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 II, the Registrant hereunder (the "Trust"), was organized as a Delaware business trust on November 20, 1992 to participate in the development, construction and operation of independent power generating facilities ("Independent Power Projects" or "Projects"). Ridgewood Energy Holding Corporation ("Ridgewood Holding"), a Delaware corporation, is the Corporate Trustee of the Trust.
The Trust sold whole and fractional shares of beneficial interest in the Trust ("Investor Shares") at $100,000 per Investor Share. The Trust terminated its private placement offering of Shares (the "Offering") on January 31, 1994, at which time it had raised approximately $23.5 million. Net of offering fees, commissions and expenses, the Offering provided approximately $19.4 million of net funds available for investments in the development and acquisition of Independent Power Projects. The Trust has 479 record holders of Investor Shares (the "Investors"). As described below in Item 1(c)(2), the Trust (and its subsidiaries) have invested its net funds in five Independent Power Projects.
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). Ridgewood Holding, as 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 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 February 27, 1993, the Trust notified the Securities and Exchange Commission of such election and registered the Investor Shares under the Securities Exchange Act of 1934, as amended (the "1934 Act"). On April 29, 1993, the election and registration became effective.
(b) Financial Information about Industry Segments.
The Trust operates in only one industry segment: investing in independent power generation and similar energy projects.
(c) Narrative Description of Business.
(1) General Description.
The Trust was formed to participate in the development, construction and operation of independent electric power projects that generate electricity for sale to utilities and other users, and in some cases, to provide heat energy or chilled water as well to users.
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 Trust has invested approximately $16.1 million of its funds in five Projects: (i) a waste-to-energy generating facility located in Pittsfield, Massachusetts (the "Berkshire Project"); (ii) a district cooling facility located in downtown San Diego, California, that supplies chilled water for office building central air conditioning systems (the "San Diego Project"); (iii) a municipal waste transfer station located in Columbia County, New York, near the Berkshire Project (the "Columbia Project"); (iv) a natural gas-fired cogeneration facility located in Monterey County, California (the "Monterey Project") and (v) various natural gas-fueled engines used to power irrigation well pumps in Ventura County, California (the "Sunkist Project"). The Trust has also invested approximately $331,000 to acquire, store and transport used electric power generation equipment for future use at its Projects.
As discussed below, the Trust is a "business development company" under the Investment Company Act of 1940. In accounting for its Projects, it treats each Project as a portfolio investment that is not consolidated with the Trust's accounts. Accordingly, the revenues and expenses of each Project are not reflected in the Trust's financial statements and only cash distributions are included, as revenue, when received. Accordingly, the recognition of revenue from Projects by the Trust is dependent upon the timing of distributions from Projects by the Managing Shareholder. As discussed below at Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters, distributions from Projects may include both income and capital components.
(2) The Trust's Investments.
(i) Berkshire Project.
On January 4, 1994, the Trust made an approximately $2.3 million equity investment in a limited partnership, Pittsfield Investors Limited Partnership, formed to acquire the Berkshire Project, including the assets and business of Pittsfield Resource Recovery Facility, from Vicon Recovery Associates ("Vicon"), the developer and former operator of the facility. The Berkshire Project is a waste to energy plant located in Pittsfield, Massachusetts, which is in the Berkshire Mountains, approximately 150 miles west of Boston and 175 miles north of New York City. The facility, which has been operating since 1981, burns municipal solid waste supplied by the City of Pittsfield ("Pittsfield"), surrounding communities and other providers.
The Berkshire Project receives "tipping fees" paid by the waste suppliers based on the number of tons of waste delivered to the facility. Tipping fees paid by Pittsfield are determined under a long-term waste supply agreement which will remain in effect until November 2004. Tipping fees paid by other waste suppliers are based on the spot market (i.e., current market prices). The facility generates additional revenue by selling steam produced from the waste burning process to a nearby paper mill owned by Crane & Co., Inc. ("Crane") under a long-term contract which will remain in effect until November 2004. The Crane paper mill is the only facility in the United States which manufactures currency paper stock used to print United States currency (as well as currency paper stock for other governments). Crane has had an exclusive currency contract for 114 years, although the U.S. Treasury is taking steps to create a competing supplier under legislation requiring the U.S. Government to create competition wherever possible.
The Trust's partners in the Berkshire Project are subsidiaries of Energy Answers Corporation (collectively, "EAC"). EAC made an equity investment of approximately $1.3 million in the Berkshire Partnership and also serves as manager and operator of the facility.
The investment structure affords the Trust a preferred 15% annual return on its investment plus a potential share of any additional cash flow. More specifically, the Trust is entitled to an annual preferred distribution of available cash flow, representing revenue from the Berkshire Project, (after funding debt service, debt service reserves and operating and maintenance expenses) in an amount equal to 15% of its investment. In the event that distributions are insufficient to pay the 15% preferred distribution in any given year, the shortfall will be payable out of distributions, if any, in subsequent years. After the Trust has received its 15% preferred distribution in any given year, EAC is entitled to an annual management fee for operating and managing the facility in an amount equal to $300,000, escalating with inflation. After these initial distributions have been made, the Trust is entitled to receive an additional amount equal to 5% of its investment and then EAC is entitled to receive an additional amount equal to 10% of the amount previously distributed to it. Any remaining distributable cash flow for the year will be shared equally by the Trust and EAC.
Ownership rights to the Berkshire Project are held under a long term lease purchase agreement and related non recourse industrial revenue bond financing agreements among the Berkshire Project, Pittsfield's industrial development authority and others. The remaining principal amount of the bonds was approximately $6.2 million at December 31, 1996. In addition, the Berkshire Project is subject to additional subordinated debt obligations of approximately $1.8 million which were issued to Vicon in connection with the acquisition of the facility.
Distributions to the Trust from the Berkshire Project in 1996 totalled $351,000 (a 14.9% annual return), down from $447,000 in 1995 and $482,000 in 1994. A decision to retain cash flow for capital expenditures, as described at Item 7 - Management's Discussion and Analysis of Results of Operations, caused the decrease from 1995 to 1996.
(ii) Columbia Project.
On August 31, 1994, the Trust entered into a partnership, B- 3 Limited Partnership with affiliates of EAC, the same firm with which the Trust participates in the Berkshire Project. The Trust made an investment of approximately $4 million into the B-3 Limited Partnership to construct a municipal waste transfer station located in Columbia County, New York.
The purpose of a transfer station like the Columbia Project is to provide a facility where municipal waste collected from nearby towns by smaller, short haul trucks can be transferred to larger, long haul trucks for more efficient transportation of the waste to distant landfills. The primary customers for the Columbia Project are local waste haulers who dispose of waste at local landfills scheduled for closing under state and federal requirements. Although one-year extensions of the closing deadlines for some local landfills have temporarily reduced anticipated demand at the facility, the process of closing many municipal landfills in the Albany area and the Berkshire region is expected to reduce the number of alternative disposal sites and increase the costs of alternative sites relative to the Columbia Project. Although designed to operate as a stand-alone facility, the additional capacity of the Columbia Project may support expanded operations of the Berkshire Project.
During the construction period, the Trust received interest on its investment at the rate of 12% per annum. The Columbia Project commenced operations in January 1995. The Trust is entitled to receive a cumulative priority return on the Trust investment of 18% per annum, with any shortfalls being carried forward into subsequent years. Thereafter, EAC affiliates will be entitled to receive a management fee of $175,000 escalating with inflation. Any additional cash flow will be split 50/50 between the Trust and EAC affiliates. Distributions to the Trust from the Columbia Project during 1996 totalled $515,000 (approximately a 12.9% return). For the period ended December 31, 1995, the Trust had received approximately $510,000 in distributions from the Columbia Project.
(iii) San Diego Project.
On March 21, 1994, the Trust made an investment of approximately $2.3 million to acquire an 80% interest in a limited partnership, RSD Power Partners, L.P. (the "San Diego Partnership"), formed to acquire the San Diego Project, including the assets and business of San Diego Central Cooling Company, from a subsidiary of Pacific Generating Corporation, the former owner and operator of the limited partnership. The Trust made additional capital contributions, totaling approximately $1.2 million, to the San Diego Partnership to fund working capital and to purchase various leased equipment. The San Diego Project has been in continuous operation since 1972 and currently sells chilled water to over 10 commercial, retail and government office buildings connected to the facility by a closed underground pipeline loop owned and used exclusively by the facility. The San Diego Project is a fundamental part of the infrastructure of downtown San Diego in that the chilled water provided by the facility is used in the central air conditioning systems of a significant portion of the downtown commercial space. The San Diego Project has 24 years remaining on its franchise with the City of San Diego for the continued use of the space beneath the city streets for the pipeline system. The facility has the potential to substantially expand its number of customers and volume of chilled water sales. The underground pipeline loop, which is approximately 2.5 miles in length, is capable of providing chilled water to 25 customers or more in a 50 block area.
The Trust's partner in the San Diego Project is Wilton Technology Associates ("Wilton"), which is owned by Steven Jay Mueller. The investment structure affords the Trust a preferred 25% annual return on its investment plus a potential share of any additional net cash flow. More specifically, the Trust is entitled to an annual preferred distribution of available cash flow attributable to the facility (after funding, operating and maintenance expenses and reserves) in an amount equal to 25% of its investment. In the event that distributions are insufficient to pay the 25% preferred distribution in any given year, the shortfall will be payable out of any distributions in subsequent years. After the Trust has received its 25% preferred distribution in any given year, Wilton will be entitled to receive any further distributions during the year until it has received an amount equal to 25% of the amount distributed to the Trust. Thereafter, distributions will be shared on a basis of 80% to the Trust and 20% to Wilton. Wilton also managed the facility on a turnkey basis for a fixed payment of $100,000 per year, terminable annually by the Trust if performance targets were not met. During 1996, the Trust's affiliate, Ridgewood Power Management Corporation ("RPMC"), began taking on responsibility for operation and maintenance and Wilton's activities were focused on marketing and expansion planning.
