Item 1. Business. Forward-looking statement advisory
This Annual Report on Form 10-K, as with some other statements made by the Trust from time to time, has forward-looking statements. These statements discuss business trends and other matters relating to the Trust's future results and the business climate and are found, among other places, at Items 1(c)(3), 1(c)(4), 1(c)(6)(ii) and 7. In order to make these statements, the Trust has had to make assumptions as to the future. It has also had to make estimates in some cases about events that have already happened, and to rely on data that may be found to be inaccurate at a later time. Because these forward-looking statements are based on assumptions, estimates and changeable data, and because any attempt to predict the future is subject to other errors, what happens to the Trust in the future may be materially different from the Trust's statements here.
The Trust therefore warns readers of this document that they should not rely on these forward-looking statements without considering all of the things that could make them inaccurate. The Trust's other filings with the Securities and Exchange Commission and its Confidential Memorandum discuss many (but not all) of the risks and uncertainties that might affect these forward-looking statements.
Some of these are changes in political and economic conditions, federal or state regulatory structures, government taxation, spending and budgetary policies, government mandates, demand for electricity and thermal energy, the ability of customers to pay for energy received, supplies 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 IV, the Registrant hereunder (the "Trust"), was organized as a Delaware business trust on September 8, 1994 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 September 30, 1996. It raised approximately $47,680,000. Net of offering fees, commissions and expenses, the offering provided approximately $39,500,000 for investments in the development and acquisition of Independent Power Projects and operating expenses. The Trust has 943 holders of Investor Shares (the "Investors"). As described below in Item 1(c)(2), the Trust has invested approximately $27.9 million of its funds to the acquisition of interests in four Independent Power Projects and in capital equipment and is actively seeking additional Projects for investment.
Ridgewood Power Corporation (the "Managing Shareholder"), a Delaware corporation, is the Managing Shareholder of the Trust and as such has direct and exclusive discretion in the 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 Corporate Trustee acts on the instructions of the Managing Shareholder and is not authorized to take independent discretionary action on behalf of the Trust. 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 Investment Company Act of 1940, as amended (the "1940 Act"). 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 January 24, 1995, 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 March 24, 1995 the election and registration became effective.
As described below at Item 1(c)(6)(iii) - Business - Narrative Description of Business - Regulatory Matters - the 1940 Act, effective October 3, 1996, the Trust, with the approval of the Investors, withdrew its election to be a business development company so that it could make investments together with other programs sponsored by the Managing Shareholder without requesting exemptive relief from the Securities and Exchange Commission. The Trust covenanted to comply with most of the substantive restrictions on business development companies, other than certain transactions with affiliated persons, as described there.
Unlike three prior investment programs that the Managing Shareholder has sponsored in the independent power industry, the Trust consolidates its subsidiaries' financial statements with its own for purposes of this Annual Report on Form 10-K.
(b) Financial Information about Industry Segments.
The Trust has been organized to operate in only one industry segment: 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 that might provide heat energy as well to users.
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). The Providence and Maine Hydro Projects are Qualifying Facilities.
(2) The Trust's Investments.
(i) Providence Project. The Trust and Ridgewood Electric Power Trust III, a similar investment program sponsored by the Managing Shareholder ("Ridgewood Power III"), acquired in April 1996 all of the equity interest in the Providence State Landfill Power Plant, located near Providence, Rhode Island. Ridgewood Power III invested $7.1 million in the Project and the Trust invested $12.9 million, which was the remainder of the $20 million investment in the Project. The acquisition cost of the Project 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 cash 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.
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 from 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 original 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, sales have approached 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 12%, 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. Net earnings from the Project (less the minority interest of Ridgewood Power III) for 1997 totalled $964,000, up from $562,000 for the period April 16-December 31, 1996.
(ii) California Pumping Project
On December 31, 1995, the Trust purchased a package of 11 irrigation service engines which have an aggregate power output equivalent to 1.2 Megawatts (the "California Pumping Project") located in Ventura County, California, for a cash purchase price of approximately $354,000. The Trust purchased the Project from Ridgewood Power III for the same price paid by Ridgewood Power III for the assets to the unaffiliated seller. In 1996, the Trust bought 9 additional engines with a rated equivalent capacity of 1.2 Megawatts from unaffiliated sellers at a price of $344,000. The total investment in the Project at December 31, 1997 was $648,000.
The California Pumping Project has been operating since 1992 and uses natural-gas-fired reciprocating engines to provide power for irrigation wells which furnish water for orchards of lemon and other citrus trees. The power is purchased by local farmers and farmers' co-operatives at a price which represents a discount from the equivalent price the customers would have paid to purchase electric power. The California Pumping Project will provide power equivalent to approximately 2.4 megawatts.
The Trust has entered into a management contract with the prior operator of the Project based on the amount of pumping power provided by each engine, computed on the basis of the equivalent amount of kilowatt-hours of electricity that would have been needed to provide that amount of pumping power. Until January 1998, the Trust received all cash flow from the engines up to $.02 per equivalent kilowatt-hour for the first 3,000 kilowatt-hours per year, and $.01 per additional kilowatt-hour in that year. The operator, which is responsible for all operating costs, received the remainder. Beginning in January 1998, the Trust will receive one-half of revenues after deduction of a 6/10 cent per equivalent kilowatt-hour maintenance fee and costs of fuel for the engines. If net revenues are less than 1.5 cents per equivalent kilowatt-hour, the operator will receive 3/4 cent per equivalent kilowatt-hour (or all the net revenues if they are less than 3/4 cent) and the Trust will receive any remainder.
Ridgewood Electric Power Trust II, a prior investment program sponsored by the Managing Shareholder ("Ridgewood Power II"), owns a package of similar engines located on different sites and operated under identical terms by the same operator. The engines operate independently of each other and revenues and expenses for each Trust are segregated from those of the other.
(iii) Maine Hydro Projects
On December 23, 1996, the Trust purchased from Consolidated Hydro, Inc. a 50% interest in 14 small hydroelectric projects located in Maine. In order to increase diversification of the Trust's investments, the remaining 50% interest was purchased by Ridgewood Electric Power Trust V ("Ridgewood Power V"), a similar investment program organized in 1996 by the Managing Shareholder. Each Trust paid approximately $6,700,000 for its interest The jointly owned partnership that acquired the Project also assumed a lease obligation in the amount of $1,005,000. The partnership was credited with all income relating to the projects from July 1, 1996 to the closing date and the seller was credited with interest on the purchase price at annual rates of 6% to 8.5% during that period.
The 14 hydroelectric projects have an aggregate rated capacity of 11.3 megawatts. All electricity generated by the projects over and above their own requirements is sold to either Central Maine Power Company or Bangor Hydro Company under long- term power purchase contracts. Eleven of the contracts expire at the end of 2008 and the remaining three expire in 2007, 2014 and 2017.
The Trust's net equity in the income of the Maine Hydro Projects for 1997 was $521,000.
The Trusts have entered into a five year operating and maintenance agreement with Consolidated Hydro, Inc. under which a subsidiary of Consolidated Hydro will manage and administer the projects for a fixed annual fee of $307,500 (adjusted upwards for inflation), plus an annual incentive fee equal to 50% of the excess of aggregate net cash flow over a target amount of $1.875 million per year. The maximum incentive fee is $112,500 per year; to the extent the annual net cash flow exceeds $2.1 million, the excess will be carried forward to future years; to the extent that the annual net cash flow is less than $1.875 million, the deficit will be carried forward to future years. In addition, the operator will be reimbursed for certain operating and maintenance expenses. In 1997, the operator was paid a total of $429,000 for operating and incentive fees.
(iv) Maine Biomass Projects
On July 1, 1997, the Trust and Ridgewood Power V purchased a preferred membership interest in Indeck Maine Energy, L.L.C., an Illinois limited liability company ("Indeck Maine") that owns two electric power generating stations fueled by waste wood at West Enfield and at Jonesboro, Maine. The Trust and Ridgewood Power V purchased the interest through a limited liability company owned equally by each. The Trust's share of the purchase price was $7,298,000 and Ridgewood Power V provided an equal amount of the total purchase price.
The original members of Indeck Maine, who continue as equity members subject to the preferred membership interest, are seven individuals. In connection with the transaction, Indeck Maine distributed $9,143,000 of the purchase price to its original members. The preferred membership interest entitles the Trust and Ridgewood Power V to receive all net cash flow from operations each year until they receive a 18% annual cumulative return on their capital contributions to Indeck Maine. Any additional net operating cash flow in that year is paid to the remaining Indeck Maine members until the total paid to them equals the amount of the 18% preferred return for that year, without cumulation. Any remaining net operating cash flow for the year is payable 25% to the Trust and Ridgewood Power V together and 75% to the other Indeck Maine members unless the Trust and Ridgewood Power V recover their capital contributions from proceeds of a capital event. Thereafter, these percentages change to 50% each. All non-operating cash flow, such as proceeds of capital events, is divided equally between (a) the Trust and Ridgewood Power V and (b) the remaining Indeck Maine members.
Under its amended operating agreement, the original Indeck Maine members designate a majority of the managers of Indeck Maine and thus have management control, although approval of the Trust and Ridgewood Power V jointly is required for many significant decisions. If the Trust and Ridgewood Power V do not receive annual distributions at least equal to the 18% preferred return requirement or if Indeck Maine after a cure period fails to make distributions to them in accordance with the operating agreement, they have the right to designate a majority of the managers of Indeck Maine. The other Indeck Maine members may regain control if Indeck Maine satisfies the cumulative preferred return requirement within the next five calendar quarters. Indeck Operations, Inc., an affiliate of the original Indeck Maine members, currently manages the plant under a renewable agreement and is reimbursed for its costs. In addition, the three managers nominated by the original Indeck Maine members will receive aggregate annual fees of $300,000 and certain other fees are payable to Indeck Maine affiliates. The management agreement may be terminated on notice if the Trust and Ridgewood Power V obtain the right to designate a majority of the managers of Indeck Maine. The Trust anticipates that it and Ridgewood Power V will have the right to do so and to terminate the management agreement at the end of 1998, at which time it anticipates that RPMC will assume management of the projects. Each of the projects has a 24.5 megawatt rated capacity and uses steam turbines to generate electricity. The fuel is waste wood chips, bark, brush and similar biomass. Both projects are Qualifying Facilities.
The Indeck Maine projects operated for five months in 1997 selling electricity to participants in the New England Power Pool or to Bangor Hydroelectric Company on monthly contracts. The contracts were not renewed in 1998 and the projects were shut down in January 1998. Later in January 1998, during a severe ice storm, local officials requested an emergency restart of the projects. A dispute ensued between Bangor Hydroelectric Company and the Indeck Maine projects, caused by the high costs of restarting the plants on an emergency basis. Bangor Hydroelectric Company accused the projects of price-gouging in the emergency. Indeck Maine responded that Bangor Hydroelectric was distorting the facts to divert attention from other matters and that it would sell the emergency energy at cost. The matter is being informally reviewed by the Maine Attorney General's office, and no action has been taken to date. The Trust does not anticipate any material adverse effect from the dispute.
The cost to the owners of Indeck Maine for maintaining the facilities in operable condition and for fixed costs such as taxes and insurance is approximately $100,000 per month for both projects, which is being funded 25% by the Trust, 25% by Ridgewood Power V and 50% by the other Indeck Maine owners.
Beginning in April 1998, ISO-New England, Inc. (the "ISO"), an independent, non-profit organization in which Indeck Maine and substantially all generators and distribution utilities in New England are members, began an auction process as part of the deregulation of the New England electricity market. See (4) -- Trends in the Electric Utility and Independent Power Industries, for an explanation of the deregulatory process. The first commodity to be auctioned is "installed capability," a measurement of the rated ability of a generating plant to create electric power. Plants are credited with installed capability whether or not they run. For an additional discussion of installed capability and other concepts related to electricity pricing, see (3) - Plant Operation, below. Beginning April 1, 1998 each distribution utility that is a member of the ISO must own or purchase installed capability on a monthly basis that at least equals its expected load for the month (the maximum amount of power that its customers may demand) plus mandated reserves. Generating facilities may enter into contracts to sell installed capability or may auction it through the ISO.
