Inc. was included in the proceeding as a contractual guarantor.
On January 17, 1999, a separate action against Waukesha-Pierce, Inc. was filed
by the Trust's subsidiaries in the United States District Court for the Northern
District of Texas to enforce the guaranty. The parties are considering
settlement negotiations but the Trust will vigorously pursue these actions if
settlement is not promptly achieved.
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 1998.
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.
(a) Market Information.
The Trust sold 391.8444 Investor Shares of beneficial interest in the Trust
in its private placement offering of Investor Shares which closed on May 31,
1995. There is currently no established public trading market for the Investor
Shares and the Trust does not intend to allow a public trading market to
develop. 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 its Investor Shares.
Investor Shares are restricted as to transferability under the Declaration.
In addition, under federal laws regulating securities the Investor Shares have
restrictions on transferability when 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 (except for certain registrations that do not permit free resale) in
reliance upon what the Trust believes to be exemptions from the registration
requirements contained therein. Because the Investor Shares have not been
registered, they are "restricted securities" as defined in Rule 144 under the
1933 Act.
The Managing Shareholder is considering the possibility of a combination of
the Trust and five other investment programs sponsored by the Managing
Shareholder (Ridgewood Electric Power Trusts I, II, IV and V, and the Ridgewood
Power Growth Fund) into a publicly traded entity. This would require the
approval of the Investors in the Trust and the other programs after proxy
solicitations complying with requirements of the Securities and Exchange
Commission, 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 combined entity 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 973 record holders of Investor
Shares.
(c) Dividends
The Trust made distributions as follows in the years 1997 and 1998:
Year ended Year ended
December 31, 1997 December 31, 1998
Total distributions
to Investors $3,045,001 $2,352,106
Distributions per
Investor Share 7,771 6,003
Distributions to
Managing Shareholder 30,758 23,759
Distributions have been made on a monthly basis. Because of recent
reductions in the rate of distributions to $500 per month, effective January
1999, the Trust has proposed making future distributions on a quarterly basis
beginning at some time during the second quarter of 1999. The Trust's ability to
make future distributions to Investors and their timing will depend on the net
cash flow of the Trust and retention of reasonable reserves as determined by the
Trust to cover its anticipated expenses.
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. Because the Trust's objective is to distribute net cash flow, a
substantial portion of many distributions by the Trust will include cash flow
derived from depreciation and amortization charges against assets at the Project
level. 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 cash released from operating or debt service reserves, Trust-level
depreciation or amortization, 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.
<TABLE>
<CAPTION>
Supplemental Information As of and As of and As of and As of and
Schedule for the for the for the for the
Selected Financial Data Year ended Year Ended Year Ended Year Ended Period Ended
December 31, December 31, December 31, December 31 December 31,
1998 1997 1996 1995 1994
Total Fund Information:
<S> <C> <C> <C> <C> <C>
Net revenue from
operating projects $2,727,986 $4,075,390 $3,525,613 $1,317,287 $0
Net income (loss) (798,415) (1,355,866)(B) 2,541,686 1,440,550 (213,299)
(A),(C)
Net assets
(shareholders' equity) 23,783,034 26,957,314 31,388,939 32,579,226 18,671,356
Investments in project
development and power
generation limited
partnerships 21,714,050 24,613,978 28,050,750 20,884,493 0
Total assets 24,257,396 27,336,224 31,430,075 32,651,668 18,405,145
Per Investor Share:
Revenues $10,404 $10,788 $9,630 $6,066 $1,178
(C)
Expenses 12,442 14,249(B) 3,143 2,389 2,144
(A)
Net income (loss) (2,038) (3,460) 6,486 3,676 (966)
(A)(B)(C)
Net asset value 60,695 68,796 80,106 83,143 84,598
Distributions to Investors 6,003 7,771 9,429 5,896 0
</TABLE>
(A) After writedowns of investments in 1998 of $4,055,214 ($10,349 per Investor
Share).
(B) After writedowns of investments in 1997 of $4,743,631 ($12,106 per
Investor Share).
(C) Includes $1,265,122 ($3,229 per Investor Share) of income from arbitration
award.
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Introduction
The following discussion and analysis should be read in conjunction with the
Trust's financial statements and the notes thereto presented 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. The States that the Trust's Projects operate in have passed or are
considering new legislation that permits utility customers to choose their
electricity supplier in a competitive electricity market. The Providence, San
Joaquin and Byron Projects are "Qualified Facilities" as defined under the
Public Utility Regulatory Policies Act of 1978 and currently sell their electric
output to utilities under long-term contracts expiring in 2020, 2021 and 2020,
respectively. During the term of the contracts, the utilities may or may not
attempt to buy out the contracts prior to expiration. At the end of the
contracts, the Projects will become merchant plants and may be able to sell the
electric output at then current market prices. There can be no assurance that
future market prices will be sufficient to allow the Projects to operate
profitably.
Additional trends affecting the independent power industry generally are
described at Item 1 - Business.
Results of Operations
The year ended December 31, 1998 compared to the year ended December 31, 1997.
In 1998 and 1997, the Trust's net loss was $798,000 and $1,356,000,
respectively. The loss primarily resulted from 1998 and 1997 charges to earnings
of $4,055,000 and $4,744,000, respectively, relating to the write-down to net
realizable value of the Trust's investment in the on-site cogeneration projects
acquired from affiliates of EUA in 1995.
The Trust's subsidiaries that own the on-site cogeneration projects brought
an arbitration proceeding against EUA, as described at Item 3 - Legal
Proceedings. The Trust has not recorded amounts of the award that are currently
being considered by the arbitration panel or that EUA has refused to pay.
Without the write-downs of the on-site cogeneration projects and income
from the arbitration award, net income for 1998 would have been $1,992,000 as
compared to $3,388,000 for 1997, a decrease of $1,396,000 (41.2%). This increase
reflects a $1,347,000 decrease in income received from Projects in which the
Trust has invested and a decrease of $68,000 in interest income. The decrease in
interest income reflected the Trust's lower average cash balances.
As summarized below, income from power generation projects decreased 33.1% to
$2,728,000 in 1998 compared to $4,075,000 in 1997:
Project 1998 1997
On-site Cogeneration:
Massachusetts $ 324,000 $ 745,000
Rhode Island --- 283,000
New York 243,000 293,000
Others 65,000 104,000
Subtotal 632,000 1,425,000
Ridgewood AES 34,000 4,000
San Joaquin 1,051,000 1,152,000
Providence 547,000 923,000
Byron 464,000 571,000
Total $ 2,728,000 $4,075,000
In 1998, income from the San Joaquin, Byron and Providence Projects
decreased by $101,000 (8.8%), $107,000 (40.7%) and $376,000 (18.7%) and
respectively. The decrease in income from San Joaquin and Byron reflected
reduced margins from operating year round in 1998 compared to nine months of
operations in 1997. The change to year round operations was necessitated by a
change in the structure of the capacity payments from the utility. The decrease
in income from the Providence Project reflects the costs of periodic engine
maintenance. In 1998, income from the On-Site Cogeneration Projects decreased by
$793,000 (55.6%) as a result of the problems discussed above.
Excluding the writedown of investments, total expenses decreased by $20,000
(2.3%) to $820,000 in 1998 from $840,000 in 1997. Management fees declined
$93,000 (12.1%) to $674,000 in 1998 from $767,000 in 1997 reflecting the lower
net assets of the Trust. Accounting and legal expenses increased $48,000
(102.1%) from $47,000 in 1997 to $95,000 in 1998 as a result of legal costs
associated with disputes that were resolved in 1998.
The year ended December 31, 1997 compared to the year ended December 31, 1996.
In 1997, the Trust's net loss was $1,356,000. The loss resulted from 1997
charges to earnings totaling $4,744,000 relating to the write-down to net
realizable value of the Trust's investment in 16 terminated On-site Cogeneration
Projects acquired from affiliates of Eastern Utilities Associates in 1995. In
1996, the Trust wrote-down four On-site Cogeneration Projects totaling $113,000.
The 1997 and 1996 results from operations for the On-site Cogeneration Projects
were substantially below expectations resulting from the prior owner's poor
maintenance and operation, design defects, defaults by a customer, a pattern of
overbilling of customers and other breaches of the purchase agreement. These
Projects also suffered temporarily in early 1997 and late 1996 from sharp
increases in natural gas prices. Most of these Projects are "shared savings"
projects under which the Projects' billings are computed with reference to
utilities' retail electricity and gas rates. Because utility rates to retail
customers in many cases did not rise as fast as the gas prices paid by the
Projects, margins were severely impacted in the winter of 1996-1997.