Distributions to the Trust from the Project in 1996 totaled $618,000 (a 17.6% annual return on investment), down from $1,027,000 in 1995 and $435,000 in 1994. The decrease reflected the loss of a significant customer, higher natural gas prices and a relatively cool summer. In early 1997 the Trust entered into discussions with Wilton about modifying or terminating the management agreement and the prospects for obtaining additional customers (which might require a material expansion of the Project).
(iv) Monterey Project.
On January 9, 1995, the Trust purchased 100% of the equity interests in the Monterey Project, which is an operating 5.5 megawatt cogeneration project located in the City of Salinas, Monterey County, California, for a cash purchase price of approximately $3.8 million plus the contribution of four engine/generator sets, valued at $1.3 million, which were owned by the Trust and cost approximately $1.6 million. The Monterey Project has been operating since 1991 and uses natural gas fired reciprocating engines to generate electricity for sale to Pacific Gas and Electric Company under a long term contract (the "Power Contract"). Thermal energy from the Monterey Project is used to provide warm water to an adjacent greenhouse under a long term contract. For 1996, the Trust had received approximately $757,000 in distributions (a 14.3% annual return) from the Monterey Project, up from $607,000 in 1995. The Trust's investment in operating and maintenance improvements was the primary reason for the increase.
(v) Sunkist Project
In March 1995, the Trust purchased 100% of the equity interests in the Sunkist Project, which is an irrigation service Project located in Ventura County, California, for a cash purchase price of approximately $732,000. The Trust has made additional investments of $220,000 to purchase additional engines and expand the Project. The Sunkist 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 Sunkist Project will provide power equivalent to approximately .3 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. The Trust receives 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, receives the remainder. In 1996, the Project paid $129,000 to the Trust (a 13.6% annual return), up from $105,742 in 1995.
(vi) Discontinued Investments
The Trust made an investment of $811,000 in a partnership organized for the purpose of pursuing the acquisition of existing larger Projects. The Trust also made equity investments of totalling $254,000 in two other partnerships organized for the purpose of pursuing the development and construction of larger Projects. Despite substantial efforts, none of these partnerships produced an investment opportunity which was satisfactory to the Trust, and the Trust terminated its participation in these partnerships and wrote off those investments in December 1994. Further, in 1994 the Trust wrote off an additional $332,000 with respect to development for a Project which failed to meet the requirements for construction.
Additional information regarding the Projects is found in the Notes to the Financial Statements.
(3) Project Operations.
The Monterey Project's revenue from its Power Contract consists of two components, energy payments and capacity payments. Energy payments are based on a facility's net electric output, with payment rates usually indexed to the fuel costs of the purchasing utility or to general inflation indices. Capacity payments are based on either a facility's net electric output or its available capacity. Capacity payment rates vary over the term of a Power Contract according to various schedules.
The San Diego Project sells its output to private customers under long-term contracts that have similarities to Power Contracts in that they provide for continuous sales and earnings over a sustained period of time. However, the Trust may be at somewhat greater risk of default from these customers as compared to sales to utilities, which until recently had a relatively low risk of default. Further, because customers have the option of installing or continuing to operate their own air conditioning and heating equipment, and because customers often prefer to operate themselves to assure control, it can be difficult to obtain new customers.
The Berkshire Project obtains waste for fuel under a long term contract providing it with revenues from tipping fees, which are subject to the default risks of dealing with municipalities and small trash haulers, and sells steam to Crane under a long-term contract.
The Sunkist Project sells its power to the farmers on whose land its engines are situated under contracts terminable at any time on 60 days' prior notice to the Trust. Although the Trust thus is at risk if many customers concurrently terminate contracts, as might happen if an electric utility or other supplier were to offer substantially discounted rates, the Trust believes that it is currently a competitive supplier even as California begins deregulation of electricity rates and that alternate customers can be secured in the event contracts are terminated. The Columbia Project obtains its revenues from spot and contract sales of transfer station services which are dependent upon the volume of waste delivered to it and which are sensitive to the prices of alternative disposal methods and local economic activity.
The major costs of a Project while in operation will be debt service (if applicable), fuel, taxes, maintenance and operating labor. The ability to reduce operating interruptions and to have a Project's capacity available at times of peak demand are critical to the profitability of a Project. Accordingly, skilled management is a major factor in the Trust's business. The Berkshire, Columbia and Sunkist Projects are managed by the development companies that were responsible for developing those Projects, as described above. Each development company also has an equity or an income interest in its Project subordinated to the Trust's preferred rights, which may create an additional incentive for the manager. The Trust monitors their performance using its own personnel and outside consultants. At the San Diego Project, a similar arrangement was in place, but the Trust has taken on the major portion of the operating and management responsibility beginning in 1996.
The Trust has owned and managed the Monterey Project through a subsidiary since its acquisition in 1994. The costs of operating this Project had been wholly borne by the Trust as operating expenses and have not been borne by the Managing Shareholder. Effective January 1, 1996, the Managing Shareholder organized RPMC and has caused the Trust's subsidiaries to hire RPMC to provide management, purchasing, engineering, planning and administrative services for the Monterey Project and operating, administrative and maintenance functions for the San Diego Project. RPMC also provides accounting support for the Sunkist Project. The Managing Shareholder believes that for these Projects, where RPMC has necessary skills, having RPMC manage the Projects benefits the Trust by creating clear responsibilities and by capturing the profit component of the management contract for the Trust.
See Item 10 - Directors and Officers and Item 13 - Certain Relationships and Related Transactions for further information regarding RPMC and for the cost reimbursements received by RPMC.
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. Chilled water produced by the San Diego Project and steam produced by the Berkshire Project are conveyed directly to the user by pipeline and the energy produced by the engines in the Sunkist Project is applied directly to pumps.
The overall demand for electrical energy is somewhat seasonal, with demand usually peaking in the summertime as a result of the increased use of air conditioning. Greenhouse demand for hot water from the Monterey Project peaks in the winter and spring months, while demand for the San Diego Project's chilled water for building cooling peaks in the summer and early fall. The impact of fluctuations in the demand or supply of electrical or thermal products generated upon the revenues of any particular Project is usually dependent on the terms of the Power Contract pursuant to which the energy is purchased.
Generally, revenues from the sales of electric energy from a cogeneration facility will represent the most significant portion of the facility's total revenue. However, to maintain its status as a Qualifying Facility under PURPA, it is imperative that the Monterey Project continue to satisfy PURPA cogeneration requirements as to the amount of thermal products generated. Therefore, since the Monterey Project has only two customers (the electric energy purchaser and the thermal products purchaser), loss of either of these customers would probably have a material adverse effect on the Project.
The technology involved in conventional power plant construction and operations as well as electric and heat energy transfers and sales is widely known throughout the world. There are usually a variety of vendors seeking to supply the necessary equipment for any Project. So far as the Trust is aware, there are no limitations or restrictions on the availability of any of the components which would be necessary to complete construction and commence operations of any Project. Generally, working capital requirements are not a significant item in the independent power industry. The cost of maintaining adequate supplies of fuel sources is usually the most significant factor in determining working capital needs.
Hydrocarbon fuels, such as natural gas, coal and fuel oil, have been generally available in recent years for use by Independent Power Projects, although there have been serious supply impairments for both oil and natural gas at times during the last 20 years. Market prices for natural gas, oil and, to a lesser extent, coal have fluctuated significantly over the last few years. See Item 7 - Management's Discussion and Analysis of Results of Operation for additional information regarding the effects of natural gas price increases on certain Projects owned by the Trust. 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. The Berkshire Project uses municipal wastes as fuel and the Columbia Project charges on the basis of volume of waste. The availability of spot waste (waste delivered otherwise than under contract) depends on the costs of other disposal alternatives.
In general, cogeneration, due to its higher efficiency, tends to be relatively more profitable as energy costs (including natural gas) increase and relatively less profitable as such costs decrease. Projects which use natural gas as a fuel source bear the risk of gas price fluctuations adversely affecting their economics.
In order to commence operations, most Projects require a variety of permits, including zoning and environmental permits. Inability to obtain such permits will likely mean that a Project will not be able to commence operations, and even if obtained, such permits must usually be kept in force in order for the Project to continue its operations.
Compliance with environmental laws is also a material factor in the independent power industry. The Trust believes that capital expenditures for and other costs of environmental protection have not materially disadvantaged its activities relative to other competitors and will not do so in the future. Although the capital costs and other expenses of environmental protection may constitute a significant portion of the costs of a Project, the Trust believes that those costs as imposed by current laws and regulations have been and will continue to be largely incorporated into the prices of its investments and that it accordingly has adjusted its investment program so as to minimize material adverse effects. If future environmental standards require that a Project spend increased amounts for compliance, such increased expenditures could have an adverse effect on the Trust to the extent it is a holder of such Project's equity securities. See Item 1(c)(6) - Business - Narrative Description of Business - Regulatory Matters.
(4) Trends in the Electric Utility and Independent Power Industries
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. In accordance with industry usage, sales of electricity by generators to utilities or other marketers of electricity are referred to as "wholesale" transactions and sales by generators, utilities or others to end users of electricity are referred to as "retail" transactions.
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" and on their ability to participate in Independent Power Projects. See Item 1(c)(6)(ii) -- Energy Regulation -- the 1992 Energy Act. 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, Independent Power Projects in the future will face competition not only from other Independent Power Projects seeking to sell electricity on a wholesale basis but also from exempt wholesale generators, electric utilities with excess capacity and independent generators spun off or otherwise separated from their parent utilities. Large-scale Projects that can sell large amounts of electricity or that have excellent reliability records or favorable locations may have competitive advantages over small-scale Projects (such as the Trust's), Projects that cannot commit to deliver power on a firm commitment basis or Projects that are located in electricity surplus areas with insufficient transmission capacity.