The Maine Biomass plants have sold installed capability for April 1998 under contract to a distribution utility and expect to sell installed capability for the rest of 1998 either through short or long-term contracts or the auction process. Later in 1998 and 1999, the ISO will add additional commodities to the auction process, such as operating capability (the amount of power that can be delivered by generating plants that are operating or can be placed in operation on short notice) and energy (the actual energy delivered by operating plants). The Trust hopes that the prices for energy or operating capacity during the remainder of 1998, either through the auction process or through short-term or long-term contracts, will be sufficient to allow the plants to be restarted and operate.
The Trust believes that as utilities sell off generating assets, as state regulators require purchase of "renewable power" as described further at (4)(ii) - Trends in the Electric Utility and Independent Power Industries - Maine Biomass and "Merchant Power Plants" - Renewable Power and as the market in New England for generation becomes more competitive, the Maine Biomass ant Power Plants" - Renewable Power and as the market in New England for generation becomes more competitive, the Maine Biomass projects will be able to sell their future output profitably. However, there can be no assurance that they can do so consistently and earn a satisfactory return in the rapidly deregulating electricity industry. See generally (4) - Trends in the Electric Utility and Independent Power Industries for further discussion of the opportunities and problems related to the deregulated industry.
Neither Indeck Maine, its original members nor Indeck Operations, Inc. is affiliated with or has any material relationship with the Trust, Ridgewood Power V, their Managing Shareholder or their affiliates, directors, officers or associates of their directors and officers. The sales price and the terms of the acquisition were determined in arm's length negotiations between the Managing Shareholder of the Trust and representatives of the original Indeck Maine members. The source of the Trust's funds was proceeds of its private placement offering of Investor Shares.
(v) Proposed Investments.
In January 1998 the Managing Shareholder executed a letter of intent under which the Trust and Ridgewood Power V would invest up to $32.3 million collectively in 17 small landfill-gas fueled generating plants being developed by NEO Corporation, a subsidiary of NRG Energy, Inc., of Minneapolis, Minnesota. The plants are to be located at public landfills in California, Washington, New Jersey, New York, Massachusetts, Virginia and Florida and range in capacity from .9 Megawatt to 20 Megawatts. As currently contemplated, the Trust would invest up to $9 million of its funds in a limited liability company and Ridgewood Power V would invest the remaining $23 million. As projects were completed and received long-term debt financing from a bank financing source, the limited liability company would advance equity funds to the operating company and would receive a preferred right to distributions from the operating company and approximately a 50% interest on dissolution. The funds invested by the limited liability company would come first from the Trust's contribution and then from Ridgewood Power V's contribution. Unexpended funds would be returned to the Trust providing them. At completion of the investment process (expected by November 1998) the Trust and Ridgewood Power V would have undivided interests in each plant in proportion to their net capital contributions to the limited liability company.
The Trust is actively seeking additional Projects for investment, either by itself or in conjunction with other programs sponsored by the Managing Shareholder if such programs are authorized to do so.
If the Trust and another program with similar investment objectives have funds available at the same time for investment in the same or similar Projects, and a conflict of interest thus arises as to which program will make the investment, the Managing Shareholder will review the investment portfolio of each program. It will make the investment decision on the basis of such factors, among others, as the effects of the investment on the diversification of each program's portfolio, potential alternative investments, the effects investment by either program would have on the program's risk-return profile, the estimated tax effects of the investment on each program, the amount of funds available and the length of time those funds have been available for investment. If more than one program has funds available for investment and the factors discussed above and other considerations indicate that the Project has approximately equal benefit for each Program, the Managing Shareholder will generally allocate the opportunity to each program in order of its organization date. In that event, the Managing Shareholder will cause the oldest program to commit all of its reasonably available funds to that opportunity; if those funds are insufficient, the remainder of the opportunity will be offered to each successive program with reasonably available funds until the investment opportunity is exhausted. A similar process would be followed for divestiture opportunities or competitive electricity sales.
An additional conflict could arise where the entities make investments in different forms, which would be the case where one entity's investment took the form of equity and the other's took the form of debt. Although it anticipates that this situation is unlikely to arise, the Managing Shareholder, if practicable, would attempt to resolve any conflict of this type by reference to the terms negotiated by other debt or equity participants in the relevant Project or similar Projects. Although the Managing Shareholder believes these practices may reduce potential conflicts of interest of this type, there can be no assurance that the interests of the entities will not diverge.
(3) Project Operation.
The Providence and Maine Hydro Projects are Qualifying Facilities under PURPA and have entered into long-term power purchase agreements ("Power Contracts") with their local distribution utilities. Under the Power Contracts for the Providence and Maine Hydro Projects, the local utilities are obligated to purchase the entire output of the Projects (up to rated levels)at formula prices. No separate payments are made for capacity or capability and all payments under the Power Contracts are made for energy supplied.
The utility purchaser at the Providence Project, New England Power Company, pays 3.0 cents per kilowatt-hour for all power provided, adjusted for inflation based on changes in the consumer price index since 1989. In addition to that base amount, it pays a flat additional 3.5 cents per kilowatt-hour for peak period power and 1.5 cents for non-peak power. Additional adjustments are made to reduce payments in later years so as to levelize total amounts paid by the utility.
The Maine Hydro Projects are licensed or operated as "run- of-river" facilities, which means that the amount of water passing through the turbines is directly dependent upon the fluctuating level of flow of the river or stream. The Projects have a very limited ability to store water during high flows for use at low flow periods. As a result, these Projects are unable to earn capacity payments and are often unable to produce high output in the peak summer and winter months when spot electricity rates are highest. Instead, they produce electric energy and sell it as generated at the fixed rates provided in the Power Contracts.
The Maine Biomass Projects do not have long-term Power Contracts and will be selling their output competitively.
The Trust's decisions to purchase Projects in New England have been driven in part by the relatively high prices paid for energy in the region and a shortage of generating capacity caused in large part by the forced shutdown of four large nuclear power plants owned by Northeast Utilities, Inc. and other utilities for regulatory and safety violations. See the discussion at (4) - Trends in the Electric Utility and Independent Power Industries and (5) - Competition below for information regarding proposed capacity additions and cost factors that may offset that shortage.
Customers of Projects that accounted for more than 10% of annual revenues from operating sources to the Trust in each of the last two fiscal years are:
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 the Providence Project. The Managing Shareholder has organized Ridgewood Power Management Corporation ("RPMC") to provide operating management for facilities operated by its investment programs. See Item 10 - Directors and Executive Officers of the Registrant for further information regarding the Operation Agreement and RPMC. The Maine Hydro Projects are managed by their former owner, Consolidated Hydro, Inc., which owns other hydroelectric facilities in the region, the California Pumping Project is managed by H&P, Inc., its former developer and the Maine Biomass Plants are currently managed by their former owner, Indeck Maine.
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 case of the Maine Biomass Projects, via utility lines to the ISO's transmission facilities.
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. As described above, peak periods in New England generally are limited to daytime and evening hours in the summer months (with a smaller peak in Maine for light and heating during the winter) and power prices are significantly higher during those periods.
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 is usually the most significant factor in determining working capital needs.
The Providence and Maine Hydro Projects owned by the Trust use landfill gas or hydroelectric energy and are not subject to fuel price changes or supply interruptions. Because the Maine Hydro Projects are "run-of-river" hydroelectric plants, their output is dependent upon rainfall and snowfall in the areas above the dams and output has varied in the range of 30% over or 25% below the average output from 1987 through 1997. Output is generally lowest in the summer months and in the winter and highest in the spring and fall.
The Maine Biomass Projects burn wood waste, including brush and chips from woodcutting or processing of raw wood at paper mills or sawmills. The price of wood waste fluctuates and is a primary determinant of whether the Projects can run profitably or not. The major causes of the fluctuation are changes in woodcutting or wood processing volumes caused by general economic conditions, increases in the use of wood waste by paper mills for their own cogeneration plants, changes in demand from competing generating plants using wood waste or paper mill refuse and weather conditions. The cost of wood waste is currently significantly in excess of that anticipated at the time the Maine Biomass Projects were purchased.
The California Pumping Project's engines burn natural gas. 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 may directly inhibit the development of Projects because of the anticipated effects on Project profitability and may deter lenders to Projects or result in higher costs of financing.
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.
Of the 14 Maine Hydro Projects, six operate under existing hydroelectric project licenses from the Federal Energy Regulatory Commission ("FERC") and two have license applications pending. Changes to the six other, unlicensed Projects (which are currently exempt from licensing) may trigger a requirement for FERC licensing. FERC licensing requirements have become progressively more stringent and often require that output of a Project that is being licensed or relicensed be restricted in order to allow a more natural flow of water, that archaeological and historical surveys be undertaken, that public access to waterways be provided (sometimes requiring purchase of property rights by the hydroelectric licensee) and that various site improvements be made. These requirements can materially impair a project's profitability. See Item 1(c)(6) - Business - Narrative Description of Business - Regulatory Matters.
(4) Trends in the Electric Utility and Independent Power Industries
	(i) Qualifying Facilities with long-term Power Contracts
	The Trust is somewhat insulated from recent deregulatory trends in the electric industry because the Providence and Maine Hydro 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 state 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 (including those in Maine) 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.
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.
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. 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 would entertain such an offer.
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 stay out of bankruptcy.
After the Power Contracts for the Providence and Maine Hydro Projects expire at varying times from 2008 to 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. 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. Both it and the Maine Hydro Projects may have diseconomies of small scale. The Trust is unable to anticipate whether the Projects would have cost disadvantages or advantages after their Power Contracts expire. It is thus impossible to predict the profitability of those Projects after termination of the Power Contracts.
	(ii) Maine Biomass and "Merchant Power Plants"
	The Maine Biomass Projects do not have long-term Power Contracts and are exposed to the newly-deregulating market for electricity generation. Those Projects and other similar plants without long-term Power Contracts that the Trust may acquire are sometimes described as "merchant power plants" because they sell their output on the open market. As a consequence of federal and state moves to deregulate large areas of the electric power industry and the existence, spurred by PURPA, of private competitors to electric utilities in the market for generating electricity, a number of interrelated trends are occurring that will affect merchant power plants.
Continued Deregulation of the Generating Market
	The Comprehensive Energy Policy Act of 1992 (the "1992 Energy Act") encourages electric utilities to expand their wholesale generating capacity by removing some, but not all, of the limitations on their ownership of new generating facilities that qualify as "exempt wholesale generators" ("EWG's") and on their ability to participate in merchant power plants. Many state electric utility regulators are considering plans to further encourage investment in wholesale generators and to facilitate utility decisions to spin off or divest generating capacity from the transmission or distribution businesses of the utilities. As a result, merchant power plants in the future will face competition not only from other independent power plants seeking to sell electricity on a wholesale basis but also from EWG's, electric utilities with excess capacity and independent generators spun off or otherwise separated from their parent utilities.
Wholesale-level Access to Transmission Capacity
	Without access to transmission capacity, an independent power plant or other wholesale generator can only sell to the local electric utility or to a facility on which it is located (or, in some states, which adjoins its location). The most important changes occurring in the electric power industry are the efforts of FERC to compel utilities and power pools to provide nationwide access to transmission facilities to all wholesale power generators. When combined with the increased competition in the generating area, this is likely to create an electricity supply market that may profoundly change the operations of electric utilities, consumers and independent power plants.
	The 1992 Energy Act empowered FERC to require electric utilities and power pools to transmit electric power generated by other wholesale generators to wholesale customers. This process is referred to as "wheeling" the electric power. Essentially, the generator contributes power to a utility or power pool and is credited with that contribution, and the utility or power pool serving the wholesale customer makes available that amount of electric power to the customer and debits the generator. Wheeling is effected between power pools on a similar basis.