Without the write-downs of the On-site Cogeneration Projects, net income
for 1997 would have been $3,388,000 as compared to net income of $2,655,000 for
1996, an increase of $733,000 (27.6%). This increase reflected a $549,000
increase in income received from Projects in which the Trust has invested, a
decrease of $96,000 (38.7%) in interest income and a decrease of $280,000
(25.0%) in other Trust expenses. In 1997, interest income decreased by $96,000
from 1996, as a result of the increase of the amount of cash invested in
Projects, which decreased the cash invested in short-term securities. For 1997,
the Trust's expenses (excluding investment write-downs) decreased by $280,000
from 1996, principally due to a $254,000 decrease in Project due diligence costs
because the Trust evaluated fewer acquisition targets in 1997. There were no
material changes in the other expense categories.
As summarized below, income from power generation projects increased 15.6%
to $4,075,000 in 1997 compared to $3,526,000 in 1996:
Project 1997 1996
On-site Cogeneration:
Massachusetts $ 745,000 $ 660,000
Rhode Island 283,000 573,000
New York 293,000 161,000
Others 104,000 362,000
Subtotal 1,425,000 1,756,000
Ridgewood AES 4,000 ---
San Joaquin 1,152,000 779,000
Providence 923,000 562,000*
Byron 571,000 429,000
Total $4,075,000 $3,526,000
* Represents a partial year April 16 to December 31, 1996.
In 1997, income from the San Joaquin, Providence and the Byron Projects
increased by $373,000 (47.9%), $361,000 (64.2%), and $142,000 (33.1%),
respectively. As a result of changes made in the calculation of capacity
payments received under their electricity sales contracts, the San Joaquin and
Byron Projects improved profitability by operating for nine months in 1997, as
compared to six months in 1996.. The Trust acquired its interest in the
Providence Project in mid-April 1996. Accordingly, 1996 results only include
eight and one half months of activity. Additionally, 1997 operating
profitability improved by adding a ninth engine and increasing sales to the
utility. In 1997, income from the On-Site Cogeneration Projects decreased by
$327,000 (18.6%) as a result of the problems discussed above.
Liquidity and Capital Resources
For 1998, net cash provided by operating activities was $2,103,000, which
included deductions of $1,155,000 for additional investments in projects. For
1997, net cash provided by operating activities was $2,804,000. This amount
included a $900,000 termination payment from the Rhode Island cogeneration
project and a deduction of $2,099,000 for additional investments in projects.
Cash distributions to shareholders were $2,376,000 in 1998 as compared to
$3,076,000 in 1997. As a result of lower earnings from the On-site Cogeneration
Projects, monthly cash distributions were reduced to $500 per share in July 1997
from an average of $800 per share during the first six months of the year.
During 1998 the Trust acquired an on-site cogeneration facility (the "El
Segundo Project") in Los Angeles, California, for $692,000. In addition, during
1998, the Trust invested an additional $331,000 in a series of cogeneration
projects in New York and New Jersey (the "Ridgewood/AES Projects"). In February
1999, the Trust made a $590,000 deposit for seven Caterpillar power modules that
are expected to be delivered in June 1999. The seven power modules have a total
purchase price of $2,361,000. The Trust plans to rent the power modules to
domestic and international customers.
During 1997, the Trust and Fleet Bank, N.A. (the "Bank") entered into a
revolving line of credit agreement, whereby the Bank provides a three year
committed line of credit facility of $750,000. 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. There were no borrowings under
the line of credit in 1998 or 1997.
Other than investments of available cash in power generation Projects,
obligations of the Trust are generally limited to payment of the management fee
to the Managing Shareholder, payments for certain accounting and legal services
to third persons and distributions to shareholders of available operating cash
flow generated by the Trust's investments. The Trust's policy is to distribute
as much cash as is prudent to shareholders. Accordingly, the Trust has not found
it necessary to retain a material amount of working capital. The need to retain
working capital is further reduced by the availability of the line of credit
facility. The Trust anticipates that its cash flow from operations during 1999,
and line of credit facility will be adequate to fund its obligations.
Year 2000 Remediation.
The Managing Shareholder and its affiliates began year 2000 review and
planning in early 1997. After initial remediation was completed, a more
intensive review discovered additional issues and the Managing Shareholder began
a formal remediation program in late 1997. The Managing Shareholder has assessed
problems, has a written plan for remediation and is implementing the plan.
The accounting, network and financial packages for the Ridgewood companies
are basically off-the-shelf packages that will be remediated, where necessary,
by obtaining patches or updated versions. The Managing Shareholder expects that
updating will be complete before the end of the April of 1999 with ample
time for implementation, testing and custom changes to some modifications made
by Ridgewood to those programs. To a large extent, these software packages would
have been upgraded within a three to five year time frame, even absent the Year
2000 problem. The Managing Shareholder estimates that the Trust's allocable
portion of the cost of upgrades that were accelerated because of the Year 2000
problem is approximately $600.
The Managing Shareholder has identified two major systems affecting the
Trust that rely on custom-written software, the subscription/investor relations
and investor distribution systems, which maintain individual investor records
and effect disbursement of distributions to Investors. In late 1998, the
Managing Shareholder's outside computer consultant reviewed the remediation
completed for those systems and advised the Managing Shareholder that material
additional work was required for these systems to work efficiently after 1999.
The Managing Shareholder accordingly employed a new specialist for Year 2000
remediation of those systems and other software and for information systems
support generally. The Managing Shareholder's plan called for completion of
changes to the distribution system and testing of that system by the end of the
first quarter of 1999 and the Managing Shareholder believes that this effort is
on schedule. The plan also targets completion by the end of the second quarter
of 1999 of minor changes to the elements of the subscription/investor relations
system that will allow it to handle individual investors' records, and of all
testing of those modifications. Elements of that system used to generate
internal sales reports and other internal reports (but which do not affect
investors' records) will require major remediation. Remediation of the internal
report generating programs is expected to be completed by the end of the third
quarter of 1999 with testing and any additional modifications to be completed no
later than the end of 1999.
The Managing Shareholder is confident that all software systems necessary
to maintain investor records will be remediated and tested well before the end
of 1999. If the systems used to generate internal reports from the
subscription/investor relations system are not remediated by the end of 1999,
the Managing Shareholder is developing a contingency plan to use the existing
systems together with manual entry of data and checking of results until
remediation is complete. The Managing Shareholder has done this in the past when
system problems have occurred and it thus believes that there will be no
material or noticeable effect on the accuracy of its records or generation of
internal reports, although it may experience delays in generating internal
reports of a few days.
Some systems are being remediated using the "sliding window" technique, in
which two digit years less than a threshold number are assumed to be in the
2000's and higher two digit numbers are assumed to be in the 1900's. Although
this will allow compliance for several years beyond the year 2000, eventually
those systems will have to be rewritten again or replaced. The Managing
Shareholder expects that the ordinary course of system upgrading will eventually
cure this problem.
The Trust's share of the incremental cost for Year 2000 remediation of this
custom written software and related items for 1998 and prior years is estimated
at $9,500 and is estimated to be approximately $9,000 for 1999.
Each of the Trust's electric generating facilities is being reviewed during
the first quarter of 1999 by an outside consultant or by Ridgewood Power
Management Corporation personnel to determine if its electronic control systems
contain software affected by the Year 2000 problem or contain embedded
components that contain Year 2000 flaws. The Trust owns small electric
generating facilities that rely on mechanical and analog systems, many of which
are not expected to be vulnerable to Year 2000 problems. The facilities use
personal computers running packaged software for routine recordkeeping and data
logging, which have been upgraded as described above. To date the Trust has
discovered no systems having a material impact on output, environmental
compliance, recordkeeping or any other material impact that have Year 2000
concerns. To date, initial reviews at the Byron and San Joaquin facilities have
not discovered any systems vulnerable to Year 2000 issues. The Providence and
On-Site Cogeneration facilities have not yet been reviewed. The Trust's share of
the estimated costs of the review and of any minor upgrades or rehabilitation is
estimated at less than $25,000.