Wholesale-level Access to Transmission Capacity.
Without access to transmission capacity, an Independent Power Project 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 Projects.
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.
FERC initially dealt with wheeling requests on a case-by- case basis as constrained by provisions of the 1992 Energy Act that require all costs of the transmitting utility to be recovered in the transmission charge and that prohibit wholesale competitors from wheeling power to customers of an electric utility under generating contracts or tariffs. 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. Initial trade estimates are that up to 6% of the entire U.S. market for wholesale power would be available to Independent Power Projects and other wholesale generators under the proposal.
Numerous regulatory issues must be addressed under this proposal of which one of the most contentious is the treatment of utility so-called "stranded costs." Utilities that own generating plants with relatively high costs of production would be under severe competitive and regulatory pressure to purchase cheaper wholesale electricity, but in that event the utilities would not receive sufficient revenue to meet debt service requirements or other capital costs (the stranded costs) relating to the high-cost plants. This might significantly impair utility cash flows and some utilities might be at risk of insolvency in that event. The FERC order would require some mitigation efforts on the utility's part, but primarily would require wholesale customers who acquire electricity from a new supplier to compensate their former utility supplier for revenue lost. This might require a customer who changes suppliers to pay a substantial additional fee to the prior utility supplier, thus inhibiting changes of supplier.
The order takes no action to modify existing power purchase 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. The Trust has developed its business plan in anticipation of the order and will pursue its investment program to take advantage of opportunities as they arise in the changing industry. The Trust is unable to predict the consequences of the order on its eventual operations or on the independent power industry.
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 the U.S., 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 Projects. 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.
Conservation Initiatives.
In recent years many state regulators, at the urging of citizens' groups and as contemplated by the 1992 Energy Act, have required electric utilities to engage in least cost utility planning, demand side management and other conservation programs. These programs have the common effect of encouraging utilities to look to conservation of electricity and the more efficient use of existing capacity as means of meeting new demand, as well as to purchases from Independent Power Projects or wholesale generators and to building more generation capacity. There are also reports that utilities are reducing their reserve capacity levels to minimums and are more aggressively controlling dispatch of power as a means of minimizing new power purchases.
Proposals to Modify PURPA and Existing Power Contracts.
The independent power industry remains a creature of PURPA in most respects. The prospects of increased competition to supply electricity, availability of wheeling of wholesale power, supply alternatives through the conservation initiative described above and reduced rates of increase in electricity demand have caused many electric utilities to advocate repeal or modification of PURPA and changes to existing long-term Power Contracts with Independent Power Projects. These utilities have alleged that PURPA requires them to purchase electricity at higher prices than they could acquire new capacity themselves and that existing Power Contracts, signed when utilities anticipated much higher fuel and capital costs and higher demand, provide for prices substantially above current wholesale prices. The independent power industry has pointed out that PURPA does not require utilities to purchase new supplies from Independent Power Projects at rates above alternative sources' prices (although a few state regulators have imposed such requirements from time to time) and that existing long-term Power Contracts were generally entered into on the basis of good faith estimates by the utilities of future conditions with the expectation that sponsors would rely upon them.
To date, FERC has rejected proposals to modify existing Power Contracts (except for contracts entered into under state regulations mandating payment of prices greater than utility avoided costs at the time the contracts were executed), and FERC's rulemaking proposals are expressly based on the principle that existing Power Contracts that comply with current law should not be modified by FERC. Although proposals have been introduced in Congress to amend or repeal PURPA, no such proposal has yet been reported. However, there can be no assurance that FERC or the Congress will not take action to reduce or eliminate the benefits or PURPA for Independent Power Projects or that they would not take action purporting to change or cancel existing Power Contracts or that they would not take action making compliance with those contracts economically or practically infeasible. If any such action were to be taken, the value of existing Independent Power Projects might be significantly impaired or even eliminated. If such action were to be proposed with any significant prospect of adoption, the consequent uncertainty might have similar effects.
In a related phenomenon, some electric utilities that are parties to long-term Power Contracts with rates substantially above current replacement costs have entered into buy-out arrangements with the owners of those Independent Power Projects. Under these agreements, the Power Contracts are terminated in exchange for a payment by the utility to the Project. Typically, these arrangements have been limited to Independent Power Projects with high costs of production or other factors that have impaired their profitability, even with a firm Power Contract. The Trust does not anticipate investing in Projects with the expectation of soliciting or receiving a buy-out arrangement, but it will consider potential arrangements if conditions warrant.
In the absence of desired regulatory or legislative changtes, many utilities have aggressivly taken action to abrogate existing Power Contracts by alleging default by the generator or Project deficiencies. Virginia Electric and Power Company attempted to do so for a Project owned by another business trust sponsored by the Managing Shareholder, alleging immaterial, technical violations of the Power Contract. A federal district court held that the utility did not have the right to terminate the Power Contract on those grounds. While the case was on appeal, that trust accepted an offer from the utility to settle the case by paying $3.75 million to the Trust in exchange for the cancellation of the Power Contract. The settlement was concluded on January 17, 1997. The case had no material effect on this Trust or its business.
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.
Many states are experimenting with retail wheeling, including New Hampshire, whose three-year pilot program would allow up to 3% of state peak loads to be subject to retail competition, and Michigan, which is proposing to allow incremental growth in load demand to be supplied competitively. The New Hampshire program may be abrogated, because it proposes to split the burden of utility stranded costs between ratepayers and the utilities in opposition to FERC's position that utilities should not bear those costs. Many larger states, including California, New York, Massachusetts, Pennsylvania and Florida among others, are implementing large scale movements toward various forms of retail deregulation. It appears that most states will do so by the year 2000. These proposals are currently the subject of intensive debate and restructuring, and any such proposal is likely to undergo judicial review. Regulators and industry participants currently have extreme uncertainty as to whether and how far retail-level competition will be authorized, the treatment of stranded costs, the extent to which FERC's actions in the wholesale market will practically compel retail-level competition and the effects of any change. As of the date of this Annual Report, however, no state authority has proposed or implemented any plan that would abrogate or impair existing long-term Power Contracts with Independent Power Projects. Instead, to the extent that long-term Power Contracts have rates above current avoided costs, the excess is being treated by most states as a form of stranded cost. Many states are providing that all or most of the stranded costs will be borne by ratepayers rather than Independent Power Projects or utilities. Typically, the state will require customers who change electricity suppliers to make payments to a fund used to reimburse utilities in part for the burden of stranded costs. Although this may lessen pressures on utilities to contest long- term Power Contracts, it may deter retail customers from switching to independent power suppliers.
Initial Effects of Trends
Although, as mentioned above, it is impractical to predict all the consequences of the rapidly evolving trends in the electric power industry, certain patterns are beginning to emerge. First, as noted before, investment in new Independent Power Projects and in new utility generating capacity in the United States has substantially decelerated since 1993, as the larger participants in the development process (including developers, utilities, lenders and equipment suppliers) reassess their positions. Indeed, many of the largest participants have announced their intentions to concentrate their resources in developing countries in Europe and Asia. Similarly, lenders are more reluctant currently to extend large amounts of non-recourse financing for development of Projects and are insisting on larger equity investments by owners of Projects. The Trust believes that because it is focused on the independent power industry without competing business interests and because it seeks to make substantial equity investments in Projects, it has the ability to invest in attractive smaller Projects under these conditions.
In response to the current perceived slowing of electricity demand growth, the prospect of wholesale competition and the relatively higher prices currently payable under some long-term Power Contracts, many electric utilities have refrained from entering into new, long-term Power Contracts with Independent Power Projects and have instead proposed to purchase electricity from Qualifying Facilities or other generators under short-term contracts. Competitive bidding by utilities, governmental units and in states where permitted, large industrial and commercial users for electricity supplies is becoming common. In 1995 and 1996, these competitive solicitations typically attracted large numbers of bids at prices substantially below prior utility prices. Although these solicitations cover a minuscule part of the wholesale market, they indicate that there is currently intense competition to sell new capacity from Independent Power Projects. Certain state regulators, in response to these conditions, have proposed or approved auctions to generating businesses of the rights to supply utilities. In response to these developments, the Trust currently seeks to purchase Projects with existing long-term Power Contracts so as to minimize exposure to volatile short-term markets. There is no assurance that it will be able to acquire those Projects or to do so on favorable terms.
As a consequence of these trends and industry participants' reactions to them, many observers, including utilities, believe that there are temporary, regional surpluses of electric generating capacity. For example, in the spring of 1995, the California public utilities commission projected that the state's three largest utilities would not need additional generating capacity until 2004, and that there was a current small surplus of capacity. It should be noted, however, that the projections also foresaw a rapid increase of demand for capacity in the ten years following 2004. Similarly, on a nationwide level a 1997 estimate forecasted that 71,000 Megawatts of capacity is currently provided by fossil-fuel power plants that are over 30 years old and are approaching the ends of their expected useful lives, that most nuclear power plants are facing relicensing proceedings that normally require extensive reconstruction, and that up to 10% of all U.S. generating capacity may be up for replacement in the next 15 years. Accordingly, one of the most important and difficult questions for determination is whether the current reluctance to finance and build additional generating capacity will lead to capacity shortages on a regional or national basis in the next ten years. Further, as the supply market becomes more fragmented and short-term, regulators and customers are beginning to raise concerns as to the dependability of supply.
Another consequence of the current industry reluctance to commit to long-term increases in capacity and the perceived existence of regional surplus capacity is a short-term orientation on the part of many industry participants. Recently, 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. A few developers and utilities are also considering the construction of "merchant power plants," which would be built without firm Power Contracts in hopes of marketing their output on the anticipated short-term, competitive wholesale or retail markets.