	On April 24, 1996 the Federal Energy Regulatory Commission adopted Order 888, which requires electric utilities and power pools to provide wholesale transmission facilities and information to all power producers on the same terms, and endorses the recovery by utilities of uneconomic capital costs from wholesale customers who change suppliers. The utilities would also be required to furnish ancillary services, such as scheduling, load dispatch, and system protection, as needed. These rights, however, would apply only to sales of new electric power over and above existing utility supply arrangements. Non- utility wholesale deliveries of electricity have grown vigorously and according to the federal government have grown at the rate of 21% per year in the ten years from 1986 to 1996.
	The Maine Biomass Projects are dependent on wheeling power in order to sell their capacity or energy to purchasers other than Bangor Hydroelectric Company. Currently, they access the ISO's facilities through transmission lines owned by Bangor Hydroelectric Company and would pay material tariff charges for transmitting energy to the ISO's lines. Indeck Maine and the Trust are pursuing regulatory and engineering measures to either have the Bangor Hydroelectric lines reclassified as ISO facilities (which would greatly reduce transmission costs) or to connect directly to ISO facilities.
	Order 888 takes no action to modify existing Power Contracts. The order intends to create a competitive national market in electricity generation and thus may create additional pressure on electric utilities to seek changes to long-term power purchase contracts, as described further below. State public utility regulatory agencies must also review and approve certain aspects of wholesale power deregulation, and those agencies are currently holding proceedings and making determinations.
	In addition to the FERC order or other Congressional or regulatory actions that may result in freer access to transmission capacity, agreements with Canada, and to a lesser extent with Mexico, are leading toward access for those countries' generators to U.S. markets. In particular, certain Canadian suppliers, such as HydroQuebec (the Quebec provincial utility) are already offering substantial amounts of electricity in New England, and more may be offered if sufficient transmission capacity can be approved and built. These agreements may also afford access to those countries' markets in the future for independent power plants. As a result, there is the possibility that a North American wholesale market will develop for electricity, with additional competitive pressures on U.S. generators.
Retail-level Competition
	An even more radical prospect for the electric power industry is retail-level competition, in which generators would be allowed to sell directly to customers by using (and paying a fee for) the local utility's distribution facilities. Retail- level competition presupposes the ability to wheel power in the appropriate amounts at economic costs from the generating Project to the electric utility whose wires link to the retail customer (typically a large industrial, commercial or governmental unit) and the ability to use the local utility's facilities to deliver the electricity to the customer. In addition to the business and regulatory issues arising from wholesale wheeling, retail-level competition raises fundamental concerns as to the ability of utilities to recover stranded costs at the generating and distribution levels, the possibility that smaller customers will have less ability to demand pricing concessions, incentives for governmental agencies to act as intermediaries for consumers and the functions of state-level regulatory agencies in a price- competitive environment which may be inconsistent with their traditional price-setting and service-prescribing roles.
	Although retail deregulation is being implemented currently on a state-by-state basis, there are some common elements which are expected to be included in the Maine and Massachusetts deregulation plans. First, most deregulating states will require that local utilities will be the "suppliers of last resort," which are required to serve any customers in their existing territories who do not purchase generated electricity from another source and which are required to obtain adequate generating capacity to meet those needs. Second, most deregulating states are requiring that utilities and other suppliers of electricity work through "independent system operators" such as the ISO, which coordinate purchase, transmission and sale of electricity between generators and distribution utilities. Independent system operators will have significant responsibility for supply reliability.
	Third, most deregulating states are requiring that utilities be compensated for stranded costs (which include long-term Power Contracts with Independent Power Projects that are above current and anticipated market prices) for a transition period. This is typically done by imposing a transition fee or surcharge on rates that is paid to the utility. 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. Fourth, many states are requiring local utilities to divest a large portion or all of their generating assets or to sell their rights under long-term Power Contracts. The states have cited concerns such as the anti- competitive effects of allowing the utilities, which retain a monopoly over the wires that take electricity the last stages to the customer, to own generating assets. Further, the sale of assets (or above-market Power Contracts) sets a market price for those assets and allows a somewhat objective computation of the stranded costs related to those assets or contracts. For example, the true stranded cost of a nuclear plant is approximately the difference between the value assigned to it under state regulation and the price someone will pay for it at auction.
	Fifth, utilities having stranded costs are expected to mitigate those costs by buying out contracts or selling costly assets. Finally, many states are attempting to protect generators who use "renewable fuels" or that are considered to have environmental or social benefits. As discussed below, Maine and Massachusetts are doing so.
Price and Cost Pressures
	The pricing pressures that retail and wholesale deregulation are bringing are expected to decrease the marginal cost of electricity. Competition will force utilities and generators to reduce overhead and administrative costs, to trim operation and maintenance costs and to more efficiently buy and use fuel. Further, wholesale and retail deregulation and new generating technologies discussed below are expected to significantly reduce capital costs. For example, electric utilities currently maintain large amounts of generating capacity in reserve to meet peak loads (for example, to serve customers during a heat wave in July). According to the federal government, competition may lead to pricing strategies that reduce these peak loads. Competition may also force utilities to stop maintaining high-cost reserve capacity and to take greater risks. Finally, the widening wholesale market for electricity may increase efficiency by allowing utilities and power consumers to obtain distant, lower- cost capacity for reserve purposes rather than maintain local, higher cost, underutilized reserve capacity. For these and other reasons, the federal government currently estimates that national average electricity rates in real terms (adjusted for inflation) will decline to about 6.3 cents per kilowatt-hour in 2015 from the 1996 average level of 7.1 cents per kilowatt-hour.
	As these trends continue, high-cost generators will be disadvantaged and may fail. The Trust's small-scale generating plants have tended to have higher per-kilowatt hour costs (except for fuel) than new, large scale generating plants. The fuel cost advantages, if any, of landfill gas, hydroelectricity or waste biomass are thus critical to the competitiveness of the Trust's merchant power plants.
New Generating Technologies and New Industry Participants
	Recent improvements in turbine technology, coupled with what is seen as the ample supply and relative cheapness of natural gas, have made gas turbines the favored technology for new electric generating plants. The federal government estimates that 80% of the new electric generating capacity to be added from 1995 to 2015 will be fueled by natural gas and that the amount of generation fueled by natural gas will increase from the current 10% to 29%. According to the federal government, new gas turbines only need 15 days per year of maintenance, on the average, compared with 30 days a year for steam turbines. Although gas turbines historically have been used to meet peak demand rather than baseload demand, new "combined cycle" units (which use heat from the turbine's exhaust to drive a second steam or gas turbine) have thermal efficiencies approaching 60% (60% of the theoretical maximum heat from the burning gas is converted to electricity) and can be used as baseload units. In contrast, steam turbines fired by coal have efficiencies in the 36% range and have operating and maintenance costs higher than those of combined cycle plants. Further, natural gas-fired turbines emit relatively low levels of sulfur dioxide, particulates and complex carbon compounds and thus may have lower environmental compliance costs than coal-fired or oil-fired plants. The federal government estimates that combined cycle gas turbine plants alone will account from 96,000 to 143,000 Megawatts of the 319,000 Megawatts of additional capacity to be added in the next 17 years.
	The new emphasis on natural gas-fired generation is causing large natural gas transmission or brokering companies to enter the electricity generation market rapidly. They have access to large volumes of gas and have the ability to raise large amounts of capital. Accordingly, most new investment in combined cycle gas Projects and other large-scale gas turbine Projects is being made by these natural gas/energy companies or by large utilities that are entering the competitive generation industry.
	A number of large participants in the independent generating industry have announced their intentions to build large gas turbine merchant power plants in Connecticut, Massachusetts and Maine in sizes from 250 to 750 Megawatts. The capacity of the proposed plants exceeds one-half of the total deficit in capacity caused by the shutdown of the Northeast Utilities nuclear power plants. If all or many of the announced plants were built, there might be a material increase in low-cost generation capacity in the New England area. There have also been reports, especially from the northeastern states, that large non-utility generating companies and utilities entering the competitive generating market outside their existing service territories are buying large numbers of older plants from local utilities with the intention of replacing them on site with new, large, natural gas- fueled plants. It is unclear whether many of the announced merchant power plants will actually be built, given the uncertainties of the market for electricity and the possibility that there may be insufficient gas pipeline capacity or supplies to fuel all of the recently announced plants.
	Many companies, including affiliates of fuel suppliers and utilities, have applied to FERC to act as electric power marketers, because they anticipate that if wholesale wheeling becomes significant there will be strong demand for brokers or market makers in electric power. It is uncertain whether power marketers will become significant factors in the electric power market. A related development is the creation of derivative contracts for hedging of and speculation in electricity supplies, which may offer generators, utilities and large industrial or commercial consumers the ability to reduce the volatility of competitive prices. To date, the effects of derivative contracts on the market for electricity in the Northeast have not been material.
Renewable Power
	The pressures of competition are expected to harm the "renewable power" segment of the industry, which includes the Maine Biomass Projects. "Renewable power" is a catchphrase that includes Projects (such as solar, wind, small hydroelectric, biomass, geothermal and landfill-gas) that do not use fossil fuels or nuclear fuels. Renewable power plants typically have high capital costs and often have total costs that are well above current total costs for new gas-turbine production. Many observers believe that renewable power plants without existing Power Contracts (with the possible exception of biomass, hydroelectric and geothermal plants with very low or zero fuel costs) will be non-competitive in the new markets unless they are given governmental protection. A number of states, including Massachusetts and Maine, are requiring that retailers of electricity purchase a certain minimum amount of electricity (often between 5% to 30% of their total requirements) from renewable power sources. Unless there is a shortage of renewable capacity these state requirements may still not raise the price for renewable power high enough to make those Projects profitable.
Initial Effects of Trends
	With these conditions in mind, many observers see two primary strategies for non-utility generating plants to succeed in the United States: first, Projects that have existing, firm, long-term Power Contracts may do well so long as regulatory or legislative actions do not abrogate the contracts. Second, Projects that are low-cost producers of electricity, either from efficiencies or good management or as the result of successful cogeneration technologies, will have advantages in the market.
	Finally, there have been industry-wide moves toward consolidation of participants and divestiture of Projects. A number of utilities and equipment suppliers have proposed or entered into joint ventures to reduce risks and mobilize additional capital for the more competitive environment, while many electric utilities are in the process of combining, either as a means of reducing costs and capturing efficiencies, or as a means of increasing size as an organizational survival tactic. This consolidation tends to create additional competitive pressures in the electric power industry; however, this trend may also encourage the divestiture of smaller Projects or Projects that are deemed less central to the operations of large, consolidated businesses.
(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 plants. 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 plants. 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.
Please also review the discussion of changes in the industry above at (4) - Trends in the Electric Utility and Independent Power Industries.
(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 has agreed to comply with most of the requirements for "business development companies" under the 1940 Act, it also is contractually bound to comply with the requirements summarized below and others described at Exhibit 99 to this Annual Report on Form 10-K.
(i) Energy Regulation.
(A) PURPA. The enactment in 1978 of PURPA and the adoption of regulations thereunder by FERC provided incentives for the development of cogeneration facilities and small power production facilities meeting certain criteria. Qualifying Facilities under PURPA are generally exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended (the "Holding Company Act"), the Federal Power Act, as amended (the "FPA"), and, except under certain limited circumstances, state laws regarding rate or financial regulation. In order to be a Qualifying Facility, a cogeneration facility must (a) produce not only electricity but also a certain quantity of heat energy (such as steam) which is used for a purpose other than power generation, (b) meet certain energy efficiency standards when natural gas or oil is used as a fuel source and (c) not be controlled or more than 50% owned by an electric utility or electric utility holding company. Other types of Independent Power Projects, known as "small power production facilities," can be Qualifying Facilities if they meet regulations respecting maximum size (in certain cases), primary energy source and utility ownership. 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." 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 has 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 Providence and Maine Hydro Projects, which sells electricity to public utilities, are Qualifying Facilities. Maintaining the Qualified Facility status of an electric generating Project is of utmost importance to the Trust. Such status may be lost if a Project does not meet the operational or ownership requirements of PURPA. For small power production facilities such as the Providence and Maine Hydro Projects, the requirements are limited to maximum size, fuel use and ownership requirements that are currently unlikely to be violated. Cogeneration Projects that are Qualifying Facilities have more stringent requirements, such as minimum operating efficiency standards and minimum use of thermal energy by customers of a cogeneration Project.