The Managing Shareholder and its affiliates do not significantly rely on
computer input from suppliers and customers and thus are not directly affected
by other companies' Year 2000 compliance. However, if customers' payment systems
or suppliers' systems were adversely affected by year 2000 problems, the Trust
could be affected. For example, if the utilities that purchase the Trust's
electricity output were unable to accept electricity because of system
malfunctions or transmission failures caused by Year 2000 non-compliance by them
or other persons, the Trust would lose revenues that could not be recouped at a
later date. Similarly, if utility payment systems were to malfunction, the
Trust's revenues might be delayed. Based on published reports the Trust believes
that it is now very unlikely that utilities will fail to accept electricity for
more than a very short time because of malfunctions caused by the Year 2000
problem. Although the Trust also believes that utility payment problems are
unlikely and, if they occur, will not exceed a month or two, there can be no
assurance that payments to the Trust will not be interrupted. The Trust has
established a line of credit, described above at "Liquidity and Capital
Resources," to cover this contingency and others. The Trust's non-utility
customers were contacted during the first quarter of 1999. The Trust
anticipates that the customers will advise it that they do not anticipate that
their own Year 2000 problems, if any, will interfere with taking or paying for
the Trust's outputs of electricity or heat, but that they will decline to give
any assurance that they will be able to do so.
The Trust's main supply contingency is the availability of natural gas from
pipelines for fueling engine sets at the Byron, San Joaquin and On-Site
Cogeneration facilities. Accordingly the Trust is exposed to a possible
interruption of gas supply if Year 2000 problems interfere with pipeline
service. There is no reasonably available alternate source of gas and
accordingly an interruption of supply would necessarily close the plants.
Availability of other supplies such as spare parts and consumables may be
affected by Year 2000 problems; the Trust purchases these items from many
different sources, no single one or group of which could have a material effect
on the Trust if it or they were not Year 2000 compliant.
Because the Trust and the Managing Shareholder are extremely small relative
to the size of their utility customers and material suppliers and are paid or
supplied using the same systems as larger companies, requests for written
assurances of compliance from those customers or suppliers are not
cost-effective. Instead, the Managing Shareholder is monitoring industry trends
and compliance and is working to assure the Trust's continued operations.
Similarly, as described above, in most cases there are no cost-effective
contingency measures that can be taken against the major risks to the Trust that
utilities will fail to take or fail to pay for the Trust's electricity output or
that natural gas pipelines will fail to deliver gas as the result of Year 2000
problems. The Trust believes that in the event that any embedded components or
other systems are found to have Year 2000 problems at its power plants it will
be able to remediate them promptly and before the end of 1999. It is preparing
contingency plans to operate the plants with manual or analog control systems if
Year 2000 problems cannot be remediated. Because the plants are small and use
simple technologies (diesel engines and conventional generators) that are not
dependent on computers or date-sensitive electronics, the Trust believes that it
is unlikely that any facility other than the Providence facility would be unable
to operate because of Year 2000 problems at the facility. The Trust believes
that the Providence facility will also be capable of operation but is awaiting
the results of the systems review.
Based on its internal evaluations and the risks and contexts identified by
the Commission in its rules and interpretations, the Trust believes that Year
2000 issues relating to its assets and remediation program will not have a
material effect on its facilities, financial position or operations, and that
the costs of addressing the Year 2000 issues will not have a material effect on
its future consolidated operating results, financial condition or cash flows.
However, this belief is based upon current information, and there can be no
assurance that unanticipated problems will not occur or be discovered that would
result in material adverse effects on the Trust.
The Trust is unable to predict reliably what, if anything, will happen
after December 31, 1999 with regard to Year 2000 problems caused by the
inability of other businesses and government agencies to complete Year 2000
remediation. The Trust knows of no specific problems identified by customers or
suppliers that would have a material adverse effect on the Trust.
The reasonable worst case scenario anticipated by the Trust is that the
Byron, San Joaquin and On-Site Cogeneration facilities will be able to operate
on and after January 1, 2000 but that there may be some short-term inability of
their customers to pay promptly. In that event, the Trust's revenues could be
materially reduced for a temporary period and it might have to draw upon its
credit line to fund operating expenses until the utility makes up any payment
arrears. The Trust believes that the Providence facility will also be capable of
operation after January 1, 2000. For purposes of a worst case scenario it will
assume, until the survey of embedded components is completed, that the
Providence facility would not be able to operate after January 1, 2000 because
there might be an embedded component that is not Year 2000 compliant and the
component could not be replaced in time. In 1998, revenues from the Providence
Plant comprised about 20% of the Trust's operating revenues. In addition, the
Byron, San Joaquin and On-Site Cogeneration facilities rely on natural gas
pipelines for fuel. If the pipelines do not function properly because of Year
2000 problems, these facilities would have to reduce or cease operations, which
would have material adverse effects on the Trust.
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, 1998
Expected Maturity Date
1999
(U.S. $)
Bank Deposits and Certificates
of Deposit $ 2,414,916
Average interest rate 5.225%
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
Report of Independent Accountants F-2
Balance Sheet at December 31, 1998 and 1997 F-3
Statement of Operations for Three Years
ended December 31, 1998 F-4
Statement of Changes in Shareholders'
Equity for Three Years ended December 31,
1998 F-5
Statement of Cash Flows for Three Years
ended December 31, 1998 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 positions
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 or on a consolidated basis.
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 Corporation 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 is its managing
shareholder.
Robert E. Swanson has been the President, sole director and sole
stockholder of Ridgewood Power Corporation since its inception in February 1991.
The Managing Shareholder has also organized Ridgewood Electric Power Trust
I ("Ridgewood Power I"), Ridgewood Electric Power Trust II ("Ridgewood Power
II"), Ridgewood Electric Power Trust IV ("Ridgewood Power IV"), Ridgewood
Electric Power Trust V ("Ridgewood Power V") and The Ridgewood Power Growth Fund
(the "Growth Fund") as Delaware business trusts to participate in the
independent power industry. Ridgewood Power Corporation is now also their
managing shareholder. The business objectives of these five trusts are similar
to those of the Trust.
A number of other companies are affiliates of Mr. Swanson and Ridgewood
Power. Each of these also was organized as a corporation that was wholly-owned
by Mr. Swanson.
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 Corporation
("Ridgewood Capital"), which assists in offerings made by the Managing
Shareholder and which is the sponsor of two privately offered venture capital
funds (Ridgewood Capital Venture Partners, LLC and Ridgewood Institutional
Venture Partners, LLC); and Ridgewood Power VI Corporation ("Power VI Corp."),
which is a managing shareholder of the Growth Fund and RPMCo. 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 52, has also served as President of the Trust since
its inception in November 1992 and as President of RPMCo, Ridgewood Power I,
Ridgewood Power II, Ridgewood Power IV, Ridgewood 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 Ridgewood Capital Venture Partners, LLC and Ridgewood Institutional
Venture Partners, LLC. 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 40, has served as Executive Vice President of the
Managing Shareholder, RPMCo, Ridgewood Power I, the Trust, Ridgewood Power II,
Ridgewood Power IV, Ridgewood Power V and the Growth Fund since their respective
inceptions, with primary responsibility for marketing and acquisitions. He has
been President of Ridgewood Power Capital Corporation since its organization in
1998. As such, he is President of Ridgewood Capital Venture Partners, LLC and
Ridgewood Institutional Venture Partners, LLC. 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.
Thomas R. Brown, age 44, joined the Managing Shareholder in November 1994
as Senior Vice President and holds the same position with the Trust, RPMCo and
each of the other trusts sponsored by the Managing Shareholder. He became Chief
Operating Officer of the Managing Shareholder, RPMCo and the Ridgewood Power I
through V trusts in October 1996, and is the Chief Operating Officer of the
Growth Fund. He is also Senior Vice President of Ridgewood Capital and of the
two venture capital funds it manages. Mr. Brown has over 20 years' experience in
the development and operation of power and industrial projects. From 1992 until
joining the Managing Shareholder he was employed by Tampella Services, Inc., an
affiliate of Tampella, Inc., one of the world's largest manufacturers of boilers
and related equipment for the power industry. Mr. Brown was Project Manager for
Tampella's Piney Creek project, a $100 million bituminous waste coal fired
circulating fluidized bed power plant. Between 1990 and 1992 Mr. Brown was
Deputy Project Manager at Inter-Power of Pennsylvania, where he successfully
developed a 106 megawatt coal fired facility. Between 1982 and 1990 Mr. Brown
was employed by Pennsylvania Electric Company, an integrated utility, as a
Senior Thermal Performance Engineer. Prior to that, Mr. Brown was an Engineer
with Bethlehem Steel Corporation. He has an Bachelor of Science degree in
Mechanical Engineering from Pennsylvania State University and an MBA in Finance
from the University of Pennsylvania. Mr. Brown satisfied all requirements to
earn the Professional Engineer designation in 1985.