With these conditions in mind, many observers see two primary strategies for Independent Power Projects 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 competitive market. The Trust intends to focus on both possibilities and to maintain a focus on medium-to-long-term results.
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. A number of large natural gas utilities have also acquired or are considering acquiring electric utilities. Industry observers have attributed this to the more entrepreneurial character of the gas industry, which has already been deregulated, and to the fact that natural gas is currently a preferred fuel for generating plants, which may encourage the combination of the fuel suppliers with fuel users to assure supply and reduce uncertainties. These consolidations and acquisitions tend to create additional competitive pressures in the electric power industry; however, this trend is also encouraging the divestiture of smaller Projects or Projects that are deemed less central to the operations of large, consolidated businesses. This may tend to depress the resale value of the Trust's Projects.
5. Competition
There are a large number of participants in the independent power industry. Several large corporations specialize in developing, building and operating Independent Power Projects. Equipment manufacturers, including many of the largest corporations in the world, provide equipment and planning services and provide capital through finance affiliates. Many regulated utilities are preparing for a competitive market, and a significant number of them already have organized subsidiaries or affiliates to participate in unregulated activities such as planning, development, construction and operating services or in owning exempt wholesale generators or up to 50% of Independent Power Projects. In addition, there are many smaller firms whose businesses are conducted primarily on a regional or local basis. Many of these companies focus on limited segments of the cogeneration and independent power industry and do not provide a wide range of products and services. There is significant competition among non-utility producers, subsidiaries of utilities and utilities themselves in developing and operating energy-producing projects and in marketing the power produced by such projects.
The Trust is unable to accurately estimate the number of competitors but believes that there are many competitors at all levels and in all sectors of the industry. Many of those competitors, especially affiliates of utilities and equipment manufacturers, may be far better capitalized than the Trust.
Competition in the energy market is generally not a factor in the current operations of the Trust since its major Projects have entered into long-term agreements to sell their output at specified prices. However, a particular Project could be subject to future competition to market its energy products if its Power Contract expires or is terminated because of a default or failure to pay by the purchasing utility or other purchaser due to bankruptcy or insolvency of the purchaser or because of the failure of a Project to comply with the terms of the Power Contract; regulatory changes; loss of a cogeneration facility's status as a Qualifying Facility due to failure to meet minimum steam output requirements; or other reasons. It is impossible at this time to estimate the level of marketing competition that the Trust would face in any such event.
6. Regulatory Matters.
Projects are subject to energy and environmental laws and regulations at the federal, state and local levels in connection with development, ownership, operation, geographical location, zoning and land use of a Project and emissions and other substances produced by a Project. These energy and environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with such permits and approvals. Since the Trust operates as a "business development company" under the 1940 Act, it is also subject to provisions of that act pertaining to such companies.
(i) Energy Regulation.
(A) PURPA. The enactment in 1978 of PURPA and the adoption of regulations thereunder by FERC provided incentives for the development of cogeneration facilities and small power production facilities meeting certain criteria. Qualifying Facilities under PURPA are generally exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended (the "Holding Company Act"), the Federal Power Act, as amended (the "FPA"), and, except under certain limited circumstances, state laws regarding rate or financial regulation. In order to be a Qualifying Facility, a cogeneration facility must (a) produce not only electricity but also a certain quantity of heat energy (such as steam) which is used for a purpose other than power generation, (b) meet certain energy efficiency standards when natural gas or oil is used as a fuel source and (c) not be controlled or more than 50% owned by an electric utility or electric utility holding company. Other types of Independent Power Projects, 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 Monterey Project, which sells electricity to public utilities, and the San Diego Project, which does not normally sell electricity but which is interconnected with the local electric utility, are Qualifying Facilities. Maintaining the Qualified Facility status of a Project is of utmost importance to the Trust. Such status may be lost if a Project does not meet the operational requirements of PURPA, such as minimum operating efficiency standards and minimum use of thermal energy by customers of a cogeneration Project. The Trust endeavors to comply with these requirements, but there can be no assurance that a Project will maintain its Qualified Facility status. If a Project loses its Qualifying Facility status, the utility can reclaim payments it made for the Project's non-qualifying output to the extent those payments are in excess of current avoided costs (which are generally substantially below the Power Contract rates) or the Project's Power Contract can be terminated by the electric utility. In California, the state regulator has authorized a comprehensive monitoring system under which electric utilities continuously meter a Project's performance. Many California utilities, including Pacific Gas and Electric Company, the utility that purchases the Monterey Project's electric output, aggressively use this data to press for termination of Qualifying Facility status, and there is an ongoing risk that the utility will assert that the Project does not qualify for any given year. The Trust believes that the Monterey Project has qualified and will qualify. The other Projects do not sell electricity to utilities or off-site customers; therefore, they need not be Qualifying Facilities.
(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.
(D) Fuel Use Act. Projects may also be subject to the Fuel Use Act, which limits the ability of power producers to burn natural gas in new generation facilities unless such facilities are also coal capable within the meaning of the Fuel Use Act. The Trust believes that the San Diego and Monterey Projects are coal capable and thus qualify for exemption from the Fuel Use Act.
(E) State Regulation. State public utility regulatory commissions have broad jurisdiction over Independent Power Projects which are not Qualifying Facilities under PURPA, and which are considered public utilities in many states. In states where the wholesale or retail electricity market remains regulated, Projects that are not Qualifying Facilities may be subject to state requirements to obtain certificates of public convenience and necessity to construct a facility and could have their organizational, accounting, financial and other corporate matters regulated on an ongoing basis. Although FERC generally has exclusive jurisdiction over the rates charged by a non-Qualifying Facility to its wholesale customers, state public utility regulatory commissions have the practical ability to influence the establishment of such rates by asserting jurisdiction over the purchasing utility's ability to pass through the resulting cost of purchased power to its retail customers. In addition, states may assert jurisdiction over the siting and construction of non-Qualifying Facilities and, among other things, issuance of securities, related party transactions and sale and transfer of assets. The actual scope of jurisdiction over non-Qualifying Facilities by state public utility regulatory commissions varies from state to state.
(ii) Environmental Regulation.
The construction and operation of Independent Power Projects 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 and there is no assurance that a market for such allowances will develop. Projects fueled by natural gas are not expected to be materially burdened by the acid rain provisions of the Clean Air Act Amendments.
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.
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 not developed expertise and experience in obtaining necessary licenses, permits and approvals, which will be the responsibility of each Project's managers and Project Sponsors. 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 February 27, 1993, the Trust notified the Securities and Exchange Commission (the "Commission") of its election to be a "business development company" and registered its Shares under the 1934 Act. On April 29, 1993, the election and registration became effective. As a "business development company," the Trust is a closed-end company (defined by the 1940 Act as a company that does not offer for sale or have outstanding any redeemable security) that is regulated under the 1940 Act only as a business development company. The act contains prohibitions and restrictions on transactions between business development companies and their affiliates as defined in that act, and requires that a majority of the board of the company be persons other than "interested persons" as defined in the act. The board of the Trust is comprised of Ridgewood Power and two individuals, Ralph O. Hellmold and Jonathan C. Kaledin, who also serve as independent trustees of Ridgewood Electric Power Trust III, and who are Independent Panel Members for Ridgewood Electric Power Trust V but who are not otherwise affiliated with the Trust, Ridgewood Power or any of their affiliates. See Item 10 - Directors and Executive Officers of the Registrant.
Under the 1940 Act, Commission approval is required for certain transactions involving certain closely affiliated persons of business development companies, including many transactions with the Managing Shareholder and the other investment programs sponsored by the Managing Shareholder. There can be no assurance that such approval, if required, would be obtained. In addition, a business development company may not change the nature of its business so as to cease to be, or to withdraw its election as, a business development company unless authorized to do so by at least a majority vote of its outstanding voting securities.
The 1940 Act restricts the kind of investments a business development company may make. A business development company may not acquire any asset other than a "Qualifying Asset" unless, at the time the acquisition is made, Qualifying Assets comprise at least 70% of the company's total assets by value. The principal categories of Qualifying Assets that are relevant to the Trust's activities are:
(A) Securities issued by "eligible portfolio companies" that are purchased by the Trust from the issuer in a transaction not involving any public offering (i.e., private placements of securities). An "eligible portfolio company" (1) must be organized under the laws of the United States or a state and have its principal place of business in the United States; (2) may not be an investment company other than a small business investment company licensed by the Small Business Administration and wholly-owned by the Trust and (3) may not have issued any class of securities that may be used to obtain margin credit from a broker or dealer in securities. The last requirement essentially excludes all issuers that have securities listed on an exchange or quoted on the National Association of Securities Dealers, Inc.'s national market system, along with other companies designated by the Federal Reserve Board. Except for temporary investments of the Trust's available funds, substantially all of the Trust's investments are expected to be Qualifying Assets under this provision.
(B) Securities received in exchange for or distributed on or with respect to securities described in paragraph (A) above, or on the exercise of options, warrants or rights relating to those securities.
(C) Cash, cash items, U.S. Government securities or high quality debt securities maturing not more than one year after the date of investment.
A business development company must make available "significant managerial assistance" to the issuers of Qualifying Assets described in paragraphs (A) and (B) above, which may include without limitation arrangements by which the business development company (through its directors, officers or employees) offers to provide (and, if accepted, provides) significant guidance and counsel concerning the issuer's management, operation or business objectives and policies.
A business development company also must be organized under the laws of the United States or a state, have its principal place of business in the United States and have as its purpose the making of investments in Qualifying Assets described in paragraph (A) above.