The Trust endeavors to comply with applicable PURPA requirements and does not believe that either the Providence or Maine Hydro Projects are subject to any requirement that could jeopardize their statuses as Qualified Facilities. If the Trust were to invest in cogeneration Projects or certain other types of Qualifying Facilities, the PURPA standards could raise material compliance questions. In any event, 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. States may require utilities to institute monitoring systems under which electric utilities continuously meter a cogeneration Project's performance.
(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 failed to be a Qualifying Facility, it would have to comply with the FPA.
The FPA also provides that any hydroelectric facility that is located on a navigable stream or that affects public lands or water from a government dam may not be constructed or be operated without a license from FERC. Certain facilities that were operating before 1935 are exempt, if the waterway is non- navigable, or "grandfathered" and do not require licenses so long as the facilities are not modernized or otherwise materially altered. Licenses are granted for 30 to 50 year terms. All but two of the Maine Hydro Projects (with a rated capacity of 2.1 Megawatts) are subject to licensing. Of these 12 Projects, six (with a rated capacity of 6.4 Megawatts) have current licenses that expire from time to time between the years 2019 and 2037 and two (1.5 Megawatts) are currently in the licensing process, which can take from three to five years. The Trust believes that it will obtain licenses for each of these.
The proposed conditions for one pending license, at the Pittsfield Project on the Kennebec River (1.1 Megawatt), have been received. The Project will have to provide upstream fish passages no earlier than 2002 or, if later, the time when all dams further upstream have provided passage. The Project will also have to provide interim fish passage both upstream and downstream to the extent warranted by fishery studies; downstream mitigation measures may require the Project to restrict flow through its turbines during certain spring peak flow periods that could materially impair electricity output. Until studies are complete, it is not possible to estimate the effects of these conditions. Further, as noted above at Item 1(c)(3) - Business - Narrative Description of Business - Project Operation, the licenses may include other onerous conditions. The Trust is a member of the Kennebec Hydro Developers Group, which is negotiating with Maine agencies and environmental groups for watershed-wide studies and remediation programs.
Finally, six of the Maine Hydro Projects (with a rated capacity of 3.7 Megawatts) are exempt, grandfathered or are not otherwise subject to FERC licensing.
(D) Fuel Use Act. Projects that may be developed or acquired 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.
(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 and the exploitation of natural resource properties 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.
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 Maine, 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.
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, which in the case of the Maine Hydro Project are the responsibility of Consolidated Hydro, Inc. andin the case of the Maine Biomass Projects are the responsibility of Indeck Operations, Inc. The Trust will rely upon qualified environmental consultants and environmental counsel retained by it or by Project Sponsors 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 January 24, 1995, 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 March 24, 1995, the election and registration became effective. As a "business development company," the Trust was subject to prohibitions and restrictions on transactions between business development companies and their affiliates as defined in that act, and required that a majority of the board of the company be persons other than "interested persons" as defined in the act.
In particular, Commission approval was 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. The decision to co-invest in the Providence Project with Ridgewood Power III required approval of the Commission, which took more than eight months to obtain. The decision to co-invest in the Maine Hydro Projects with Ridgewood Power V would also have required approval of the Commission. There was no assurance that the necessary approval for that co-investment or others could be obtained.
Accordingly, in September 1996 the Managing Shareholder made a proxy solicitation requesting that the Investors in this Trust approve a proposal to end the Trust's status as a business development company. The purpose of the change was to allow the Trust to invest with other programs sponsored by the Managing Shareholder, with only the approval of the Trust's Independent Trustees. The Independent Trustees may not be "interested persons" (as defined by law) of the Trust or the Managing Shareholder. The Managing Shareholder advised the Investors of its belief that the change would end the delays and uncertainties of seeking approval from the Securities and Exchange Commission (the "Commission") for such transactions and therefore would increase opportunities for the Trust to diversify its investments and to increase the size and quality of the potential investment pool.
A majority in interest of the Investors approved an amendment to the Trust's Declaration of Trust by written consent. The amendment and the termination of business development company status became effective on October 3, 1996. In summary, the amendment authorized the Trust to withdraw the business development company election. It also defined a "Ridgewood Program Transaction" as a transaction with a Ridgewood Program, an entity controlled by a Ridgewood Program or Programs, or an entity in which a Ridgewood Program or Program has invested, that would otherwise be prohibited by the 1940 Act. The amendment stated that Ridgewood Program Transactions will not be subject to any provision of the 1940 Act or rules thereunder that would restrict the Trust or entities the Trust controls or has invested inform entering into Ridgewood Program Transactions. Instead, a Ridgewood Program Transaction must be approved either by the Managing Shareholder and a majority of the Independent Trustees, or by a majority of the Independent Trustees and a Majority of the Investors. No express standards for approval are specified, although the Managing Shareholder and the Independent Trustees are subject to the fiduciary requirements of Delaware law in making their decisions.
The amendment also required the Trust to continue to comply with all other requirements of the 1940 Act as if the Trust continued to be a business development company, except that the Trust would not be required to file any reports required of business development companies with the Commission or any other regulatory agency. With regard to the requirements that the Trust will continue to adhere to, the Trust will not be able to request exemptive relief from or to take actions requiring approval by the Commission, and the Commission will not have the ability to regulate the Trust under the 1940 Act, because the Trust will no longer be subject to the Commission's authority over business development companies.
The requirements of the 1940 Act that the Trust has promised to comply with, and those that it will not be required to follow, are listed in Exhibit 99 to this Annual Report on Form 10-K. Some of those requirements that are particularly relevant to the Trust's acquisitions of Projects are described below.
The Trust 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 Trust'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.
(d) Financial Information about Foreign and Domestic Operations and Export Sales.
The Trust has committed funds to Projects located in Rhode Island, Maine and California. Although the Managing Shareholder from time to time considers potential projects located outside the United States as potential investments for the Trust, the Trust has not acquired any Project located outside the United States.
(e) Employees.
The Trust has no employees. The persons described below at Item 10 - Directors and Executive Officers of the Registrant serve as executive officers of the Trust and have the duties and powers usually applicable to similar officers of a Delaware corporation in carrying out the Trust business.
Item 2.
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 or limited liability companies in which the Trust has an interest.
Approximate Square Ownership Ground Approximate Footage of Description Interests Lease Acreage Project of Projects Location in Land Expiration of Land (Actual Project or Projected)
Provi- Providence, dence Rhode Leased 2020 4 10,000 Landfill Island gas-fired generation facility Maine Hydro 14 sites in Maine Owned n/a 24 n/a Hydro- by joint electric venture* facilities
Pump Ser- Ventura License n/a n/a nominal Natural- vices County, gas-fueled California engines for irrigation pumps located on various farms Maine West Enfield Owned n/a less 18,000 Wood waste- Bio- and Jonesboro, by joint than fired genera- mass Maine venture 25 tion facility
*Joint venture equally owned by Trust and Ridgewood Power V. ** Joint venture owned by Indeck Maine former members, the Trust and Ridgewood Power V.
Item 3.
Item 3. Legal Proceedings.
There are no legal proceedings involving the Trust.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
The Trust has not submitted any matters to a vote of its security holders during the fourth quarter of 1997.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
(a) Market Information.
The Trust sold 476.8 Investor Shares of beneficial interest in the Trust in its private placement offering, which concluded on September 30, 1996. 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.
Investor Shares are restricted as to transferability under the Declaration, as well as under federal and state laws regulating securities. 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 four other investment programs sponsored by the Managing Shareholder (Ridgewood Electric Power Trusts I, II, IV and V) into a publicly traded entity. This would require the approval of the Investors in the Trust and the other programs after proxy solicitations complying with requirements of the Securities and Exchange Commission, compliance with the "rollup" rules of the Securities and Exchange Commission and other regulations, and a change in the federal income tax status of the Trust from a partnership (which is not subject to tax) to a corporation. The process of considering and effecting a combination, if the decision is made to do so, will be very lengthy. There is no assurance that the Managing Shareholder will recommend a combination, that the Investors of the Trust or other programs will approve it, that economic conditions or the business results of the participants will be favorable for a combination, that the combination will be effected or that the economic results of a combination, if effected, will be favorable to the Investors of the Trust or other programs.
(b) Holders
As of the date of this Form 10-K, there are 943 record holders of Investor Shares.
(c) Dividends
The Trust made distributions as follows in 1996 and 1997:
Year ended December 31, 1996 1997 Total distributions to Investors $1,659,928 $3,287,256 Distributions per Investor Share 3,481 6,894 Distributions to Managing Shareholder $16,767 $33,205
Distributions are made on a monthly basis. 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.
Subject to the other factors described in this Annual Report on Form 10-K, the Trust's goal is to provide Investors with annual distributions of net cash flow, as defined in the Declaration of Trust, of 14% of their Capital Contributions to the Trust. Occasionally, distributions may include funds derived from the release of cash from operating or debt service reserves. For purposes of generally accepted accounting principles, amounts of distributions in excess of accounting income may be considered to be capital in nature. Investors should be aware that the Trust is organized to return net cash flow rather than accounting income to Investors.
Item 6.
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.
* Restated on consolidation and equity method accounting principles. See Item 8 - Financial Statements and Supplementary Data.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
The following discussion and analysis should be read in conjunction with the Trust's financial statements and the notes thereto presented below. Dollar amounts in this discussion are generally rounded to the nearest $1,000, except per share data.
The consolidated financial statements include the accounts of the Trust and the limited partnerships owning the Providence and California Pumping Projects. The Trust uses the equity method of accounting for its investments in the Maine Hydro Projects and the Indeck Maine Biomass Projects, which are owned 50% by the Trust.
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 would permit utility customers to choose their electricity supplier in a competitive electricity market. The Providence and Maine Hydro 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. The Providence contract expires in 2020 and eleven of the Maine Hydro contracts expire in 2008 and the remaining three expire in 2004, 2014 and 2017. 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 sufficient to allow the Trust's Projects to operate profitably.
The Providence Project generates electricity from methane gas produced at the Central Landfill in Johnston, Rhode Island. Gas reserves are estimated to be in excess of the amount needed to generate the 12 Megawatt maximum under the Power Contract with New England Power Company. The price paid for the gas is a percentage (15% to 18%) of net revenue from power sales. Accordingly, the Providence Project is not affected by fuel cost price changes. The quality of the gas may vary from time to time. Poor quality gas may cause operating problems, down time and unplanned maintenance at the generating facility.
The Maine Hydro Projects have a limited ability to store water. Accordingly, the amount of revenue from electricity generation from these Projects is directly related to river water flows, which have fluctuated as much as 30% from the average over the past ten years. It is not possible to accurately predict revenues from the Maine Hydro Projects.
The Indeck Maine Biomass Projects sold electricity under short-term contracts during the months of July, August, October, November and December 1997. The Projects are currently shut down and will not be operated unless sales arrangements are obtained which would provide sufficient revenue to cover the Projects fixed and variable costs. Under current legislation, the electricity market in the State of Maine will be deregulated on March 1, 2000. Assuming biomass fuel can be purchased at reasonable prices in the year 2000 and beyond, the Indeck Maine Biomass Projects should be among the low cost producers of electricity in Maine and should be able to operate profitably in a competitive market environment. In the meantime, the Trust intends to keep the Projects in an idle mode until market conditions become more favorable, and the Project operator will seek short-term contracts to sell energy, installed capacity and operable capacity.