Martin V. Quinn, age 51, assumed the duties of Chief Financial Officer of
the Managing Shareholder, the Trust, the other four trusts organized by the
Managing Shareholder and RPMCo in November 1996 under a consulting arrangement.
He became a full-time officer of the Managing Shareholder and RPMCo in April
1997 and is now also Chief Financial Officer of the Growth Fund. He is also the
Chief Financial Officer of Ridgewood Capital and of Ridgewood Capital Venture
Partners, LLC and Ridgewood Institutional Venture Partners, LLC.
Mr. Quinn has 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 Price Waterhouse, and a Bachelor of Science
degree in Accounting and Finance from the University of Scranton (1969).
Mary Lou Olin, age 46, has served as Vice President of the Managing
Shareholder, RPMCo, Ridgewood Capital, the Trust, Ridgewood Power I, Ridgewood
Power II, Ridgewood Power IV, Ridgewood Power V and the Growth 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 both initial 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 until January 4, 2000 and 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. RPMCo 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 corporation 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 and Jonathan C.
Kaledin. Set forth below is certain information concerning Mr. Hellmold and Mr.
Kaledin, who also serve as independent trustees of Ridgewood Power II 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 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 58, is founder, sole shareholder and President of
Hellmold Associates, Inc., an investment banking firm and investment adviser
specializing in working with troubled companies or their creditors to raise
capital, divest businesses and restructure liabilities, whether in or outside
bankruptcy. Other financial advisory services provided by 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
which 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 Ridgewood
Power I and Ridgewood Power III, 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 41, 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 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 Ridgewood Power I, Ridgewood Power II, Ridgewood Power IV and Ridgewood Power
V 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) RPMCo.
As discussed above at Item 1 - Business, RPMCo assumed day-to-day
management responsibility for the San Joaquin, Byron, On- site Cogeneration and
Providence Projects in 1996. Like the Managing Shareholder, RPMCo 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 RPMCo, 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, RPMCo
charges the Trust at its cost for these services and for the Trust's allocable
amount of certain overhead items. RPMCo shares space and facilities with the
Managing Shareholder and its Affiliates. To the extent that common expenses can
be reasonably allocated to RPMCo, the Managing Shareholder may, but is not
required to, charge RPMCo 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 RPMCo for
the full amount of rent, utility supplies and office expenses allocable to
RPMCo. As a result, both initially and on an ongoing basis the Managing
Shareholder believes that RPMCo'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. RPMCo 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 RPMCo; and allocations will be made in a manner consistent
with generally accepted accounting principles.
RPMCo does not provide any services related to the administration of the
Trust, such as investment, accounting, tax, investor communication or regulatory
services, nor will it participate in identifying, acquiring or disposing of
Projects. RPMCo 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
RPMCo, 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 RPMCo; however, no amendment that
materially increases the obligations of the Trust or that materially decreases
the obligations of RPMCo shall become effective until at least 45 days after
notice of the amendment, togetherwith the text thereof, has been given to all
Investors.
The executive officers of RPMCo are Mr. Swanson (President), Mr. Gold
(Executive Vice President), Mr. Brown (Senior Vice President and Chief Operating
Officer), Mr. Quinn (Senior Vice President and Chief Financial Officer) and Ms.
Olin (Vice President). Douglas V. Liebschner, Vice President - Operations, is a
key employee.
Douglas V. Liebschner, age 50, joined RPMCo in June 1996 as Vice President
of Operations. He has over 27 years of experience in the operation and
maintenance of power plants. From 1992 until joining RPMCo, he was employed by
Tampella Services, Inc., an affiliate of Tampella, Inc., one of the world's
largest manufacturers of boilers and related equipment for the power industry.
Mr. Liebschner was Operations Supervisor for Tampella's Piney Creek project, a
$100 million bituminous waste coal fired circulating fluidized bed ("CFB") power
plant. Between 1989 and 1992, he supervised operations of a waste to energy
plant in Poughkeepsie, N.Y. and an anthracite-waste-coal-burning CFB in
Frackville, Pa. From 1969 to 1989, Mr. Liebschner served in the U.S. Navy,
retiring with the rank of Lieutenant Commander. While in the Navy, he served
mainly in billets dealing with the operation, maintenance and repair of ship
propulsion plants, twice serving as Chief Engineer on board U.S. Navy combatant
ships. He has a Bachelor of Science degree from the U.S. Naval Academy,
Annapolis, Md.
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. Since 1996 the Managing Shareholder has
compensated 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 will reimburse RPMCo at allocable cost for services provided by
RPMCo's employees; no such reimbursement per employee exceeded $60,000 in 1997
or 1998. 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. Accordingly, in January 1998 the Trust paid each
Independent Trustee $5,000 for his services. 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 391.8444 Investor Shares (approximately $39.2 million of
gross proceeds) of beneficial interest in the Trust pursuant to a private
placement offering under Rule 506 of Regulation D under the Securities Act. The
offering closed on May 31, 1995. Further details concerning the offering are set
forth above at Item 1 -- Business.
The Managing Shareholder purchased for cash in the offering one full
Investor Share. 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 purchase 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 the Managing Shareholder (excluding its interest
in the Trust attributable to Investor Shares it acquired in the offering). The
management rights of the Managing Shareholder are described in further detail
above at Item 1 -- Business and in Item 10 Directors and Executive Officers of
the Registrant. Its beneficial interest in cash distributions of the Trust and
its allocable share of the Trust's net profits and net losses and other items
attributable to the Management Share are described in further detail below at
Item 13 -- Certain Relationships and Related Transactions.
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable
reserves which the Trust deems necessary to cover anticipated Trust expenses, is
to be distributed to the Investors and the Managing Shareholder (collectively,
the "Shareholders"), from time to time as the Trust deems appropriate. Prior to
Payout (the point at which Investors have received cumulative distributions
equal to the amount of their capital contributions), 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 14% of their total capital contributions (a "14% Priority
Distribution"), and thereafter all remaining distributions from the Trust during
the year, other than distributions of the revenues from dispositions of Trust
Property, are to be allocated 80% to Investors and 20% to the Managing
Shareholder. Revenues from dispositions of Trust Property are to be distributed
99% to Investors and 1% to the Managing Shareholder until Payout. In all cases,
after Payout, Investors are to be allocated 80% of all distributions and the
Managing Shareholder 20%.
For any fiscal period, the Trust's net profits, if any, other than those
derived from dispositions of Trust Property, are allocated 99% to the Investors
and 1% to the Managing Shareholder until the profits so allocated offset (1) the
aggregate 14% Priority Distribution to all Investors and (2) any net losses from
prior periods that had been allocated to the Shareholders. Any remaining net
profits, other than those derived from dispositions of Trust Property, are
allocated 80% to the Investors and 20% to the Managing Shareholder. If the Trust
realizes net losses for the period, the losses are allocated 80% to the
Investors and 20% to the Managing Shareholder until the losses so allocated
offset any net profits from prior periods allocated to the Shareholders. Any
remaining net losses are allocated 99% to the Investors and 1% to the Managing
Shareholder. Revenues from dispositions of Trust Property are allocated in the
same manner as distributions from such dispositions. Amounts allocated to the
Investors are apportioned among them in proportion to their capital
contributions.
On liquidation of the Trust, the remaining assets of the Trust after
discharge of its obligations, including any loans owed by the Trust to the
Shareholders, will be distributed, first, 99% to the Investors and the remaining
1% to the Managing Shareholder, until Payout, and any remainder will be
distributed to the Shareholders in proportion to their capital accounts.