The Managing Shareholder believes that it may no longer be necessary for the Trust to continue its status as a business development company, because of the Managing Shareholder's active involvement in operating Projects through the Trust and other investment programs. Although the Managing Shareholder believes it would be beneficial to the Trust to end the election and reduce costs of legal compliance that do not contribute to income, the process of withdrawing the business development company election requires a proxy solicitation and a special vote of investors, which is also costly. Accordingly, the Managing Shareholder does not intend at this time to request the Investors' consent to withdrawing the business development company election. Any change in the Trust's status will be effected only with the Investors' consent.
(iv) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are subject to amendment or repeal. Future legislation and regulation is uncertain, and could have material effects on the Trust.
(d) Financial Information about Foreign and Domestic Operations and Export Sales.
The Trust has invested in Projects located in California, Massachusetts and New York and has no foreign operations.
(e) Employees.
The employees of the Monterey and Sunkist Projects have been transferred to RPMC and accordingly the Trust has no employees. The persons described below at Item 10. Directors and Executive Officers of the Registrant serve as executive officers of the Trust and have the duties and powers usually applicable to similar officers of a Delaware corporation in carrying out the Trust business.
Item 2.
Item 2. Properties.
Pursuant to the Management Agreement between the Trust and the Managing Shareholder (described at Item 10(c) - Directors and Executive Officers of the Registrant - Management Agreement), the Managing Shareholder provides the Trust with office space at the Managing Shareholder's principal office at The Ridgewood Commons, 947 Linwood Avenue, Ridgewood, New Jersey 07450.
The following table shows the material properties (relating to Projects) owned or leased by the Trust's subsidiaries or partnerships in which the Trust has an interest. Ownership rights to the property associated with the Berkshire Project are held under a long-term lease-purchase agreement and related non- recourse industrial revenue bond financing agreements among the City of Pittsfield's industrial development authority and others. Upon repayment of the bonds and the satisfaction of other conditions, the partnership which operates the facility and in which the Trust owns an interest, will have the option to acquire the facility for nominal consideration. The other properties are not subject to any mortgages, liens or encumbrances. All of the Projects are described in further detail at Item 1(c)(2).
Approximate Square Ownership Ground Approximate Footage of Description Interests Lease Acreage Project (Actual of Project Location in Land Expiration of Land or Projected) Project
Berkshire Pittsfield, Massachusetts Leased 2004 5 30,000 Waste-to- energy facility in operation San Diego San Diego, California Leased 2023 .3 12,000 Gas-fired power facility in operation which produces chilled water for customers' office building central air conditioning systems Columbia Columbia, New York Owned __ 44 25,000 Municipal waste transfer station in operation Monterey Monterey, California Leased 2021 2 10,000 Gas-fired cogeneration facility Sunkist Ventura Leased N/A N/A N/A Natural County, or gas fired California licensed engines powering irrigation pumps located on various farms
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 did not submit any matters to a vote of the Investors during the fourth quarter of 1996. PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
(a) Market Information.
The Trust sold 235.3775 Investor Shares of beneficial interest in the Trust in its private placement offering of Investor Shares which closed on January 31, 1994. There is currently no established public trading market for the Investor Shares and the Trust does not intend to allow a public trading market to develop. As of the date of this Form 10-K, all such Investor Shares have been issued and are outstanding. There are no outstanding options or warrants to purchase, or securities convertible into, Investor Shares and the Trust has no intention to make any public offering of Investor Shares.
Investor Shares are restricted as to transferability under the Declaration, and are restricted under federal and state laws regulating securities when the Investor Shares are held by persons in a control relationship with the Trust. Investors wishing to transfer Shares should also consider the applicability of state securities laws. The Investor Shares have not been and are not expected to be registered under the Securities Act of 1933, as amended (the "1933 Act"), or under any other similar law of any state in reliance upon what the Trust believes to be exemptions from the registration requirements contained therein. Because the Investor Shares have not been registered, they are "restricted securities" as defined in Rule 144 under the 1933 Act.
(b) Holders
As of the date of this Form 10-K, there are 479 record holders of Investor Shares.
(c) Dividends
The Trust made distributions as follows for the years 1994 through 1996:
Year ended Year ended Year ended December 31, December 31, December 31, 1996 1995 1994
Total distributions to Investors $2,082,754 $2,457,231 $1,243,907 Distributions per Investor Share 8,924 10,450 5,285 Distributions to Managing Shareholder $21,037 24,807 11,626
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 15% of their Capital Contributions to the Trust. Because the Trust's objective is to distribute net cash flow, a substantial portion of many distributions will include cash flow that represents depreciation and amortization charges against assets at the Project level. Nevertheless, because the Projects are not consolidated with the Trust for accounting purposes, all funds received from Projects are considered to be revenue to the Trust for accounting purposes. Occasionally, distributions may also include funds derived from operating or debt service reserves, Trust-level depreciation or amortization, or other non-cash charges against earnings. 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.
Supplemental Information As of and As of and As of and As of and Schedule for the for the for the for the Selected Financial Data Year Ended Year Ended Year Ended Year Ended December 31, December 31, December 31, December 31, 1996 1995 1994 1993
Total Fund Information: Net revenue from operating projects $2,371,208 $2,696,578 $916,588 $0 Net income (loss) 1,970,401 2,149,184 (1,698,844) (444,284) Net assets (shareholders' equity) 16,353,759 16,477,149 16,760,003 15,163,680 Investments in Project development and power generation limited partnerships 16,116,582 16,056,151 9,236,653 1,443,119 Total assets 16,466,241 16,521,944 16,791,571 15,792,506 Per Investor Share: Revenues $10,076 $11,456 $3,894 $397 Expenses 1,705 2,473 12,368 (2,285) Net income (loss) 8,371 9,131 $(7,218) $(1,888) Net asset value 69,639 70,158 $71,345 $64,380 Distributions to Investors $8,849 $10,440 $5,285 $0
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with the Trust's financial statements and the notes thereto presented elsewhere herein.
Results of Operations.
Income of the Trust from Projects was as follows:
Project 1996 1995 1994 Berkshire $351,451 $446,888 $481,588 Columbia 515,000 510,000 0 San Diego 618,080 1,027,412 435,000 Monterey 757,498 606,536 0 Sunkist 129,179 105,742 0
12 months ended December 31, 1996 versus 12 months ended December 31, 1995
Net income for 1996 was $1,970,000, which was $179,000 (8.3%) less than the $2,149,000 recorded in 1995. There was a $360,000 decline in revenues (13.2%) from 1995 to 1996, which was partially offset by a $181,000 (31.1%) decrease in Trust expenses from 1996 to 1995.
The decline in revenues was primarily the result of a $409,000 (39.8%) decrease in distributions from the San Diego Project. A major customer, the old San Diego County Courthouse was closed in early 1996 and replacement customers have not been obtained, although the Project is in active discussions with several office building owners and developers. Cool summer weather also reduced demand. The Trust's other Projects had mixed results. The Berkshire Project's distributions declined $95,000, reflecting its management's decision to retain cash flow at the Project level to fund capital expenditures, while increases in operating efficiencies and preventative maintenance caused the Monterey Project's distributions to increase by $51,000. The Columbia and Sunkist Projects' distributions remained approximately level. Because substantially all Trust cash flow was distributed, interest and dividend income was nominal in 1996.
The major element of the decline in Trust expenses was a $165,000 (33.4%) decrease in the management fee caused by the Managing Shareholder's decision to waive a portion of its fees. Accounting and legal expenses fell by $27,000 (45.6%), although adoption of a comprehensive insurance program caused insurance expenses to increase by $22,000 (608.4%).
12 months ended December 31, 1995 versus 12 months ended December 31, 1994. Net income for calendar 1995 was $2,149,000 as compared to a net loss of $1,699,000 for 1994. The improvement came from both revenue and expense items. Gross revenue increased $1,520,000 (125.3%) as Trust investments were acquired and began earning income, while operating expenses decreased by $2,329,000 (80.0%) as expenditures for project due diligence ended and no additional writedowns of Trust assets were incurred. Income from Projects rose by 194.2% from 1994 to 1995, as the Trust enjoyed a full year of income from the Columbia and San Diego Projects (which were acquired in 1994) and the Monterey and Sunkist Projects were acquired. Interest and dividend revenues in 1995 decreased by 93.8%, attributable to the application of the Trust's remaining uninvested funds to purchasing the Monterey and Sunkist Projects. The 80.0% decrease in operating expenses was primarily caused by a $510,000 decrease (97.5%) in due diligence expenses for Project investments, which reflects the conclusion of the Trust's investment program. No writedowns were recorded in 1995, as opposed to $1,697,000 in 1994. No investment fee was charged in 1995 because the Trust's offering had concluded, which resulted in a $59,000 decrease in expenses. Equipment storage also decreased by $55,000 as purchased equipment was installed and left storage, and insurance costs decreased by $9,000 as the result of a consolidation of coverage.
Liquidity and Capital Resources.
The Trust has completed the investment of its funds and does not contemplate that it will make any significant capital investments from Trust-level funds in 1997. However, significant capital improvements, which are being financed from Project cash flow, are underway at the Berkshire Project to improve ash handling and allow use of ash as aggregate for concrete block production. The Trust is also considering expansions to the San Diego Project in order to extend its lines to additional customers and possibly to increase capacity, but no decision has been made to do so. The Trust may also undertake additional repairs to and improvements to the Monterey Project as may be determined by an engineering study in progress, and routine maintenance expenses for the San Diego Project. The Trust expects to fund these from cash reserves or current operating cash flow.
The Trust anticipates that its cash flow during 1997 will be adequate to fund its obligations. In the event that there is an unanticipated need for working capital or for repairs or replacement of equipment, the Managing Shareholder has also obtained a credit line of $500,000 from a bank, which it intends to make available for those purposes to the Trust or other programs the Managing Shareholder is sponsoring. The Managing Shareholder will not impose charges for use of that line in excess of those charged to it by the bank.