All Projects currently owned by the Trust produce electricity from renewable energy sources, such as landfill gas, hydropower and biomass ("Green Power"). In the State of Maine, as a condition of licensing, competitive generation providers and power marketers will have to demonstrate that at least 30% of their generation portfolio is Green Power sources. Other States in the New England Power Pool have or are expected to have similar Green Power licensing requirements, although the percentage of Green Power generation may differ from State to State. These Green Power licensing requirements should have a beneficial affect on the future profitability of the Trust's Projects.
Industry trends that may affect results of operations in 1998 and beyond are discussed above at Item 1(c)(4) - Business - Trends in the Electric Utility and Independent Power Industries.
Results of Operations The year ended December 31, 1997 compared to the year ended December 31, 1996.
In 1997, the Trust had a net loss of $403,000 as compared to net income of $73,000 in 1996. The 1997 results include earnings, net of minority interest, from the Providence Project of $964,000, equity in net income from the Maine Hydro Projects of $522,000, equity in the net loss of the Indeck Maine Biomass Projects of $680,000, and a minor contribution from the California Pumping Project of $10,000, interest income at the Trust level of $701,000, less Trust level expenses of $1,920,000. The Trust-level expenses include management fees, due diligence costs and general, and administrative and other expenses of $1,155,000, $669,000 and $96,000, respectively.
The Trust's only investments in the first nine months of 1996 were the Providence Project and the California Pumping Project and the Trust had significant investment fee expenses relating to the share offering. Net income for 1996 of $73,000, includes earnings, net of minority interest, from the Providence Project of $520,000, equity in net income from the Maine Hydro Projects of $99,000 a minor contribution to earnings from the California Pumping Project of $16,000, interest income at the Trust level of $1,004,000, less Trust-level expenses of $1,566,000. The Trust-level expenses include investment fees, management fees and general, and administrative and other expenses of $628,000, $845,000 and $93,000, respectively.
The year ended December 31, 1996 compared to the period from February 6, 1995 to December 31, 1995.
During 1995, the Trust had not yet acquired any interests in Projects and its activities were limited to organizational and offering efforts and to initial review of potential investments.
The Trust acquired the California Pumping Project at the end of 1995 and acquired its interest in the Providence Project on April 16, 1996. The Trust closed on the acquisition of its 50% in the Maine Hydro Projects on December 23, 1996. Accordingly, the 1995 results reflected only income earned on interim investments and Trust level administration expenses, while the 1996 results primarily reflect the results of the Providence Project for eight and one half months, and insignificant results from the California Pumping and Maine Hydro Projects.
Total 1996 revenues from the operating Projects were $4,349,000 and, after subtracting the $2,992,000 cost of sales, the 1996 gross profit from operations was $1,357,000 (a 31.2% operating margin). Other operating expenses, primarily reflecting the costs of administering the Trust and carrying on its investment program, totaled $1,994,000, as compared with $454,000 in 1995. The 339.2% increase was caused primarily by the $888,000 management fee (3% of net asset value) that was charged for the first time in 1996 and a $323,000 (105.9%) increase in the investment fee. The increase in the investment fee was directly proportional to the higher level of sales of Investor Shares in 1996. There was also a $303,000 (439.1%) increase in general and administrative expenses, reflecting the larger size of the Trust, costs of the Providence Project, the increase in the number of Investors and the costs of the proxy solicitation and related legal and accounting expenses. As a result of these factors, the operating loss for 1996 increased by only $183,000 (40.2%) from 1995 to 1996.
Non-operating income in 1996 (up $701,000, or 235.2% from 1995) was made up of interest income on the Trust's uninvested funds and a small amount of accrued income from the eight days on which the Trust owned a 50% interest in the Maine Hydro Projects. Against this in 1996 was subtracted $395,000 of interest expense on the debt encumbering the Providence Project.
Distributions from the Providence Project for 1996 were low (an 11.6% annualized return on investment) but within expectations. At the time the Project was purchased its profitability was low and the Trust planned to make major investments and changes to operations to increase efficiency. Electric output increased by an average of 33% in the eight and one half months in which RPMC has operated the Project in 1996.
Liquidity and Capital Resources
As of December 31, 1997, the Trust had raised approximately $40,507,000 of funds from its offering, net of offering fees and expenses. The Trust has invested $12,850,000 in the Providence Project, $7,080,000 in the Maine Hydro Projects, $7,298,000 in the Indeck Maine Biomass Project, $723,000 in the California Pumping Project and $455,000 in equipment.
At December 31, 1997, the Trust had $11,086,000 of cash available for investment in Projects. Cash flow provided by operation activities in 1997 amounted to $2,656,000. Distributions to shareholders of the Trust amounted to $3,320,000.
In 1997, capital expenditures amounted to $3,060,000, most of which related to the installation of a ninth generator engine at the Providence Project.
During the fourth quarter of 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 $1,150,000. 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 1997.
Other than investments of available cash in power generation Projects, obligations of the Trust are generally limited to payment of Project operating expenses, payment of a management fee to the Managing Shareholder, payments for certain accounting and legal services to third persons and distributions to shareholders 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 amount of working capital retained is further reduced by the availability of the line of credit facility.
The Trust anticipates that during 1998 its cash flow from operations, unexpended offering proceeds and line of credit facility will be adequate to fund its obligations.
Financial instruments
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. Currently the Trust invests only in bank obligations of Fleet Bank, N.A. Because the Trust invests only in short-term instruments for cash management, its exposure to interest rate changes is low.
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 on schedule.
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 1998 with ample time for implementation, testing and custom changes to some modifications made by Ridgewood to those programs.
The marketing and investor relations functions rely on custom-written software and the Managing Shareholder has hired a specialist to remedy that software. The year 2000 changes in the distribution system, which is used to send checks to Investors, have been completed and are being tested. The effort is on schedule to complete remediation and testing by December 31, 1998 and the Managing Shareholder believes that all material systems will be year 2000 compliant by early 1999. Some systems are being remediated using the "sliding window" technique. 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 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. Because the Trust and the Managing Shareholder are extremely small relative to the size of their material customers and 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.
Although the total cost associated with year 2000 compliance is not yet determined, the Trust does not believe that the costs will be material to its financial position or results of operation.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Report of Independent Accountants Balance Sheets at December 31, 1997 and 1996 Statement of Operations for Years Ended December 31, 1997 and 1996 and for Period from Commencement of Share Offering (February 6, 1995) through December 31, 1995 Statement of Changes in Shareholders' Equity for Years Ended December 31, 1997 and 1996 and for Period from Commencement of Share Offering through December 31, 1995 Statement of Cash Flows for Years Ended December 31, 1997 and 1996 and for Period from Commencement of Share Offering through December 31, 1995 Notes to Financial Statements to
Financial Statements for Maine Hydro Projects * Financial Statements for Maine Biomass Projects*
*To be supplied by amendment.
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 for operating companies, using consolidation and equity method accounting principles. This differs from the basis used by the three prior independent power programs sponsored by the Managing Shareholder, which present the Trust's investments in Projects on the estimated fair value method rather than the consolidation and equity accounting method. The financial statements for 1995 have been restated on the same basis used for 1996 and 1997. No material changes in net income or cash flow resulted..
Item 9.
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, Price Waterhouse LLP, have been engaged by the Trust.
PART III
Item 10.
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 Energy Holding Corporation ("Ridgewood Holding"), a Delaware corporation incorporated in April 1992, is the Corporate Trustee of the Trust.
(b) Managing Shareholder.
The Managing Shareholder 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.
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 III ("Ridgewood Power III"), 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. The business objectives of these four trusts are similar to those of the Trust.
The Managing Shareholder is an affiliate of Ridgewood Energy Corporation ("Ridgewood Energy"), which has organized and operated 46 limited partnership funds and one business trust over the last 16 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 Power Capital Corporation ("Ridgewood Capital"), organized in 1998, which assists in offerings made by the Managing Shareholder; and Ridgewood Power VI Corporation ("Power VI Corp."), which is a managing shareholder of the Growth Fund and RPMC. Each of these corporations is wholly owned by Robert E. Swanson, who is their sole director.
Robert E. Swanson has been the President, sole director and sole stockholder of the Managing Shareholder since its inception in February 1991. Set forth below is certain information concerning Mr. Swanson and other executive officers of the Managing Shareholder.
Robert E. Swanson, age 51, has also served as President of the Trust since its inception in November 1992 and as President of RPMC, Ridgewood Power I, Ridgewood Power II, Ridgewood Power III, 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. 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 39, has served as Executive Vice President of the Managing Shareholder, RPMC, Ridgewood Power I, the Trust, Ridgewood Power II, Ridgewood Power III, 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. 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 43, joined the Managing Shareholder in November 1994 as Senior Vice President and holds the same position with the Trust, RPMC and each of the other trusts sponsored by the Managing Shareholder. He became Chief Operating Officer of the Managing Shareholder, RPMC and the Ridgewood Power I through V trusts in October 1996, and is the Chief Operating Officer of the Growth Fund. 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 50, assumed the duties of Chief Financial Officer of the Managing Shareholder, the Trust, the other four trusts organized by the Managing Shareholder and RPMC in November 1996 under a consulting arrangement. He became a full-time officer of the Managing Shareholder and RPMC in April 1997 and is now also Chief Financial Officer of the Growth Fund.
Mr. Quinn has 29 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 45, has served as Vice President of the Managing Shareholder, RPMC, Ridgewood Capital, the Trust, Ridgewood Power I, Ridgewood Power II, Ridgewood Power III, 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, 1999 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, with the addition of Joseph A. Heyison, Senior Vice President and General Counsel. Mr. Heyison, age 43, joined RPMC in January 1996. He was previously of counsel to the law firm of De Forest & Duer, concentrating in corporate finance, banking, environmental law and securities. He is a member of the bars of New Jersey, New York and Ohio and was graduated from the University of Pennsylvania Law School in 1979.
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 John C. Belknap and Dr. Richard D. Propper. Mr. Belknap and Dr. Propper also serve as independent trustees for Ridgewood Power I and the Growth Fund. Set forth below is certain information concerning these individuals, who are not otherwise affiliated with the Trust, the Managing Shareholder or their directors, officers or agents.
John C. Belknap, age 49, has been chief financial officer of three national retail chains and their parent companies. Since July 1997, he has been Executive Vice President and Chief Financial Officer of Richfood Holdings, Inc., a Virginia-based food manufacturer. From December 1995 to June 1997 Mr. Belknap was Executive Vice President and Chief Financial Officer of OfficeMax, Inc., a national chain of office supply stores. From February 1994 to February 1995, Mr. Belknap was Executive Vice President and Chief Financial Officer of Zale Corporation, a 1,200 store jewelry retail chain. From January 1990 to January 1994 and from February 1995 to December 1995, Mr. Belknap was an independent financial consultant. From January 1989 through May 1993 he aso served as a director of and consultant to Finlay Enterprises, Inc., an operator of leased fine jewelry departments in major department stores nationwide. Prior to 1989, Mr. Belknap served as Chief Financial Officer of Seligman & Latz, Kay Corporation and its subsidiary, Kay Jewelers, Inc.
From January 1990 until February 1994, Mr. Belknap consulted in a variety of strategic corporate transactions, including mergers and acquisitions, divestitures and refinancing. One such transaction involved the recapitalization and change of control of Finlay in May 1993. From 1979 to 1985, Mr. Belknap served as Chief Financial Officer of Kay Corporation ("Kay"), the parent of Kay Jewelers, Inc. ("KJI"), a national chain of jewelry stores and leased jewelry departments in major department stores. He served as Chief Financial Officer of KJI from 1974 to 1979 and as its Assistant Controller from 1973 to 1974. Between 1970 and 1973, Mr. Belknap was a senior auditor at Arthur Young & Company (now Ernst & Young), a national accounting firm. Mr. Belknap earned BA and MBA degrees from Cornell University.