The Trust did not make any distributions in 1994 to the Managing
Shareholder (which is a member of the Board of the Trust) or any other person
and made distributions in 1995 and 1996 as stated at Item 5 -- Market for
Registrant's Common Equity and Related Stockholder Matters. The Trust and its
subsidiaries paid fees or reimbursements to the Managing Shareholder and its
affiliates as follows:
<TABLE>
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Fee Paid to 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C> <C>
Management Managing $673,933 $ 766,866 $794,026 $482,000 $0
fee Shareholder
Cost
reimbursements* RPMCo 15,617,631 14,308,444 11,566,400 0 0
Investment Managing 0 0 0 343,779 421,011
fee Shareholder
Placement Ridgewood 0 0 0 147,950 188,847
agent fee Securities
and sales Corporation
commissions
Organizational, Managing 0 0 0 860,195 1,088,727
distribution Shareholder
and offering fee
</TABLE>
* Prior to 1996, these costs were either paid by the Trust or by the Projects
directly. These include all payroll, parts, routine maintenance and other
expenses (except for royalties for landfill gas) of operating Projects that are
not operated by non-affiliated managers, and an allocation of RPMCo's overhead.
These costs are almost exclusively paid by the Projects and do not appear in the
Trust's financial statements.
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. In addition to
the foregoing, the Trust reimbursed the Managing Shareholder at cost for
expenses and fees of unaffiliated persons engaged by the Managing Shareholder
for Trust business and in 1995 for payroll and other costs of operation of the
Trust's Projects. Beginning in 1996, these reimbursements were paid to RPMCo.
The reimbursements to RPMCo, which do not exceed its actual costs, are described
at Item 10(g) -- Directors and Executive Officers of the Registrant -- RPMCo.
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, 1998.
(c) Exhibits
3A. Certificate of Trust of the Registrant is incorporated by reference to
Exhibit 3A of Registrant's Registration Statement filed with the Commission on
February 15, 1994.
3B. Declaration of Trust of the Registrant is incorporated by reference to
Exhibit 3B of Registrant's Registration Statement filed with the Commission on
February 19, 1994.
10A. Management Agreement dated as of January 3, 1994 between the
Registrant and Ridgewood Power Corporation is incorporated by reference to
Exhibit 10A of Registrant's Registration Statement filed with the Commission on
February 15, 1994.
10B. Acquisition Agreement dated as of January 9, 1995 among JRW Cogen,
Inc., and NorCal Cogen, Inc., as Sellers, and RW Central Valley, Inc., and
Ridgewood Electric Power Trust III, as Purchasers, is incorporated by reference
to Exhibit 2(i) to Registrant's Form 8K filed with the Commission on February
16, 1995.
10C. Agreement of Merger dated as of January 9, 1995 among Altamont
Cogeneration Corporation, NorCal Altamont, Inc., and Byron Power Partners, L.P.
is incorporated by reference to Exhibit 2(ii) to Registrant's Form 8K filed with
the Commission on February 16, 1995.
10.D Asset Acquisition Agreement by and among Northeast Landfill Power
Joint Venture, Northeast Landfill Power Company, Johnson Natural Power
Corporation and Ridgewood Providence Power Partners, L.P. , is incorporated by
reference to Exhibit 2 of the Registrant's Current Report on Form 8-K filed with
the Commission on May 2, 1996.
10.E Operation Agreement, dated as of April 16, 1996, among
Ridgewood/Providence Corporation, Ridgewood/Providence Power Partners, L.P. and
Ridgewood Power Management Corporation. Incorporated by reference to Exhibit 10E
to Registrant's Annual Report on Form 10-K for the year ended December 31, 1996.
The Registrant agrees to furnish supplementally a copy of any omitted
exhibit or schedule to agreements filed as exhibits to the Commission upon
request.
21. Subsidiaries of the Registrant. Incorporated by reference to Exhibit 21
of the Registrant's Annual Report on Form 10-K for the year ended December 31,
1995.
24. Powers of Attorney Page 69
27. Financial Data Schedule Page 72
<PAGE>
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Signature Title Date
RIDGEWOOD ELECTRIC POWER TRUST III (Registrant)
By:/s/ Robert E. Swanson President and Chief April 14, 1999
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 April 14, 1999
Robert E. Swanson Executive Officer
By:/s/ Martin V. Quinn Senior Vice President and
Martin V. Quinn Chief Financial Officer April 14, 1999
By:/s/ Kathleen P. McSherry Controller April 14, 1999
Kathleen P. McSherry
RIDGEWOOD POWER CORPORATION Managing Shareholder April 14, 1999
By:/s/ Robert E. Swanson President
Robert E. Swanson
/s/ Robert E. Swanson * Independent Trustee April 14, 1999
Ralph O. Hellmold
/s/ Robert E. Swanson Independent Trustee April 14, 1999
Jonathan C. Kaledin
* As attorney-in-fact for the Independent Trustee
Ridgewood Electric Power Trust III
Financial Statements
December 31, 1998, 1997 and 1996
-F1-
<PAGE>
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10036
[Letterhead of PricewaterhouseCoopers LLP]
Report of Independent Accountants
March 23, 1999
To the Shareholders and Trustees of Ridgewood Electric Power Trust III
In our opinion, the accompanying balance sheets and the related 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 III (the "Trust") at December 31, 1998 and 1997, and
the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles. 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 generally accepted
auditing standards 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 the opinion expressed above.
As explained in Note 3, the financial statements include investments,
valued at $21,714,050 and $24,613,978 (91% of shareholders' equity) as of
December 31, 1998 and 1997, 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, those estimated values may differ
significantly from the values that would have been used had a ready market
for the investments existed, and the differences could be material to the
financial statements.
/s/ PricewaterhouseCoopers LLP
-F2-
<PAGE>
Ridgewood Electric Power Trust III
Balance Sheet
- --------------------------------------------------------------------------------
December 31,
----------------------------
1998 1997
------------ ------------
Assets:
Investments in power generation projects . $ 21,714,050 $ 24,613,978
Cash and cash equivalents ................ 2,414,916 2,687,626
Due from affiliates ...................... 30,071 20,458
Other assets ............................. 98,359 14,162
------------ ------------
Total assets .................... $ 24,257,396 $ 27,336,224
------------ ------------
Liabilities and Shareholders' Equity:
Liabilities:
Accounts payable and accrued expenses .... $ 185,209 $ 38,537
Due to affiliates ........................ 289,153 340,373
------------ ------------
Total liabilities ............... 474,362 378,910
Commitments and contingencies
Shareholders' equity:
Shareholders' equity (391.8444
shares issued and outstanding) ......... 23,876,239 27,018,776
Managing shareholder's accumulated deficit (93,205) (61,462)
------------ ------------
Total shareholders' equity ...... 23,783,034 26,957,314
------------ ------------
Total liabilities and
shareholders' equity .......... $ 24,257,396 $ 27,336,224
------------ ------------
See accompanying notes to financial statements.
-F3-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Operations
- --------------------------------------------------------------------------------
Year Ended December 31,
1998 1997 1996
----------- ----------- -----------
Revenue:
Income from power generation
projects ..................... $ 2,727,968 $ 4,075,390 $ 3,525,613
Interest income ................ 83,807
247,762
Income from arbitration award .. 1,265,122 -- --
----------- ----------- -----------
Total revenue ............ 4,076,897 4,227,395 3,773,375
Expenses:
Project due diligence costs .. -- 3,692
258,378
Management fee ............... 673,933 766,866
794,026
Accounting and legal fees .... 94,734 46,869
48,231
Miscellaneous ................ 51,431 22,203
18,012
Writedown of investments
in power generation projects 4,055,214 4,743,631 113,042
----------- ----------- -----------
Total expenses ........... 4,875,312 5,583,261 1,231,689
----------- ----------- -----------
Net (loss) income ........ $ (798,415) $(1,355,866) $ 2,541,686
----------- ----------- -----------
See accompanying notes to financial statements.
-F4-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Changes in Shareholders' Equity
For the Years Ended December 31, 1998, 1997 and 1996
- --------------------------------------------------------------------------------
Managing
Shareholders Shareholder Total
------------ ------------ ------------
Shareholders' equity,
January 1, 1996 ..... $ 32,584,476 $ (5,250) $ 32,579,226
Cash distributions .... (3,694,661) (37,312) (3,731,973)
Net income for the year 2,516,269 25,417 2,541,686
------------ ------------ ------------
Shareholders' equity,
December 31, 1996 ... 31,406,084 (17,145) 31,388,939
Cash distributions .... (3,045,001) (30,758) (3,075,759)
Net loss for the year . (1,342,307) (13,559) (1,355,866)
------------ ------------ ------------
Shareholders' equity,
December 31, 1997 ... 27,018,776 (61,462) 26,957,314
Cash distributions .... (2,352,106) (23,759) (2,375,865)
Net loss for the year . (790,431) (7,984) (798,415)
------------ ------------ ------------
Shareholders' equity,
December 31, 1998 ... $ 23,876,239 $ (93,205) $ 23,783,034
------------ ------------ ------------
See accompanying notes to financial statements.