Trends affecting Results of Operations.
In addition to the industry trends discussed above at Item 1(c)(4) - Business --Trends in the Electric Utility and Independent Power Industries, as described above several of the Trust's Projects are experiencing significant pressures on their profitability and operations. Recent increases in natural gas prices during the winter months of 1996 and early 1997 impaired profitability at the Monterey, Sunkist and San Diego Projects, although prices began to fall toward prior levels in February 1997. The Managing Shareholder is considering entering into long-term gas supply arrangements to reduce exposure to these fluctuations, but the relatively small size of each Project may limit its ability to do so.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Report of Independent Accountants Statement of Operations For the Three Years Ended December 31, 1996 Balance Sheet at December 31, 1996 and 1995 Statement of Changes in Shareholders' Equity For the Three Years Ended December 31, 1996 Statement of Cash Flows For the Three Years Ended December 31, 1996 Notes to Financial Statements to
All schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
The financial statements are presented in accordance with generally accepted accounting principles and Securities and Exchange Commission positions applicable to business investment companies, which require the Trust's investments in Projects to be presented on the cash method, rather than on the equity method.
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 III ("Ridgewood Power III"), Ridgewood Electric Power Trust IV ("Ridgewood Power IV") and Ridgewood Electric Power Trust V ("Ridgewood Power V") 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 12 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.
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 50, has also served as President of the Trust since its inception in November 1992 and as President of RPMC, Ridgewood Power I, Ridgewood Power III, Ridgewood Power IV and Ridgewood Power V, since their respective inceptions. Mr. Swanson has been President, registered principal, sole director and sole stockholder of Ridgewood Securities Corporation, the Placement Agent for the private placement offerings of those four trusts. In addition, he has been President, sole director 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 38, has served as Executive Vice President of the Managing Shareholder, RPMC, Ridgewood Power I, the Trust, Ridgewood Power III, Ridgewood Power IV and Ridgewood Power V since their respective inceptions, with primary responsibility for marketing and acquisitions. 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 42, 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 five trusts in October 1996. Mr. Brown has over 19 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 48, 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, Mr. Quinn will devote a majority of his time to the business of the Managing Shareholder and RPMC while continuing his other activities, which are expected to conclude in the spring of 1997. Thereafter, he expects to become a full-time officer of the Managing Shareholder and RPMC.
Mr. Quinn has 27 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 44, has served as Vice President of the Managing Shareholder, RPMC, the Trust, Ridgewood Power I, Ridgewood Power III and Ridgewood Power IV 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, 1998 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 principal officers of the Trust are identical to those of the Managing Shareholder. The officers have the duties and powers usually applicable to similar officers of a Delaware business corporation in carrying out Trust business. Officers act under the supervision and control of the Managing Shareholder, which is entitled to remove any officer at any time. Unless otherwise specified by the Managing Shareholder, the President of the Trust has full power to act on behalf of the Trust. The Managing Shareholder expects that most actions taken in the name of the Trust will be taken by Mr. Swanson and the other principal officers in their capacities as officers of the Trust under the direction of the Managing Shareholder rather than as officers of the Managing Shareholder.
(e) The Trustees.
The 1940 Act requires the Independent Trustees to be individuals who are not "interested persons" of the Trust as defined under the 1940 Act (generally, persons who are not affiliated with the Trust or with affiliates of the Trust). There must always be at least two Independent Trustees; a larger number may be specified by the Board from time to time. Each Independent Trustee has an indefinite term. Vacancies in the authorized number of Independent Trustees will be filled by vote of the remaining Board members so long as there is at least one Independent Trustee; otherwise, the Managing Shareholder must call a special meeting of Investors to elect Independent Trustees. Vacancies must be filled within 90 days. An Independent Trustee may resign effective on the designation of a successor and may be removed for cause by at least two-thirds of the remaining Board members or with or without cause by action of the holders of at least two-thirds of Shares held by Investors. Under the Declaration, the Independent Trustees are authorized to act only where their consent is required under the 1940 Act and to exercise a general power to review and oversee the Managing Shareholder's other actions. They are under a fiduciary duty similar to that of corporation directors to act in the Trust's best interest and are entitled to compel action by the Managing Shareholder to carry out that duty, if necessary, but ordinarily they have no duty to manage or direct the management of the Trust outside their enumerated responsibilities.
The Independent Trustees of the Trust are Ralph O. Hellmold and Jonathan C. Kaledin. Set forth below is certain information concerning Mr. Hellmold and Mr. Kaledin, who also serve as independent trustees of Ridgewood Power III and as independent panel members of Ridgewood Power V. Both are independent power programs sponsored by Ridgewood Power. Independent panel members must approve transactions between their program and the Managing Shareholder or companies affiliated with the Managing Shareholder, but have no other responsibilities. Neither Mr. Hellmold nor Mr. Kaledin is otherwise affiliated with the Trust, any of the Trust's officers or agents, the Managing Shareholder, any other Trustee, any affiliates of the Managing Shareholder and any other Trustees, or any director, officer or agent of any of the foregoing. Mr. Hellmold made a late filing in March 1997 under Section 16 of the 1934 Act to report director status and beneficial ownership of Investor Shares.
Ralph O. Hellmold, age 56, is founder, sole shareholder and President of Hellmold Associates, Inc., an investment banking firm, broker-dealer and investment adviser specializing in working with troubled companies or their creditors to raise capital, divest businesses and restructure liabilities, whether in or outside bankruptcy. Other financial advisory services provided by Hellmold Associates, Inc. include mergers and acquisitions advice, valuations, fairness opinions and expert witness testimony. In addition to working with troubled companies or their creditors, Hellmold Associates, Inc. also acts as general partner of funds which invest in the securities of financially distressed companies.
From 1987 to 1990, when he formed Hellmold Associates, Inc., Mr. Hellmold was a Managing Director at Prudential-Bache Capital Funding, where he served as co-head of the Corporate Finance Group, co-head of the Investment Banking Committee and head of the Financial Restructuring Group. From 1974 to 1987, Mr. Hellmold was a partner at Lehman Brothers and its successors, where he worked in the General Corporate Finance Group and co-founded the Financial Restructuring Group. Prior thereto, he was a research analyst at Lehman Brothers and at Francis I. du Pont & Company. He received his undergraduate degree magna cum laude from Harvard College and an M.I.A. from Columbia University. He is a Chartered Financial Analyst and a member of the New York Society of Security Analysts. Mr. Hellmold is the holder of one-half share in each of Ridgewood Power I and Ridgewood Power III, a shareholder of one-half Share in the Trust and a limited partner or shareholder in numerous limited partnerships and a business trust sponsored by Ridgewood Energy to invest in oil and gas development and related businesses. Mr. Hellmold is a director of Core Materials Corporation, Columbus, Ohio.
Jonathan C. Kaledin, age 38, has been New York Regional Counsel of The Nature Conservancy, the international land conservation organization, since September 1995. From 1990 to June 1995, he was founder and Executive Director of the National Water Funding Council ("NWFC"), an advocacy and public affairs organization representing municipalities, businesses, financial institutions and others on federal Clean Water Act and Safe Drinking Water Act funding issues. Prior to forming the NWFC in 1990, Mr. Kaledin was an attorney with the Boston law firm of Wright & Moehrke. There he specialized in wetlands, water, environmental review, zoning and hazardous and solid waste matters, representing clients in state and federal court and before state and federal agencies and local boards and commissions. From 1987 through 1990, Mr. Kaledin was Assistant Regional Counsel for the New England office of the Environmental Protection Agency ("EPA"). His responsibilities at the EPA included administrative and judicial environmental enforcement under the Clean Water Act and other federal water protection legislation. Mr. Kaledin received his undergraduate degree magna cum laude from Harvard College and a law degree from New York University.
The Corporate Trustee of the Trust is Ridgewood Holding. Legal title to Trust Property is now and in the future will be in the name of the Trust, if possible, or Ridgewood Holding as trustee. Ridgewood Holding is also a trustee of Ridgewood Power I, Ridgewood Power III, Ridgewood Power IV and Ridgewood Power V and of an oil and gas business trust sponsored by Ridgewood Energy and is expected to be a trustee of other similar entities that may be organized by the Managing Shareholder and Ridgewood Energy. The President, sole director and sole stockholder of Ridgewood Holding is Robert E. Swanson; its other executive officers are identical to those of the Managing Shareholder. See - -- Managing Shareholder. The principal office of Ridgewood Holding is at 1105 North Market Street, Suite 1300, Wilmington, Delaware 19899.
The Trustees are not liable to persons other than Shareholders for the obligations of the Trust.
The Trust has relied and will continue to rely on the Managing Shareholder and engineering, legal, investment banking and other professional consultants (as needed) and to monitor and report to the Trust concerning the operations of Projects in which it invests, to review proposals for additional development or financing, and to represent the Trust's interests. The Trust will rely on such persons to review proposals to sell its interests in Projects in the future.
(f) Section 16(a) Beneficial Ownership Reporting Compliance
Mr. Brown and Mr. Quinn did not file on a timely basis as required by section 16(a) of the 1934 Act Forms 3 reporting their status as officers or directors of the Trust and their beneficial ownership. Each person made one late filing of Form 3 in December 1996. The number of transactions that were not reported on a timely basis by each of these persons was zero.
(g) RPMC.