Dr. Richard D. Propper, age 47, graduated from McGill University in 1969 and received his medical degree from Stanford University in 1972. He completed his internship and residency in Pediatrics in 1974, and then attended Harvard University for post doctoral training in hematology/oncology. Upon the completion of such training, he joined the staff of the Harvard Medical School where he served as an assistant professor until 1983. In 1983, Dr. Propper left academic medicine to found Montgomery Medical Ventures, one of the largest medical technology venture capital firms in the United States. He served as managing general partner of Montgomery Medical Ventures until 1993.
Dr. Propper is currently a consultant to a variety of companies for medical matters, including international opportunities in medicine. In June 1996 Dr. Propper agreed to an order of the Commission that required him to make filings under Sections 13(d) and (g) and 16 of the 1934 Act and that imposed a civil penalty of $15,000. In entering into that agreement, Dr. Propper did not admit or deny any of the alleged failures to file recited in that order.
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 III and of an oil and gas business trust sponsored by Ridgewood 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. 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
All individuals subject to the requirements of Section 16(a) have complied with those reporting requirements during 1997.
(g) RPMC.
As discussed above at Item 1 - Business, RPMC assumed day- to-day management responsibility for the Providence Project. Like the Managing Shareholder, RPMC is wholly owned by Robert E. Swanson. It entered into an "Operation Agreement" with the Trust's subsidiary that owns the Project under which RPMC, under the supervision of the Managing Shareholder, will provide the management, purchasing, engineering, planning and administrative services for the Providence Project. RPMC will charge the Trust at its cost for these services and for the Trust's allocable amount of certain overhead items. RPMC shares space and facilities with the Managing Shareholder and its affiliates. To the extent that common expenses can be reasonably allocated to RPMC, the Managing Shareholder may, but is not required to, charge RPMC at cost for the allocated amounts and such allocated amounts will be borne by the Trust and other programs. Common expenses that are not so allocated will be borne by the Managing Shareholder.
Initially, the Managing Shareholder does not anticipate charging RPMC for the full amount of rent, utility supplies and office expenses allocable to RPMC. As a result, both initially and on an ongoing basis the Managing Shareholder believes that RPMC'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. RPMC 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 RPMC; and allocations will be made in a manner consistent with generally accepted accounting principles.
RPMC will not provide any services related to the administration of the Trust, such as investment, accounting, tax, investor communication or regulatory services, nor will it participate in identifying, acquiring or disposing of Projects. RPMC 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.
The Operation Agreement does not have a fixed term and is terminable by RPMC, by the Managing Shareholder or by vote of a majority in interest of Investors, on 60 days' prior notice. The Operation Agreement may be amended by agreement of the Managing Shareholder and RPMC; however, no amendment that materially increases the obligations of the Trust or that materially decreases the obligations of RPMC shall become effective until at least 45 days after notice of the amendment, together with the text thereof, has been given to all Investors.
The executive officers of RPMC 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), Ms. Olin (Vice President) and Mr. Heyison, (Senior Vice President and General Counsel). Douglas V. Liebschner, Vice President - Operations, is a key employee.
Douglas V. Liebschner, age 50, joined RPMC 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 RPMC, 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.
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 Ridgewood Power's business. In 1996 and future years, the Managing Shareholder compensates its officers 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 RPMC at cost for services provided by RPMC's employees; no such reimbursement per employee exceeded $60,000 in 1996 or 1997 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 1995 and following years 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.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The Managing Shareholder purchased for cash one full Investor Share. By virtue of its purchase of Investor Shares, the Managing Shareholder is 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. No person beneficially owns 5% or more of the Investor Shares.
The Managing Shareholder was issued one Management Share in the Trust representing the beneficial interests and management rights of the Managing Shareholder in its capacity as 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 below 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
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 1995 to the Managing Shareholder (which is a member of the Board of the Trust) or any other person and made distributions in 1996 as stated at Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters. The Trust paid fees to the Managing Shareholder and its affiliates as follows:
Fee Paid to 1997 1996 1995
Management fee Managing Shareholder $1,154,758 $888,209 $0 Cost reimbursements* RPMC 3,995,249 337,228 0 Investment fee Managing Shareholder 0 627,561 304,697 Placement agent fee Ridgewood and sales commis- Securities sions Corporation 0 315,493 172,674 Organizational, Managing distribution and Shareholder offering fee 0 1,892,959 954,342
* These include all payroll, parts, routine maintenance and other expenses (except for royalties for landfill gas but including an allocation of RPMC overhead) of the Providence Project.
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 3% 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 for payroll and other costs of operation of the Providence and California Pumping Projects. Beginning in 1996, these reimbursements were paid to RPMC. The reimbursements to RPMC, which do not exceed its actual costs and allocable overhead, are described at Item 10(g) - Directors and Executive Officers of the Registrant -- RPMC.
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.
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 Form 8-K was filed with the Commission by the Registrant during the quarter ending December 31, 1997.
(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 onFebruary 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.
3C. Amendment No. 1 to Declaration of Trust is incorporated by reference to Exhibit 3C of Registrant's Annual Report on Form 10-K for the year ended December 31, 1996.
10A. 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.
10B. Agreement of Merger, dated as of July 1, 1996, by and among Consolidated Hydro Maine, Inc., CHI Universal, Inc., Consolidated Hydro, Inc., Ridgewood Maine Power Partners, L.P. and Ridgewood Maine Hydro Corporation. Incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K filed with the Commission on January 8, 1997.
10C. Letter, dated November 15, 1996, amending Agreement of Merger. Incorporated by reference to Exhibit 2.2 of Amendment No. 1 to the Registrant's Current Report on Form 8-K filed with the Commission on January 9, 1997
10D. Letter, dated December 3, 1996, amending Agreement of Merger. Incorporated by reference to Exhibit 2.3 of the Registrant's Current Report on Form 8-K filed with the Commission on January 8, 1997.
10E. Operation, Maintenance and Administration Agreement, dated November __, 1996, by and among Ridgewood Maine Hydro Partners, L.P., CHI Operations, Inc. and Consolidated Hydro, Inc. Incorporated by reference to Exhibit 10 of the Registrant's Current Report on Form 8-K filed with the Commission on January 8, 1997.
10F. Management Agreement, dated as of __________, 1996, between the Registrant and Ridgewood Power Corporation. Incorporated by reference to Exhibit 10F of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1996.
10G. Operation Agreement, dated as of April 16, 1996, among the Registrant, Ridgewood Providence Corporation and Ridgewood Power Management Corporation. Incorporated by reference to Exhibit 10G of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1996
10H. Agreement to Purchase Membership Interests, dated as of June 11, 1997, by and between Ridgewood Maine, L.L.C. and Indeck Maine Energy, L.L.C. Incorporated by reference to Exhibit 2.A. of Amendment No. 1 to Registrant's Current Report on Form 8-K dated July 1, 1997.
10I. Amended and Restated Operating Agreement of Indeck Maine Energy, L.L.C., dated as of June 11, 1997. Incorporated by reference to Exhibit 2.B. of Amendment No. 1 to Registrant's Current Report on Form 8-K dated July 1, 1997.
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 Page 78
24. Powers of Attorney Page 79
27. Financial Data Schedule Page 81
99. Listing of Statutory Provisions that the Trust Agrees to Comply with. Incorporated by reference to Exhibit 99 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1996.
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 IV (Registrant)
By:/s/ Robert E. Swanson President and Chief April 15, 1998 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 15, 1998 Robert E. Swanson Executive Officer
By:/s/ Martin V. Quinn Senior Vice President and Martin V. Quinn Chief Financial Officer April 15, 1998
By:/s/ Kathleen P. McSherry Controller April 15, 1998 Kathleen P. McSherry
RIDGEWOOD POWER CORPORATION Managing Shareholder April 15, 1998
By:/s/ Robert E. Swanson President Robert E. Swanson
/s/ Robert E. Swanson * Independent Trustee April 15, 1998 John C. Belknap
/s/ Robert E. Swanson * Independent Trustee April 15, 1998 Richard D. Propper
As attorney-in-fact for Independent Trustee
Ridgewood Electric Power Trust IV
Consolidated Financial Statements
December 31, 1997, 1996 and 1995
-F1-
Price Waterhouse LLP 1177 Avenue of the Americas Telephone 212 596 7000 New York, NY 10036 Facsimile 212 596 8910 [Letterhead of Price Waterhouse LLP]
Report of Independent Accountants
April 2, 1998
To the Shareholders and Trustees of Ridgewood Electric Power Trust IV
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in shareholders' equity and of cash flows present fairly, in all material respects, the financial position of Ridgewood Electric Power Trust IV at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1997 and the period February 6, 1995 (commencement of share offering) through December 31, 1995, 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 discussed in Notes 1 and 2, effective on October 2, 1996, the shareholders of the Trust consented to end its election to be treated as a Business Development Corporation under the Investment Company Act of 1940. As a result, generally accepted accounting principles for investment companies no longer applied to the Trust and the Trust adopted generally accepted accounting principles applicable to operating companies. The financial statements of the Trust have been restated to reflect the application of generally accepted accounting principles for operating companies for the period from February 6, 1995 (commencement of share offering) to October 2, 1996.
/s/ Price Waterhouse LLP
-F2-
Ridgewood Electric Power Trust IV Consolidated Balance Sheet December 31, 1997 1996
Assets: Cash and cash equivalents $ 11,086,281 $ 22,685,829 Maintenance reserve fund --- 394,070 Accounts receivable, trade 559,764 1,065,181 Other receivables 97,453 109,999 Due from affiliates 164,536 --- Other assets 383,810 528,345
Total current assets 12,291,844 24,783,424
Investments: Investment in Maine Hydro Projects 6,694,826 6,913,421 Investment in Maine Biomass Projects 6,617,862 --- Electric power equipment held for resale 455,182 455,182 Deferred due diligence costs 27,159 245,828
Plant and equipment 14,949,735 11,889,451 Less- Accumulated depreciation (1,068,812) (357,109)
Electric power sales contract 8,338,040 8,338,040 Less- Accumulated amortization (946,212) (390,343)
Debt reserve fund 605,199 575,441
Total assets $ 47,964,823 $ 52,453,335
Liabilities and Shareholders' Equity:
Current maturities of long-term debt $ 592,193 $ 538,191 Accounts payable and accrued expenses 384,533 747,960 Due to affiliates 658,253 92,057 Total current liabilities 1,634,979 1,378,208
Long-term debt, less current portion 4,848,067 5,440,260 Minority interest in the Providence Project 6,458,416 6,888,268
Commitments and contingencies
Shareholders' Equity: Shareholders' equity (476.8 shares issued and outstanding) 35,078,194 38,764,199 Managing shareholder's accumulated deficit (54,833) (17,600) Total shareholders' equity 35,023,361 38,746,599
Total liabilities and shareholders' equity $ 47,964,823 $ 52,453,335
See accompanying notes to the consolidated financial statements. -F3-
Ridgewood Electric Power Trust IV Consolidated Statement of Operations
Commencement of Share Offering (February 6, 1995) Year Ended Year Ended through December 31, December 31, December 31, 1997 1996 1995 Restated
Net sales $ 6,810,911 $ 4,087,722 $ --- Sublease income 369,000 261,375 --- Total revenue 7,179,911 4,349,047 ---
Cost of sales, including depreciation and amortization of $1,267,572 and $747,452 in 1997 and 1996 4,879,962 2,991,835 ---
Gross profit 2,299,949 1,357,262 ---
General and administrative expenses 505,116 372,415 68,752 Management fee 1,154,758 888,209 --- Investment fee --- 627,561 304,697 Project due diligence costs 668,554 63,052 50,000 Other expenses 32,255 43,160 31,089 Total other operating expenses 2,360,683 1,994,397 454,538
Loss from operations (60,734) (637,135) (454,538)
Other income (expense): Interest income 926,641 1,294,037 298,405 Interest expense (572,660) (394,665) --- Loss from Maine Biomass projects (680,109) --- --- Income from Maine Hydro projects 521,710 99,224 --- Other income, net 195,582 998,596 298,405
Income (loss) before minority interest 134,848 361,461 (156,133)
Minority interest in the earnings of the Providence Project (537,625) (288,692) ---
Net income (loss) (402,777) $ 72,769 $ (156,133)
See accompanying notes to the consolidated financial statements.