-F5-
<PAGE>
Ridgewood Electric Power Trust III
Statement of Cash Flows
- --------------------------------------------------------------------------------
Year Ended December 31,
--------------------------------------------
1998 1997 1996
------------ ------------ ------------
Cash flows from operating
activities:
Net (loss) income ............ $ (798,415) $ (1,355,866) $ 2,541,686
------------ ------------ ------------
Adjustment to reconcile net
(loss) income to net cash
flows from operating
activities:
Writedown of power generation
project investments
4,055,214 4,743,631 113,042
Investments in power
generation projects ........ (1,155,286) (2,098,774) (7,279,299)
Proceeds from sale or transfer
of investment .............. -- 900,000 353,619
Changes in assets and
liabilities:
(Increase) decrease in due
to/from affiliates, net ... (60,833) 320,915 (109,085)
Decrease in deferred due
diligence costs ........... -- 30,000 273,213
(Increase) decrease in other
assets .................... (84,197) 266,838 (88,808)
Increase (decrease) in
accounts payable and
accrued expenses .......... 146,672 (2,599) (85,731)
------------ ------------ ------------
Total adjustments ......... 2,901,570 4,160,011 (6,823,049)
------------ ------------ ------------
Net cash provided by (used
in)operating activities . 2,103,155 2,804,145 (4,281,363)
------------ ------------ ------------
Cash flows from financing
activities:
Cash distributions to
shareholders ............. (2,375,865) (3,075,759) (3,731,973)
------------ ------------ ------------
Net cash used in financing
activities ............... (2,375,865) (3,075,759) (3,731,973)
------------ ------------ ------------
Net decrease in cash and
cash equivalents ......... (272,710) (271,614) (8,013,336)
Cash and cash equivalents,
beginning of year .......... 2,687,626 2,959,240 10,972,576
------------ ------------ ------------
Cash and cash equivalents,
end of year ................ $ 2,414,916 $ 2,687,626 $ 2,959,240
------------ ------------ ------------
See accompanying notes to financial statements.
- -F6-
<PAGE>
Ridgewood Electric Power Trust III
Notes to Financial Statements
- --------------------------------------------------------------------------------
1. Organization and Purpose
Ridgewood Electric Power Trust III (the "Trust") was formed as a Delaware
business trust on December 6, 1993, by Ridgewood Energy Holding Corporation
acting as the Corporate Trustee. The managing shareholder of the Trust is
Ridgewood Power Corporation. The Trust began offering shares on January 3, 1994.
The Trust commenced operations on April 16, 1994 and discontinued its offering
of shares on May 31, 1995.
The Trust has been organized to invest in independent power generation
facilities and in the development of these facilities. These independent power
generation facilities include cogeneration facilities, which produce both
electricity and thermal energy, and other power plants that use various fuel
sources (except nuclear). The power plants sell electricity and, in some cases,
thermal energy to utilities and industrial users under long-term contracts.
"Business Development Company" election
Effective April 16, 1994, 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 original maturities of
three months or less when purchased to be cash and cash equivalents.
Due diligence costs relating to potential power project investments
Costs relating to the due diligence performed on potential power project
investments, are initially deferred, until such time as the Trust determines
whether or not it will make an investment in the respective project. Costs
relating to completed projects are capitalized and costs relating to rejected
projects are expensed at the time of rejection.
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 Trust.
-F7-
<PAGE>
Reclassifications
Certain items in previously issued financial statements have been reclassified
for comparative purposes.
3. Investments in Power Generation Projects
The Trust had the following investments in power generation projects:
Fair Values as of December 31,
1998 1997
----------- -----------
JRW Associates, L.P. ............................. $ 6,087,039 $ 5,481,186
Byron Power Partners, L.P. ....................... 2,999,031 2,734,331
Ridgewood Providence Power Partners, L.P. ........ 7,310,458 7,504,792
Ridgewood AES Power Partners, LLC ................ 472,496 141,065
Ridgewood El Segundo LLC ......................... 691,619 --
On-site Cogeneration Projects:
Ridgewood/Mass PPLP ........................... 2,394,851 3,731,067
Ridgewood/Elmsford PPLP ....................... 990,082 1,756,416
Other On-site Cogeneration Project Partnerships 768,474 3,265,121
----------- -----------
$21,714,050 $24,613,978
----------- -----------
The Trust's distribution income from the projects was as follows:
For the Year Ended December 31,
------------------------------------
1998 1997 1996
---------- ---------- ----------
JRW Associates, L.P. .................... $1,051,375 $1,152,013 $ 779,409
Byron Power Partners, L.P. .............. 464,530 571,576 428,540
Ridgewood Providence Power Partners, L.P. 546,690 922,941 562,427
Ridgewood AES Power Partners, LLC ....... 33,807 4,249 --
On-site Cogeneration Projects:
Ridgewood/Rhode Island PPLP ........... -- 282,943 572,970
Ridgewood/Mass PPLP ................... 323,694 745,005 660,201
Ridgewood/Elmsford PPLP ............... 242,881 292,543 160,940
Other On-site Cogeneration
Project Partnerships ................ 64,991 104,120 361,126
---------- ---------- ----------
$2,727,968 $4,075,390 $3,525,613
---------- ---------- ----------
JRW Associates, L.P. (known as San Joaquin Power Company)
On January 17, 1995, the Trust acquired 100% of the existing partnership
interests of JRW Associates, L.P., which owns and operates an 8.5 megawatt
electric cogeneration facility, located in Atwater, California. The aggregate
cost of the investment was $6,087,039 and $5,481,186 at December 31, 1998 and
1997, respectively. The increase in investment was primarily caused by the
cost of a new boiler installed at the facility in 1998. The Trust received
distributions of $1,051,375, $1,152,013 and $779,409 from the project in
1998, 1997 and 1996, respectively.
Byron Power Partners, L.P. (known as Byron Power Company)
In January 1995, the Trust caused the formation of Byron Power Partners, L.P.
in which the Trust owns 100% of the existing partnership interests. On
January 17, 1995, Byron Power Partners, L.P. acquired a 5.7 megawatt electric
cogeneration facility, located in Byron, California. As of December 31, 1998
and 1997, the aggregate cost of the Trust's investment in the partnership was
$2,999,031 and $2,734,331, respectively. The Trust received distributions of
$464,530, $571,576 and $428,540 from the project in 1998, 1997 and 1996,
respectively.
-F8-
<PAGE>
Ridgewood Providence Power Partners, L.P. (known as the Providence Project)
In 1996, Ridgewood Providence Power Partners, L.P. was formed as a Delaware
limited partnership ("Providence Power"). The Trust owns a 35.7% limited
partnership interest in Providence Power. In addition, Ridgewood Providence
Power Corporation was formed as a Delaware corporation ("RPPCorp.") and the
Trust owns 35.7% of the outstanding common stock of RPPCorp., which is the
sole general partner of Providence Power. At December 31, 1998 and 1997, the
total cost of the Trust's investment was $7,310,458 and $7,504,792,
respectively.
On April 16, 1996, Providence Power purchased substantially all of the net
assets of Northeastern Landfill Power Joint Venture. The assets acquired
included a 12.3 megawatt capacity electrical generating station, located at
the Central Landfill in Johnston, Rhode Island (the "Providence Project"). In
1997, the capacity was increased to 13.8 megawatt.
The Providence Project includes nine reciprocating electric generator engines
which are fueled by methane gas produced and collected from the landfill. The
electricity generated is sold to New England Power Corporation under a
long-term contract. The purchase price was $15,533,021 in cash, including
transaction costs and repayment of $3,000,000 of principal on senior secured
non-recourse notes payable. In addition, Providence Power assumed the
obligation to repay the remaining principal outstanding of $6,310,404 on the
senior secured non-recourse notes payable.