As discussed above at Item 1 - Business, RPMC has assumed day-to-day management responsibility for the Monterey and Sunkist Projects, effective January 1, 1996 and has assumed certain responsibilities for the San Diego Project. Like the Managing Shareholder, RPMC is wholly owned by Robert E. Swanson. It has entered into an "Operation Agreement" with certain of the Trust's subsidiaries, effective January 1, 1996, under which RPMC, under the supervision of the Managing Shareholder, will provide the management, purchasing, engineering, planning and administrative services for those Projects that were previously furnished by employees of the Trust or by unaffiliated professionals or consultants and that were borne by the Trust or Projects as operating expenses. To the extent that those services were provided by the Managing Shareholder and related directly to the operation of the Project, RPMC will charge the Trust at its cost for these services and for the Trust's allocable amount of certain overhead items. RPMC will share 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, although it may be authorized to act on behalf of the subsidiaries that own Projects.
The Operation Agreement does not have a fixed term and is terminable by RPMC, by the Managing Shareholder or by vote of a majority of interest of Investors, on 60 days' prior notice. The Operation Agreement may be amended by agreement of the Managing Shareholder and 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 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), Joseph A. Heyison, General Counsel, and Douglas V. Liebschner, Vice President - Operations. Mr. Heyison, age 42, 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.
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 the Managing Shareholder's business. In 1996 and future years, the Managing Shareholder will compensate these persons without additional payments by the Trust and will be reimbursed by Ridgewood Energy for costs related to Ridgewood Energy's business. The Trust will reimburse RPMC at allocable cost for services provided by RPMC's employees. Information as to the fees payable to the Managing Shareholder and certain affiliates is contained at Item 13 -- Certain Relationships and Related Transactions.
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 1996 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 Trust sold 235.3775 Investor Shares (approximately $23.5 million of gross proceeds) of beneficial interest in the Trust pursuant to a private placement offering under Rule 506 of Regulation D under the Securities Act. The offering closed on January 31, 1994. Further details concerning the offering are set forth above at Item 1 -- Business.
The Managing Shareholder purchased for cash in the offering 1.45 Investor Shares (.6 of 1% of the outstanding Investor Shares). Ralph O. Hellmold, an Independent Trustee of the Trust, purchased for cash in the offering one-half of a full Investor Share. By virtue of their purchases of Investor Shares, the Managing Shareholder and Mr. Hellmold are entitled to the same ratable interest in the Trust as all other purchasers of Investor Shares. No other Trustees or executive officers of the Trust acquired Investor Shares in the Trust's offering.
The Managing Shareholder was issued one Management Share in the Trust representing the beneficial interests and management rights of the Managing Shareholder in its capacity as such (excluding its interest in the Trust attributable to Investor Shares it acquired in the offering). Addtional information concerning the management rights of the Managing Shareholder is at Item 1 - Business and at Item 10 -- Directors and Executive Officers of the Registrant. Its beneficial interest in cash distributions of the Trust and its allocable share of the Trust's net profits and net losses and other items attributable to the Management Share are described in further detail below at Item 13
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable reserves which the Trust deems necessary to cover anticipated Trust expenses, is to be distributed to the Investors and the Managing Shareholder (collectively, the "Shareholders"), from time to time as the Trust deems appropriate. Prior to Payout (the point at which Investors have received cumulative distributions equal to the amount of their capital contributions), each year all distributions from the Trust, other than distributions of the revenues from dispositions of Trust Property, are to be allocated 99% to the Investors and 1% to the Managing Shareholder until Investors have been distributed during the year an amount equal to 15% of their total capital contributions (a "15% Priority Distribution"), and thereafter all remaining distributions from the Trust during the year, other than distributions of the revenues from dispositions of Trust Property, are to be allocated 80% to Investors and 20% to the Managing Shareholder. Revenues from dispositions of Trust Property are to be distributed 99% to Investors and 1% to the Managing Shareholder until Payout. In all cases, after Payout, Investors are to be allocated 80% of all distributions and the Managing Shareholder 20%.
For any fiscal period, the Trust's net profits, if any, other than those derived from dispositions of Trust Property, are allocated 99% to the Investors and 1% to the Managing Shareholder until the profits so allocated offset (1) the aggregate 15% Priority Distribution to all Investors and (2) any net losses from prior periods that had been allocated to the Shareholders. Any remaining net profits, other than those derived from dispositions of Trust Property, are allocated 80% to the Investors and 20% to the Managing Shareholder. If the Trust realizes net losses for the period, the losses are allocated 80% to the Investors and 20% to the Managing Shareholder until the losses so allocated offset any net profits from prior periods allocated to the Shareholders. Any remaining net losses are allocated 99% to the Investors and 1% to the Managing Shareholder. Revenues from dispositions of Trust Property are allocated in the same manner as distributions from such dispositions. Amounts allocated to the Investors are apportioned among them in proportion to their capital contributions.
On liquidation of the Trust, the remaining assets of the Trust after discharge of its obligations, including any loans owed by the Trust to the Shareholders, will be distributed, first, 99% to the Investors and the remaining 1% to the Managing Shareholder, until Payout, and any remainder will be distributed to the Shareholders in proportion to their capital accounts.
In 1995, 1994 and 1993, the Trust made distributions to the Managing Shareholder (which is a member of the Board of the Trust) as stated at Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters. In addition, the Trust paid fees to the Managing Shareholder and its affiliates as follows:
Fee Paid to 1996 1995 1994 1993 Management Managing fee Shareholder $328,952 $494,000 $495,000 $0 Cost reimburse- ments* RPMC 1,207,252 0 0 0 Investment Managing fee Shareholder 0 0 59,000 388,000 Placement Ridgewood agent fee Securities and sales Corporation commissions 0 0 4,000 245,000 Organizational, Managing distribution Shareholder and offering fee 0 0 149,000 1,014,000
* Prior to 1996, these costs were either absorbed by the Trust or by the Projects directly. These include all payroll, fuel and other expenses of operating Projects that are not operated by non-affiliated managers, and an allocation of RPMC's overhead costs.
The investment fee equaled 2% of the proceeds of the offering of Investor Shares and was payable for the Managing Shareholder's services in investigating and evaluating investment opportunities and effecting investment transactions. The placement agent fee (1% of the offering proceeds) and sales commissions were also paid from proceeds of the offering, as was the organizational, distribution and offering fee (5% of offering proceeds) for legal, accounting, consulting, filing, printing, distribution, selling, closing and organization costs of the offering.
The management fee, payable monthly under the Management Agreement at the annual rate of 2.5% of the Trust's net asset value, began on the date the first Project was acquired and compensates the Managing Shareholder for certain management, administrative and advisory services for the Trust.
In addition to the foregoing, the Trust reimbursed the Managing Shareholder at cost for expenses and fees of unaffiliated persons engaged by the Managing Shareholder for Trust business and in years before 1996 for payroll and other costs of operation of the Monterey and Sunkist Projects. 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(f) - 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 Forms 8-K were filed with the Commission by the Registrant during the quarter ending December 31, 1996.
(c) Exhibits
3A. Certificate of Trust of the Registrant, is incorporated by reference to Exhibit 3A to the Registrant's Registration Statement on Form 10 filed with the Commission on February 27, 1993.
3B. Amended and Restated Declaration of Trust of the Registrant, is incorporated by reference to Exhibit 4 to the Quarterly Report on Form 10Q of the Registrant for the quarter ended September 30, 1993.
10A. Management Agreement dated as of January 4, 1993 between the Registrant and Ridgewood Power Corporation, is incorporated by reference to Exhibit 10 to the Registrant's Registration Statement on Form 10 filed with the Commission on February 27, 1993.
10B. Limited Partnership Agreement of Pittsfield Investors Limited Partnership (without exhibits), is incorporated by reference to Exhibit 2(i) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10C. Asset Purchase Agreement between EAC Systems, Inc. and Vicon Recovery Associates ("Vicon") dated as of December 23, 1992 (the "Asset Purchase Agreement") (without exhibits), is incorporated by reference to Exhibit 2(ii) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10D. First Amendment of Asset Purchase Agreement dated as of December 30, 1993 (without exhibits), is incorporated by reference to Exhibit 2(ii) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10E. Lease dated as of September 1, 1979 between the City of Pittsfield, Massachusetts (acting by and through its Industrial Development Financing Authority), is incorporated by reference to Exhibit 2(iv) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10F. Amended and Restated Solid Waste Disposal and Resource Recovery Agreement dated August 6, 1979 by and among the City of Pittsfield, Vicon and others (together with amendments dated October 26, 1984, July 28, 1989 and December 29, 1993), is incorporated by reference to Exhibit 2(v) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10G. Steam Purchase Agreement by and between Crane & Co., Inc. and Vicon dated as of February 1, 1979 (with amendments), is incorporated by reference to Exhibit 2(vi) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10H. Asset Purchase Agreement dated as of December 15, 1993 between San Diego Central Cooling Company ("SDCCC") and RSD Power Partners, L.P. is incorporated by reference to Exhibit 10M to the Form 10K of Registrant filed with the Commission on March 30, 1994.
10I. RSD Power Partners, L.P. Agreement of Limited Partnership dated as of January 7, 1994 is incorporated by reference to Exhibit 10N to the form 10K of Registrant filed with the Commission on March 30, 1994.
10J. Lease dated June 7, 1983 between San Diego Gas & Electric Company ("SDG&E") and Applied Energy, Incorporated ("AEI") is incorporated by reference to Exhibit 10O to the Form 10K of Registrant filed with the Commission on March 30, 1994.
10K. Assignment and Consent among AEI, Energy Factors, Incorporated, SDCCC and SDG&E is incorporated by reference to Exhibit 10P to the form 10K of Registrant filed with the Commission on March 30, 1994.
10L. Memorandum and Lease and Assignment of Lease dated as of July 3, 1989 among SDG&E, AEI and SDCCC is incorporated by reference to Exhibit 10Q to the form 10K of Registrant filed with the Commission on March 30, 1994.
10M. Letter Agreement dated July 7, 1989 between Energy Factors Incorporated and SDG&E is incorporated by reference to Exhibit 10R to the form 10K of Registrant filed with the Commission on March 30, 1994.