-F4-
Ridgewood Electric Power Trust IV Consolidated Statement Of Changes in Shareholders' Equity For the Years Ended December 31, 1997 and 1996 and the Period February 6, 1995 (inception) to December 31, 1995
Managing Shareholders Shareholder Total
Initial capital contributions, net (162.1 shares) $13,658,264 $ --- $13,658,264
Net loss for the period (154,572) (1,561) (156,133)
Shareholders' equity, December 31, 1995 (162.1 shares) 13,503,692 (1,561) 13,502,131
Capital contributions, net (314.7 shares) 26,848,394 --- 26,848,394
Cash distributions (1,659,928) (16,767) (1,676,695)
Net income for the year 72,041 728 72,769
Shareholders' equity December 31, 1996 (476.8 shares) $38,764,199 $ (17,600) $38,746,599
Cash distributions (3,287,256) (33,205) (3,320,461)
Net loss for the year (398,749) (4,028) (402,777)
Shareholders' equity, December 31, 1997 (476.8 shares) $35,078,194 $ (54,833) $35,023,361
See accompanying notes to the consolidated financial statements.
-F5-
Ridgewood Electric Power Trust IV Consolidated Statement of Cash Flows
Commencement of Share Offering (February 6, 1995) Year Ended Year Ended through December 31, December 31, December 31, 1997 1996 1995
Cash flows from operating activities: Net income (loss) $ (402,777) $ 72,769 $ (156,133)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation and amortization 1,267,572 747,452 --- Amortization of prepaid and accrued royalties- net --- 777,886 --- Minority interest in earnings of the Providence Project 537,625 288,692 --- Income of unconsolidated Maine Hydro Projects (521,710) (99,224) --- Loss from unconsolidated Maine Biomass Projects 680,109 --- ---
Changes in assets and liabilities, net of effects of Providence Project investment: Decrease (increase) in maintenance reserve fund 394,070 (14,164) --- Decrease (increase) in accounts receivable, trade 505,417 (418,433) --- Decrease (increase) in other receivables 12,546 (50,535) (59,464) Decrease in customer escrow fund --- 1,119,115 --- (Decrease) increase in accounts payable and accrued expenses (363,426) 450,418 34,413 Increase (decrease) in due to/from affiliates, net 401,660 (261,562) --- Other- net 144,535 76,628 ---
Total adjustments 3,058,398 2,616,273 (25,051)
Net cash provided by (used in) operating activities 2,655,621 2,689,042 (181,184)
Cash flows from investing activities: Investment in the Providence Project, net of cash acquired --- (8,287,184) --- Investment in Maine Hydro Projects (265,953) (6,814,197) --- Investment in Maine Biomass Project (7,297,971) --- --- Distributions from Maine Hydro Projects 1,006,257 --- --- Capital expenditures (3,060,284) (1,928,332) --- Deferred due diligence costs 218,669 (222,393) (23,435) Purchase of electric generating equipment --- --- (455,182)
Net cash used in investing activities (9,399,282) (17,252,106) (478,617)
Cash flows from financing activities: Proceeds from shareholders' contributions --- 31,495,223 16,017,470 Selling commissions and offering costs paid --- (4,646,829) (2,359,206) Cash distributions to shareholders (3,320,461) (1,676,695) --- Payments to reduce long-term debt (538,191) (331,953) --- Increase in debt reserve fund (29,758) (58,677) --- Distributions to minority interest (967,477) (530,639) ---
Net cash (used in) provided by financing activities (4,855,887) 24,250,430 13,658,264
Net (decrease) increase in cash and cash equivalents (11,599,548) 9,687,366 12,998,463
Cash and cash equivalents, beginning of period 22,685,829 12,998,463 ---
Cash and cash equivalents, end of period $11,086,281 $ 22,685,829 $ 12,998,463
See accompanying notes to the consolidated financial statements.
-F6-
Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
1. Organization and Purpose
Nature of Business
Ridgewood Electric Power Trust IV (the "Trust") was formed as a Delaware business trust in September 1994 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 February 6, 1995 and discontinued its offering of shares in March 1996.
The Trust has been organized to invest in independent power generation facilities and in the development of these facilities. These independent power generation facilities will include cogeneration facilities, which produce both electricity and heat energy and other power plants that use various fuel sources (except nuclear). The power plants will sell electricity and, in some cases, heat energy to utilities and industrial users under long-term contracts.
Business Development Company Election
The Trust initially made an election to be treated as a Business Development Company ("BDC") under the Investment Company Act of 1940 ("the 1940 Act"). On January 24, 1995, the Trust notified the Securities Exchange Commission of such election and registered its shares under the Securities Exchange Act of 1934 ("the 1934 Act"). On March 24, 1995, the election and registration became effective.
On September 9, 1996, through a proxy solicitation the Trust requested investor consent to end the BDC status. As of October 2, 1996, more than 50% of the investors shares consented to the elimination of the BDC status. Accordingly, the Trust is no longer an investment company under the 1940 Act.
2. Summary of Significant Accounting Policies
Accounting changes
As a BDC under the 1940 Act, the Trust utilized generally accepted accounting principles for investment companies. As a result of the elimination of the BDC status, the Trust now utilizes generally accepted accounting principles for operating companies. In accordance with the generally accepted accounting principles for BDCs, investments in power generation projects were stated at fair value in previously issued financial statements. As a result of the elimination of the BDC status, consolidation and equity method accounting principles now apply to the accounting for investments. Accordingly, the financial data for the period from February 6, 1995 to December 31, 1995 has been restated to reflect the use of consolidation and equity method accounting principles. Because the Trust did not invest in projects until 1996, the restatement had no impact on net income or stockholders' equity.
Principles of consolidation and accounting for investment in power generation projects
The consolidated financial statements include the accounts of the Trust and affiliates owned more than 50%. All material intercompany transactions have been eliminated. -F7-
Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
The Trust uses the equity method of accounting for its investments in affiliates which are 50% owned because the Trust has the ability to exercise significant influence over the operating and financial policies of the affiliate but does not control the affiliate. The Trust's share of the earnings of the affiliates is included in the consolidated results of operations.
Use of estimates
The preparation of consolidated 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.
Cash and cash equivalents
The Trust considers all highly liquid investments with maturities when purchased of three months or less as cash and cash equivalents.
Plant and equipment
Plant and equipment, consisting principally of electrical generating equipment, is stated at cost. Renewals and betterments that increase the useful lives of the assets are capitalized. Repair and maintenance expenditures that increase the efficiency of the assets are expensed as incurred. The Trust periodically assesses the recoverability of plant and equipment, and other long-term assets, based on their estimated future cash flows.
Depreciation is recorded using the straight-line method over the useful lives of the assets, which is 10 to 20 years. During 1997 and 1996, the Trust recorded depreciation expense of $711,703 and $357,109, respectively.
Intangible asset
A portion of the purchase price of the Providence Project was assigned to the Electric Power Sales Contract and is being amortized over the life of the asset (15 years) on a straight-line basis. During 1997 and 1996, the Trust recorded amortization expense of $555,869 and $390,343, respectively.
Electric power equipment held for resale
The Trust owns certain used electric power equipment that is stated at cost, which approximates estimated net realizable value.
Revenue recognition
Power generation revenue is recognized based on power delivered at rates stipulated in the power sales contract. Interest and dividend income is recorded when earned.
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
In come 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.
Offering costs
Costs associated with offering Trust shares (selling commissions, distribution and offering costs) are reflected as a reduction of the shareholders' capital contributions.
Due diligence costs relating to potential power projects
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 project. Costs relating to completed projects are capitalized and costs relating to rejected projects are expensed at the time of rejection.
3. Investments
The Trust has the following investments in power generation projects and electric power equipment:
Nature of Ownership December 31, Project Name Ownership Interest 1997 1996
Consolidated: Providence Project Partnerships 64.3% $11,632,385 $12,411,572
California Pumping Project Direct Ownership 100.0% 648,176 687,733 Electric Power Equipment Direct Ownership 100.0% 455,182 455,182
Equity method: Maine Hydro Projects Partnerships 50.0% $6,694,826 $6,913,421
Maine Biomass Projects Limited Liability Companies 50.0% 6,617,862 ---
Providence Project
In 1996, Ridgewood Providence Power Partners, L.P. was formed as a Delaware limited partnership ("Providence Power"). The Trust invested $12,721,500 and owns a 64.3% limited partnership interest in Providence Power.
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
In addition, Ridgewood Providence Power Corporation, was formed as a Delaware corporation ("RPPCorp."). The Trust invested $128,500 and owns 64.3% of the outstanding common stock of RPPCorp., which is the sole general partner of Providence Power.
On April 16, 1996, Providence Power purchased substantially all of the net assets of Northeastern Landfill Power Joint Venture. The assets acquired include 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 megawatts. 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 the 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 64.3% of the Providence Project. The remaining 35.7% is owned by Ridgewood Electric Power Trust III ("Trust III"). Ridgewood Power Corporation is the managing partner of the Trust and Trust III.
The acquisition of the Providence Project was accounted for as a purchase as of April 16, 1996, and the results of operations of the Providence Project have been included in the Trust's Consolidated Financial Statements since that date. The purchase price was allocated to the net assets acquired, based on their respective fair values. Of the purchase price, $8,338,040 was allocated to the Electric Power Sales Contract and is being amortized over 15 years.
The following unaudited pro forma information has been prepared assuming the Providence Project was acquired as of the beginning of the periods presented. The pro forma information is presented for information purposes only and is not necessarily indicative of what would have occurred if the formation and acquisition had been made as of those dates. In addition, the pro forma information is not intended to be a projection of future results and does not reflect capital equipment additions and changes in operating management which have been made at the Providence Project subsequent to the acquisition.
Pro Forma Information (Unaudited) 1996 1995
Net sales $5,511,642 $4,146,000 Income from operations 1,032,806 712,975 Net income (loss) 88,558 (28,696)
California Pumping Project
On December 31, 1995, the Trust acquired a package of natural gas fueled diesel engines which drive deep irrigation well pumps in Ventura County, California from an affiliated trust. The engines' shaft horsepower-hours are
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
sold to the operator at a discount from the equivalent kilowatt hours of electricity. The Trust receives a distribution of $0.02 per equivalent kilowatt up to 3,000 running hours per year and $0.01 per equivalent kilowatt for each additional running hour per year. The operator pays for fuel, maintenance, repair and replacement. The initial acquisition included 11 engines with a rated capacity of 1.2 megawatts. The purchase price of $353,619 was paid in 1996. During 1996, the Trust acquired an additional 9 engines with a rated capacity of 1.2 megawatts at a purchase price of $344,111. At December 31, 1997 and 1996, the Trusts total investment in the California Pumping Project was $697,730.
Electric Power Equipment Held for Resale
The Trust purchased, from an affiliated entity, various used electric power generation equipment to be held for resale or, in the event a buyer is not found, for use in potential power generation projects. The equipment is held in storage. At December 31, 1997 and 1996, the cost of such equipment was $455,182.
Maine Hydro Projects
On September 5, 1996, Ridgewood Maine Hydro Partners, L.P. was formed as a Delaware limited partnership ("Ridgewood Hydro L.P."). The Trust made investments totaling $6,748,256 and owns a 50% limited partnership interest in Ridgewood Hydro L.P. In addition, Ridgewood Maine Hydro Corporation, was formed as a Delaware corporation ("RMHCorp."). The Trust invested $65,941 and owns 50% of the outstanding common stock of RMHCorp., which is the sole general partner of Ridgewood Hydro L.P.