Through ownership in RPPCorp. and Providence Power, the Trust owns 35.7% of
the Providence Project. The remaining 64.3% is owned by Ridgewood Electric
Power Trust IV ("Trust IV"). Ridgewood Power Corporation is the managing
partner of the Trust and Trust IV. In 1998, 1997 and 1996, the Trust received
distributions of $546,690, $922,941 and $562,427, respectively, from the
Providence Project.
Ridgewood AES Power Partners, LLC (known as Ridgewood AES)
In September 1997, the Trust formed Ridgewood AES Power Partners, LLC entered
into an agreement with AES-NJ Cogen, Inc. (AES-NJ) to invest in co-generation
facilities operated by AES-NJ. In 1997, Ridgewood AES owned three facilities
and added two additional facilities in 1998. The facilities are all located
in New York. The aggregate cost of the investment was $472,496 and $141,065
at December 31, 1998 and 1997, respectively. The Trust received distributions
of $33,807 and $4,249 from the projects in 1998 and 1997, respectively. In
January 1999, the Trust transferred five of its Other On-site Cogeneration
Projects with a fair value of $283,966 to Ridgewood AES.
Ridgewood El Segundo, LLC (known as the Dobbs House project)
In April 1998, the Trust purchased an on-site cogeneration facility located
near one of its existing on-site cogeneration facilities in Los Angeles,
California. The total purchase price was approximately $590,733, including
the payment of liabilities that encumbered the project. The aggregate cost of
the investment was $691,619 at December 31, 1998.
On-site Cogeneration Projects
In 1995, the Trust acquired a portfolio of 35 projects from affiliates of
Eastern Utilities Associates ("EUA"), which sell electricity and thermal
energy to industrial and commercial customers. The projects are held in eight
limited partnerships of which the Trust is the sole limited partner and is
the sole owner of each of the general partners. In the aggregate, the
projects had 13.7 megawatts of base load and 5.7 megawatts of backup and
standby capacity. The Trust paid a total of $11,300,000 for the projects and
invested additional amounts for capital repairs and improvements and for
working capital. EUA operated the projects under a transition agreement until
January 1, 1996, at which time Ridgewood Power Management Corporation
("RPMC"), an affiliate of the Trust, assumed operational control. No
distributions were made by these projects in 1995. The Trust received
distributions of $631,566, $1,424,611 and $1,755,237 from these projects in
1998, 1997 and 1996, respectively. See Note 6 - Arbitration and Litigation,
for information relating to arbitration proceedings against EUA.
-F9-
<PAGE>
Ridgewood/Rhode Island Power Partners L.P.
Ridgewood/Rhode Island Power Partners Limited Partnership (the "Partnership")
leased three 1.4 megawatt Cooper Superior gas fired generator sets with heat
recovery to a Rhode Island manufacturing company under a lease expiring in
2006. Two engines were in regular use and one engine was on standby. The
partnership received a monthly fixed lease payment and a maintenance payment,
which escalated over the term of the lease. The Partnership was responsible
for maintaining the engines and related equipment. At the expiration of the
lease, the lessee had the right to purchase the equipment from the
partnership for its fair market value. The Trust received distributions of
$282,943 and $572,970 from the project in 1997 and 1996, respectively.
During 1997, the lessee experienced severe financial difficulties and
repeatedly defaulted on its payment obligations. In response, the lessee
alleged violations by the Partnership of the lease and requested
renegotiation of the lease. In the course of the negotiations, the lessee's
principal creditor threatened to place the lessee in Chapter 11 bankruptcy,
which would result in a cancellation of the lease. In December 1997, the
lessee purchased the facility (the "Worcester Project") and terminated the
lease in exchange for a single cash payment of $900,000. Accordingly, the
Trust wrote down its investment in the Partnership and recorded a loss of
$2,752,168.
Ridgewood/Massachusetts Power Partners L.P.
Ridgewood/Massachusetts Power Partners L.P. (the "Partnership") owns two
projects. The first is a 3.5 megawatt base load, single cycle, dual-fuel,
combustion turbine powered plant with a heat recovery steam generator which
sells electric power and steam to a manufacturing facility on whose site the
plant is located. The project includes two 1.6 megawatt Caterpillar diesel
engine generator sets to provide backup power. The project sells electric and
thermal energy to the manufacturing facility at the project's production cost
(as defined in the Energy Service Agreement) plus a share of the savings (the
difference between what the electric and thermal energy would have cost the
company absent the cogeneration plant). The Energy Service Agreement expires
at the end of 2005. During 1998, the Trust completed an intensive review of
the project and determined that a write-down of the fair value of $1,236,002
was required. As of December 31, 1998 and 1997, the total cost of the Trust's
investment in the partnership was $2,394,851 and $3,731,067 respectively. The
Trust received distributions of $323,694, $745,005 and $660,201 from the
project in 1998, 1997 and 1996, respectively. The Partnership also owns a
smaller group of four cogeneration generator sets totaling 255 kilowatt
serving a residential complex in Worcester, Massachusetts. The energy
services agreement ("ESA") provides that the partnership receives from the
customer the cost to purchase electricity and natural gas from the local
utility, less a guaranteed savings based on the utility's current rates. The
ESA expires in 2004.
Ridgewood/Elmsford Power Partners, L.P.
Ridgewood/Elmsford Power Partners, L.P. (the "Partnership") owns one
cogeneration project consisting of two 665 kilowatt (1,330 kilowatt total)
dual-fuel Cooper Superior engine generator sets with heat recovery and a
Caterpillar 600 kilowatt standby diesel generator set. The Energy Services
Agreement ("ESA") expires in 2005 and provides that the Partnership receives
its production costs (as defined in the ESA) plus a share of the excess of
the customer's avoided cost over production costs. During 1998, the Trust
completed an intensive review of the project and determined that a write-down
of the fair value of $505,390 was required. As of December 31, 1998 and 1997,
the total cost of the Trust's investment in the partnership was $990,082 and
$1,756,416, respectively. The Trust received distributions of $242,881,
$292,543 and $160,940 from the project in 1998, 1997 and 1996, respectively.
The "Other On-site Cogeneration Project Partnerships"
The "other on-site cogeneration project partnerships" include five
partnerships, which owned 31 of the 35 projects acquired from Eastern
Utilities Associates. These 31 projects represented approximately one-third
of the Trust's original investment in the on-site cogeneration projects. All
thirty-one were gas-fired cogeneration projects, located in California,
Connecticut or New York. Their energy service
-F10-
<PAGE>
agreements had terms expiring between September 1996 and 2011. The projects
represented 5.5 MW of base load capacity. The largest project was 660 kilowatts
or 12% of the capacity. The projects ranged in size from 30 kilowatts to 660
kilowatts. In 1996, the Trust wrote-off four small projects amounting to
$113,042. In 1997, the Trust wrote-off an additional fifteen projects with 2.1
megawatts of base load capacity amounting to $1,991,463. During 1998, the Trust
completed an intensive review of the projects and determined that a write-down
of the fair value of $2,313,822 was required. The Trust received distributions
of $64,991, $104,120 and $361,126 from the projects in 1998, 1997 and 1996,
respectively. As of December 31, 1998 and 1997, the total cost of the Trust's
investment in the "other on-site cogeneration partnerships" was $768,474 and
$3,265,121, respectively. In January 1999, the Trust transferred five of its
Other On-site Cogeneration Projects with a fair value of $283,966 to Ridgewood
AES.
4. Transactions With Managing Shareholder And Affiliates
The Trust pays to the managing shareholder a distribution and offering fee up
to 5% of each capital contribution made to the Trust. The fee is intended to
cover legal, accounting, consulting, filing, printing, distribution, selling
and closing costs for the offering of the Trust. These fees were recorded as
a reduction in shareholders' capital contributions.
The Trust pays to the managing shareholder an investment fee up to 2% of each
capital contribution made to the Trust. The fee is payable to the managing
shareholder for its services in investigating and evaluating investment
opportunities and effecting transactions for investing the capital of the
Trust.
The Trust entered into a management agreement with the managing shareholder,
under which the managing shareholder renders certain management,
administrative and advisory services and provides office space and other
facilities to the Trust. As compensation to the managing shareholder, the
Trust pays the managing shareholder an annual management fee equal to 2.5% of
the net asset value of the Trust payable monthly upon the closing of the
Trust. For the years ended December 31, 1998, 1997 and 1996, the Trust paid
management fees to the managing shareholder of $673,933, $766,866 and
$794,026, respectively.