On December 23, 1996, in a merger transaction, Ridgewood Hydro L.P. acquired 14 hydroelectric projects, located in Maine (the "Maine Hydro Projects"), from a subsidiary of Consolidated Hydro, Inc. The assets acquired include a total of 11.3 megawatts of electrical generating capacity. The electricity generated is sold to Central Maine Power Company and Bangor Hydro Company under long-term contracts. The purchase price was $13,628,395 cash, including transaction costs. In addition, Ridgewood Hydro L.P. assumed a long-term lease obligation of $1,004,679. The Trust's 50% share of the cash consideration paid was $6,814,198. The remaining 50% was paid by Ridgewood Electric Power Trust V ("Trust V"). Ridgewood Power Corporation is the managing partner of the Trust and Trust V.
The Trust's 50% investment in the Maine Hydro Projects is accounted for under the equity method of accounting. The Trust's equity in the earnings of the Maine Hydro Projects has been included in the Consolidated Financial Statements since December 23, 1996.
The Maine Hydro Projects are operated by a subsidiary of Consolidated Hydro, Inc., under an Operation, Maintenance and Administrative Agreement. The annual operator's fee is $307,500, adjusted for inflation, plus an annual incentive fee equal to 50% of the net cash flow in excess of a target amount. The Maine Hydro Projects recorded $429,430 and $3,070 of expense under this arrangement during the periods ended December 31, 1997 and 1996, respectively. The agreement has a five year term and can be renewed for two additional five year terms by mutual consent.
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
Summarized financial information for the Maine Hydro Prjects are as follows:
Balance Sheet Information
December 31, 1997 December 31, 1996 Current assets $ 1,757,908 $ 2,115,375 Electric power sales contract 12,225,765 13,286,920 Other non-current assets 634,952 800,000
Total assets $ 14,618,625 $ 16,202,295
Current liabilities $ 291,911 $ 1,370,774 Non-current liabilities 937,062 1,004,679 Partners' equity 13,389,652 13,826,842 Total liabilities and equity $ 14,618,625 $ 16,202,295
Statement of Operations Information
For the Period September 5, 1996 For The Year Ended (date of inception) December 31, 1997 To December 31, 1996
Revenue $4,113,065 $192,152 Operating expenses 2,952,589 50,340 Net income 1,043,420 198,447
Maine Biomass Projects
On July 1, 1997, through a subsidiary, the Trust purchased a preferred membership interest in Indeck Maine Energy, L.L.C. ("Maine Biomass Projects"), which owns two electric power generating stations fueled by waste wood. The aggregate purchase price was $7,297,971 and includes transaction costs of $297,971. Each project has 24.5 megawatts of electrical generating capacity. The Penobscot project is located in West Enfield, Maine and the Eastport project is located in Jonesboro, Maine. The Maine Biomass Projects had a power sales contract with the New England Power Pool, which expired on August 31, 1997. The facilities were shut down in September 1997 and were reactivated in November 1997 to sell capacity and energy to Bangor Hydro- Electric Company, a local utility ("BHC") on a month-to-month basis. The facilities were again shut down in January 1998. The cost of maintaining the idled facilities in good condition is approximately $100,000 per month.
The preferred membership interest entitles the Trust to receive an 18% cumulative annual return on its $7,000,000 capital contribution to the Maine Biomass Projects from the operating net cash flow from the projects. Trust V also purchased an identical preferred membership interest in the Maine Biomass Projects. After payments in full to the preferred membership interests, up to $2,500,000 of any remaining cash flow during the year is paid to the other the Maine Biomass Projects members. Any remaining operating net cash flow is payable 25% to the Trust and Trust V and 75% to the other the Maine Biomass Projects members.
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
The Trust's investment in the Maine Biomass Projects is accounted for under the equity method of accounting. The Trust's equity in the loss of the Maine Biomass Projects for the period July 1, 1997 to December 31, 1997 was $680,109.
The Penobscot and Eastport projects are operated by Indeck Operations, Inc., an affiliate of the other members of Indeck Maine under a management agreement. The annual operator's fee is $300,000, of which $200,000 is payable contingent upon the Trusts receiving their cumulative annual return. The management agreement has a form of one year and automatically continues for successive one year terms unless canceled by either the Maine Biomass Projects or Indeck Operations, Inc. The Trusts can also cancel the contract effective December 31, 1998 if certain preferred membership interest payments have not been made.
Summarized financial information for the Maine Biomass Projects is as follows:
Balance Sheet Information at December 31, 1997
Current assets $ 861,677 Current liabilities $ 912,683 Non-current assets 3,524,356 Members' equity 3,473,350 Total assets $ 4,386,033 Total liabilities and equity $4,386,033
Statement of Operations Information for the Period July 1, 1997 (date of acquisition) to December 31, 1997
Revenue $ 2,991,793 Operating expenses 4,276,373 Depreciation & Amortization 100,085 Net loss $ (1,384,665)
4. Long-term Debt
Following is a summary of long-term debt at December 31, 1997:
Senior secured non-recourse notes payable $5,440,260 Less - Current maturity (592,193) Total long-term debt $4,848,067
The senior secured non-recourse notes are due in monthly installments of $90,738 including interest at 9.6%. Final payment is due on October 15, 2004. The notes also provide for additional interest equal to 5% of the annual net cash flow of the Providence Project, as defined. No additional interest was due for the year ended December 31, 1997 or for the eight and one half months ending December 31, 1996. The notes are secured by a leasehold mortgage on Providence Power's landfill lease agreements and substantially all of the assets of Providence Power. In addition to the required monthly payments, mandatory prepayments may be required if certain events occur. The loan agreement also provides for a cash funded debt service reserve and maintenance reserve. At December 31, 1997 and 1996, the cash balance in these reserve accounts was $605,199 and $575,441, respectively. Additions and reductions to
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
these reserve accounts are defined in the loan agreement. As of January 31, 1997, Providence Power's obligations to maintain a cash balance in the maintenance reserve account terminated and the cash balance in the reserve account was released to Providence Power. The loan agreement contains various covenants, including the maintenance of a specified debt service ratio.
Scheduled repayments of long-term debt principal for the next five years are as follows:
Year Ended December 31, Repayment
1998 $592,193 1999 651,613 2000 716,995 2001 788,937 2002 868,098
During the fourth quarter of 1997, the Trust and its principal bank executed a revolving line of credit agreement, whereby the bank will provide a three year committed line of credit facility of $1,150,000. At December 31, 1997, there were no borrowings outstanding under the credit facility. Outstanding borrowing 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.
5. Fair Value of Financial Instruments
At December 31, 1997, the carrying value of the Trust's cash, accounts receivable, debt service reserve fund and accounts payable approximates their fair value. The fair value of the long-term debt, calculated using current rates for loans with similar maturities, also approximates its carrying value.
6. Electric Power Sales Contracts
Providence Power is committed to sell all of the electricity it produces to New England Power Company ("NEP") for prices as specified in the Power Purchase Agreement. The prices are adjusted annually for changes in the Consumer Price Index, as defined. The NEP agreement expires in the year 2020 and can be terminated by either party under certain conditions in 2010. At the time of the acquisition of the Providence Project, Providence Power was required under the NEP agreement to maintain in an escrow account cash to secure payment to NEP in the event of default. At April 16, 1996, the required escrow balance amounted to $1,065,989. In October 1996, the required escrow balance decreased to zero and the cash held in escrow was released to Providence Power. For the year ended December 31, 1997 and the eight and one half months ended December 31, 1996, sales revenue under the NEP Power Purchase Agreement amounted to $6,458,648 and $3,946,077, respectively.
The Maine Hydro Projects qualify as small power production facilities under the Public Utility Regulatory Policies Act ("PURPA"). PURPA requires that each electric utility company, operating at the location of a small power production facility, as defined, purchase the electricity generated by such facility at a specified or negotiated price. The Maine Hydro Projects sell
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
substantially all of their electrical output to two public utility companies, Central Maine Power Company ("CMP") and Bangor Hydro-Electric Company ("BHC"), under long-term power purchase agreements. Eleven of the twelve power purchase agreements with CMP expire in December 2008 and are renewable for an additional five year period. The twelfth power purchase agreement with CMP expires in December 2007 with CMP having the option to extend the contract for three more five-year periods. The two power purchase agreements with BHC expire in December 2014 and February 2017.
7. Landfill Lease and Sublease
Providence Power leases the Central Landfill, located in Johnston, Rhode Island from Rhode Island Solid Waste Management Corporation ("RISWMC"). The lease expires in 2020 and can be extended for an additional 10 years. This operating lease requires Providence Power to pay a royalty equal to 15% of net revenues, as defined, for the first 15 years of the lease. For subsequent years, the royalty is 15% of net revenues for each month in which the average daily kilowatt hour production is less than 180,000 and 18% of net revenues for each month in which the average daily kilowatt hour production exceeds 180,000. At the time of the acquisition of the Providence Project, Providence Power made a royalty prepayment to RISWMC of $925,000. For the year ended December 31, 1997 and the eight and one half months ended December 31, 1996, royalty expense relating to the RISWMC lease amounted to $951,767 and $588,456, respectively.
Providence Power subleases the Central Landfill to Central Gas Limited Partnership ("Gasco"). Gasco operates and maintains the landfill gas collection system and supplies landfill gas to the Providence Project. The sublease agreement is effective through December 31, 2010 and provides for the following:
1. Sublease Income - Gasco is to pay Providence Power an annual amount equal to the product of $30,000 times the assumed output capacity of each engine generator set in megawatts installed and operating by the joint venture. Income recorded under the sublease amounted to $369,000 and $261,375 for the year ended December 31, 1997 and eight and one half months ended December 31, 1996, respectively.
2. Fuel Expense - Providence Power agreed to purchase all the landfill gas produced by Gasco and pay on a monthly basis $.01183 per kilowatt hour for the first 4,000,000 kilowatt hours, $.005 per kilowatt hour for kilowatt hours in excess of 4,000,000 and $.05 per million BTU's of excess landfill gas. The price is adjusted annually for changes in the Consumer Price Index, as defined. Purchases from Gasco for the year ended December 31, 1997 and the eight and one half months ended December 31, 1996, amounted to $863,536 and $555,447, respectively.
8. Transactions With Managing Shareholder and Affiliates
The Trust pays to the managing shareholder a distribution and offering fee up to 6% of each capital contribution made to the Trust. This fee is intended to cover legal, accounting, consulting, filing, printing, distribution, selling and closing costs for the offering of the Trust. For
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
the period ended December 31, 1996 and 1995, the Trust paid fees for these services to the managing shareholder of $1,892,959 and $954,342, respectively. These fees were recorded as a reduction in the shareholders' capital contribution.
The Trust also 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. For the periods ended December 31, 1996 and 1995, the Trust paid investment fees to the managing shareholder of $627,561 and $304,697, respectively.
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 3% of the net asset value of the Trust payable monthly upon the closing of the Trust. For the year ended December 31, 1997 and 1996, the Trust paid an annual management fees to the managing shareholder of $1,154,758 and $888,209, 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 each 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, 1997.
The managing shareholder purchased one share of the Trust for $83,000 in 1995. Through December 31, 1997, commissions and placement fees of $172,674 were earned by Ridgewood Securities Corporation, an affiliate of the managing shareholder.
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 Trust's power generation projects. Ridgewood Management charges 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 amount invested in projects managed by Ridgewood
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Ridgewood Electric Power Trust IV Notes to the Consolidated Financial Statements
Management. During the year ended December 31, 1997 and the eight and one half months ended December 31, 1996, Ridgewood Management charged Providence Power $467,881 and $337,228, respectively. During the periods ended December 31, 1997 and 1996, Ridgewood Management did not charge any amounts to the Maine Hydro projects or the Maine Biomass projects.
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