Under the Declaration of Trust, the managing shareholder is entitled to
receive each year 1% of all distributions made by the Trust (other than those
derived from the disposition of Trust property) until the shareholders have
been distributed in that year an amount equal to 14% of their equity
contribution. Thereafter, the managing shareholder is entitled to receive 20%
of the distributions for the remainder of the year. The managing shareholder
is entitled to receive 1% of the proceeds from dispositions of Trust
properties until the shareholders have received cumulative distributions
equal to their original investment ("Payout"). After Payout the managing
shareholder is entitled to receive 20% of all remaining distributions of the
Trust.
Where permitted, in the event the managing shareholder or an affiliate
performs brokering services in respect of an investment acquisition or
disposition opportunity for the Trust, the managing shareholder or such
affiliate may charge the Trust a brokerage fee. Such fee may not exceed 2% of
the gross proceeds of any such acquisition or disposition. No such fees have
been paid through December 31, 1998.
The managing shareholder owns one share of the Trust with a cost of $84,000.
In conjunction with the offering of the Trust shares, commissions and
placement fees of $390,844 were earned by Ridgewood Securities Corporation,
an affiliate of the managing shareholder.
Effective from January 1, 1996, under an operating agreement with the Trust,
Ridgewood Power Management Corporation ("Ridgewood Management"), an entity
related to the managing shareholder through common ownership, provides
management, purchasing, engineering, planning and administrative services to
the power generation projects operated by the Trust. Ridgewood
- -F11-
<PAGE>
Management harges the projects at its cost for these services and for the
allocable amount of certain overhead items. Allocations of costs are on the
basis of identifiable direct costs, time records or in proportion to amounts
invested in projects managed by Ridgewood Management. During the year ended
December 31, 1998, 1997 and 1996, Ridgewood Management charged the following to
the projects based on proportionate amounts invested:
For the Year Ended December 31,
------------------------------
1998 1997 1996
-------- -------- --------
JRW Associates, L.P. .................... $119,960 $ 94,460 $ 91,962
Byron Power Partners, L.P. .............. 70,956 55,740 49,972
Ridgewood Providence Power Partners, L.P. 401,290 467,881 316,228
Ridgewood El Segundo LLC ................ 9,120 -- --
On-site Cogeneration Projects:
Ridgewood/Mass PPLP ................... 106,685 91,081 79,408
Ridgewood/Elmsford PPLP ............... 47,385 42,590 35,129
Other On-site Cogeneration
Project Partnerships ................ 100,005 122,871 31,264
5. Line of Credit Facility
During the fourth quarter of 1997, the Trust and the Trust's principal bank
executed a revolving line of credit agreement, whereby the bank will provide
a three year committed line of credit facility of $757,000. Outstanding
borrowings bear interest at the bank's prime rate or, at the Trust's choice,
at LIBOR plus 2.5%. 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. At December 31, 1998 and 1997,
there were no borrowings outstanding under the credit facility.
6. Arbitration and Litigation
In December 1996, the Trust's subsidiaries that own the on-site cogeneration
projects brought an arbitration proceeding against EUA, claiming that EUA had
breached its representations in the acquisition agreement and had also
defrauded the trust through misrepresentations, improper billing practices
and violations of state fair trade practice laws. In October 1998, the
arbitrators awarded the Trust damages of approximately $2,600,000 on its
claims and awarded approximately $400,000 to EUA for alleged unpaid
management services thereon. In November 1998, EUA made a payment of
$2,210,184 to the Trust to liquidate the claims. After deducting costs
associated with the arbitration proceeding, the Trust recognized income of
$1,265,122.
The arbitration panel also awarded the Trust its attorneys' fees and expenses
incurred in prosecuting the case, which the Trust computed at approximately
$997,000, and awarded EUA its attorneys' fees and expenses incurred in
prosecuting its counterclaim. The panel is expected to rule by the end of
April 1999 on objections raised by each party to the others' fees and
expenses and to make a final award. EUA has also refused to pay interest at
12% per year awarded by the panel on the Trust's award from September 1995 to
November 1998 (approximately $808,000) until a final ruling by the panel.
The Trust has brought a motion in the United States District Court for the
District of Massachusetts to confirm the award, which will await the final
ruling of the panel on the attorneys' fees and expenses. The Trust is not
accruing any potential recovery on fees, expenses and interest, pending a
final ruling or payment.
-F12-
<PAGE>
In the ordinary course of business, in late 1996 the Trust had discovered a
small number of overbillings at on-site cogeneration projects purchased from
EUA and had refunded the overbilled amounts to customers. In preparing for
the arbitration hearings against EUA in the second quarter of 1998, the Trust
made an intensive engineering and financial review of the on-site
cogeneration projects and discovered what appeared to be a pattern of
material overbillings of customers of a number of the on-site projects. The
overbillings were caused by the Trust's reliance on billing formulas and
practices used by EUA and EUA's transfer of false billing protocols to the
Trust was an element of the Trust's claim against EUA. The Trust has informed
affected customers of the overbillings and has offered or paid refunds
totaling over $271,000. It has also advised federal government authorities of
overbillings to federally supported entities that were included in the that
amount. Although the federal government has the right at any time to take
action adverse to the Trust if it sees fit, it has not done so to date.
Although there can be no assurance that adverse action will not be taken
against the Trust, the Trust believes that it is not probable that any such
adverse action will occur.
7. Administrative Proceeding at the Providence Project
In September 1998, the Region I office of the U.S. Environmental Protection
Agency ("EPA") filed an administrative proceeding against RPPP seeking to
recover civil penalties of up to $190,000 for alleged violations of
operational recordkeeping and training requirements at the Providence
Project. RPPPP answered and the matter has been referred to an alternate
dispute resolution procedure within the EPA. In the course of discussions
with the EPA and through the alternate dispute resolution procedure, the EPA
has offered to reduce the penalty to $88,750. Further, EPA is discussing with
RPPP a proposal to offset a portion of the penalty by crediting RPPP with
certain environmental audit and remediation expenditures, over and above
those required by law, that the Trust and other Ridgewood Power Trusts may
agree to make. RPPP expects to resolve this matter in the second quarter of
1999 and does not anticipate that it will have to make further material
capital expenditures to remedy the items identified by the EPA or that this
proceeding will have a material adverse impact on it. The Trust does not
anticipate that it will be liable for or will have to fund the costs of the
proceeding.
8. Subsequent Event - Purchase of Caterpillar Power Modules
On February 19, 1999, the Trust made a $590,200 deposit for seven Caterpillar
power modules that are expected to be delivered in June 1999. The seven power
modules have a total price of $2,360,803 and a total capacity of 7.8
megawatts. The Trust plans to rent the power modules to domestic and
international customers.
-F13-
<PAGE>
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, 1998 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 27th day of March, 1999, at Naples, Florida.
/s/Ralph O. Hellmold
Ralph O. Hellmold
<PAGE>
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, 1998 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 27th day of March, 1999, at Naples, Florida.
/s/Jonathan C. Kaledin
Jonathan C. Kaledin
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>This schedule contains summary financial information
extracted from the Registrant's audited financial statements for
the year ended December 31, 1998 and is qualified in its entirety
by reference to those financial statements.
</LEGEND>
<CIK> 0000917032
<NAME> RIDGEWOOD ELECTRIC POWER TRUST III
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,414,916
<SECURITIES> 21,714,050<F1>
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,543,346<F2>
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 24,257,396
<CURRENT-LIABILITIES> 474,362<F3>
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 23,783,034<F4>
<TOTAL-LIABILITY-AND-EQUITY> 24,257,396
<SALES> 0
<TOTAL-REVENUES> 4,076,897
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 4,875,312<F5>
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (798,415)<F5>
<INCOME-TAX> 0
<INCOME-CONTINUING> (798,415)<F5>
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (798,415)<F5>
<EPS-PRIMARY> (2,038)
<EPS-DILUTED> (2,038)
<FN>
<F1>Investments in power project partnerships.
<F2>Includes $30,071 due from subsidiaries.
<F3>Includes $289,153 due to subsidiaries.
<F4>Represents Investor Shares of beneficial interest in Trust
with capital accounts of $23,876,239 less managing shareholder's
accumulated deficit of $93,205.
<F5>Includes writedowns of investments of $4,055,214.
</FN>
</TABLE>