10N. Acquisition Agreement dated as of January 9, 1995 among Sunnyside Cogen, Inc., and NorCal Sunnyside Inc., as Sellers, and RW Monterey, Inc. and Ridgewood Electric Power Trust II, as Purchasers, is incorporated by reference to Exhibit 2(i) to the Form 8K of Registrant filed with the Commission on February 16, 1995.
10O. Acquisition Agreement, dated as of March 31, 1995, by and among the Trust and its subsidiary, Pump Services Corporation, as purchasers and Donald C. Stewart, Union Energy Corp. and Donald A. Sherman as sellers. Incorporated by reference to Exhibit 10O to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 1995.
21. Subsidiaries of the Registrant. Incorporated by reference to Exhibit 21 to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 1996.
24. Powers of Attorney Page 72
27. Financial Data Schedule Page 73
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Signature Title Date
RIDGEWOOD ELECTRIC POWER TRUST II (Registrant)
By: /s/Robert E. Swanson President and Chief April 14, 1997 Robert E. Swanson Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
By: /s/Robert E. Swanson President and Chief April 14, 1997 Robert E. Swanson Executive Officer
By: /s/Martin V. Quinn Senior Vice President April 15, 1997 Martin V. Quinn and Chief Financial Officer
By: /s/Kathleen P. McSherry Controller April 15, 1997 Kathleen P. McSherry
RIDGEWOOD POWER CORPORATION Managing Shareholder April 14, 1997
By: /s/Robert E. Swanson President Robert E. Swanson
/s/Robert E. Swanson * Independent Trustee April 14, 1997 Ralph O. Hellmold
/s/Robert E. Swanson * Independent Trustee April 14, 1997 	Jonathan C. Kaledin
* Robert E. Swanson, as attorney-in-fact for the Independent Trustee
Ridgewood Electric Power Trust II
Financial Statements
December 31, 1996, 1995 and 1994
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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
March 24, 1997
To the Shareholders and Trustees of Ridgewood Electric Power Trust II
In our opinion, the accompanying balance sheet and the related statements of operations, changes in shareholders' equity and of cash flows present fairly, in all material respects, the financial position of Ridgewood Electric Power Trust II at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Trust's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As explained in Note 4, the financial statements include investments, valued at $16,116,582 and $16,056,151 (99% and 97% of shareholders' equity, respectively) as of December 31, 1996 and 1995, respectively, whose values have been estimated by management in the absence of readily ascertainable market values. We have reviewed the procedures used by management in arriving at their estimate of value and have inspected underlying documentation, and, in the circumstances, we believe the procedures are reasonable and the documentation appropriate. However, because of the inherent uncertainty of valuation, those estimated values may differ significantly from the values that would have been used had a ready market for the investments existed, and the differences could be material to the financial statements.
/s/ Price Waterhouse LLP -F2-
Ridgewood Electric Power Trust II Statement of Operations
Year Ended Year Ended Year Ended December 31, December 31, December 31, 1996 1995 1994
Revenue: Income from power generating projects $ 2,371,208 $ 2,696,578 $ 916,588 Interest and dividend income 540 18,401 295,623 Other income --- 16,325 ---
2,371,748 2,731,304 1,212,211
Expenses: Investment fee --- --- 59,400 Project due diligence costs --- 13,068 523,104 Management fee 328,952 494,023 494,820 Equipment storage costs --- 1,755 56,700 Accounting and legal fees 31,750 58,331 54,698 Insurance 25,501 3,600 12,450 Writedown of limited partnership investments --- --- 1,397,350 Writedown of electric power equipment --- --- 299,940 Miscellaneous 15,144 11,343 12,593
401,347 582,120 2,911,055
Net income (loss) $ 1,970,401 $ 2,149,184 $ (1,698,844)
Allocation to: Shareholders $ 1,950,697 $ 2,127,692 $ (1,681,856) Managing shareholder 19,704 21,492 (16,988) $ 1,970,401 $ 2,149,184 $ (1,698,844)
See accompanying notes to financial statements.
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Ridgewood Electric Power Trust II Balance Sheet
Year Ended December 31, 1996 1995
Assets:
Investments in project development and power generation projects $ 16,116,582 $ 16,056,151 Cash and cash equivalents --- 101,975 Electric power equipment 331,018 331,018 Other assets 18,641 32,800
Total assets $ 16,466,241 $ 16,521,944
Liabilities and Shareholders' Equity:
Accounts payable and accrued expenses $ 112,482 $ 44,795
Shareholders' equity: Shareholders' equity (235.3775 shares issued and outstanding) 16,391,464 16,513,521 Managing shareholder's accumulated deficit (37,705) (36,372)
Total shareholders' equity 16,353,759 16,477,149
Total liabilities and shareholders' equity $ 16,466,241 $ 16,521,944
See accompanying notes to financial statements.
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Ridgewood Electric Power Trust II Statement of Cash Flows
Year Ended December 31, 1996 1995 1994 Cash flows from operating activities: Net income (loss) $ 1,970,401 $ (2,149,184) $ (1,698,844)
Adjustments to reconcile net income (loss) to net cash (provided by) used in operating activities: Proceeds from sale of electric power equipment --- 438,855 --- Purchase of electric power equipment --- --- (1,738,855) Writedown of limited partnership investments --- --- 1,397,350 Purchase of investments in electric power projects (60,431) (5,519,498) (9,190,884) Changes in assets and liabilities: Decrease in cash held in escrow for project purchase --- --- 2,343,000 Decrease in deferred due diligence costs --- 14,570 181,243 (Increase) decrease in other assets 14,159 (30,757) 18,826 Increase (decrease) in accounts payable and accrued expenses 67,687 13,227 (607,258)
Total adjustments 21,415 (5,083,603) (7,596,578)
Net cash provided by (used in) operating activities 1,991,816 (2,934,419) (9,295,422)
Cash flows provided by (used in) financing activities: Proceeds from shareholders' contributions 10,000 50,000 4,962,600 Selling commissions and distribution and offering fees paid --- --- (401,900) Cash distributions to shareholders (2,103,791) (2,482,038) (1,255,533) Net cash provided by (used in) financing activities (2,093,791) (2,432,038) 3,305,167
Net decrease in cash and cash equivalents (101,975) (5,366,457) (5,990,255)
Cash and cash equivalents, beginning of period 101,975 5,468,432 11,458,687 Cash and cash equivalents, end of period $ --- $ 101,975 $ 5,468,432
See accompanying notes to financial statements. -F6-
Ridgewood Electric Power Trust II Notes to Financial Statements
1. Organization and Purpose
Nature of business
Ridgewood Electric Power Trust II (the "Trust") was formed as a Delaware business trust on November 20, 1992, by Ridgewood Energy Holding Corporation acting as the Corporate Trustee. The managing shareholder of the Trust is Ridgewood Power Corporation. The Trust began offering shares on January 4, 1993. The Trust commenced operations on April 29, 1993 and discontinued its offering of Trust shares on January 31, 1994.
The Trust was organized to invest in independent power generation facilities and in the development of these facilities. These independent power generation facilities include cogeneration facilities which produce electricity, thermal energy and other power plants that use various fuel sources (except nuclear). The power plants sell electricity and thermal energy to utilities and industrial users under long-term contracts.
"Business Development Company" election
Effective April 29, 1993, the Trust elected to be treated as a "Business Development Company" under the Investment Company Act of 1940 and registered its shares under the Securities Exchange Act of 1934.
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from the estimates.
Investments in project development and power generation limited projects
The Trust holds investments in power generation projects, which are stated at fair value. Due to the non-liquid nature of the investments, the fair values of the investments are assumed to equal cost unless current available information provides a basis for adjusting the carrying value of the investments.
Revenue recognition
Income from investments is recorded when received. Interest and dividend income are recorded as earned.
Offering costs
Costs associated with offering Trust shares (selling commissions, distribution and offering costs) are recorded as a reduction of the shareholders' capital contributions.
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.
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Ridgewood Electric Power Trust II Notes to Financial Statements
Due diligence costs relating to potential power project investments
Costs relating to the due diligence performed on potential power project investments are initially deferred, until such time the Trust determines whether or not it will make an investment in the respective project. Costs relating to completed projects are capitalized and costs relating to rejected projects are expensed at the time of rejection.
Income taxes
No provision is made for income taxes in the accompanying financial statements as the income or losses of the Trust are passed through and included in the tax returns of the individual shareholders of the Trusts.
Reclassification
Certain items in previously issued financial statements have been reclassified for comparative purposes.
3. Electric Power Equipment
The Trust purchased various used electric power generation equipment to be used in potential power generation projects. In January 1995, power generating equipment with a fair value of $1,300,000 was transferred to the Sunnyside (Monterey) project as part of its purchase price. In October 1995, the Trust sold to a related party power generating equipment with a cost of $438,855 for $455,182. The remaining equipment is held in storage and depreciation is not recorded. As of December 31, 1996, the cost of the remaining equipment was $331,018.
4. Investments in Project Development and Power Generation Limited Projects
The Trust had the following investments in power generation and waste transfer projects:
Fair values as of December 31,
1996 1995 Power generation and waste transfer projects: Pittsfield Investors Limited Partnership $ 2,347,330 $ 2,347,330 RSD Power Partners, L.P. 3,507,275 3,507,275 B-3 Limited Partnership 4,001,843 3,941,412 Sunnyside Cogeneration Partners, L.P. 5,308,467 5,308,467 California Pumping Project 951,667 951,667 $ 16,116,582 $ 16,056,151
Investments in power generation limited partnerships
Pittsfield Investors Limited Partnership (known as the Berkshire project)
On January 4, 1994, the Trust made a limited partnership investment in this partnership, which was formed to acquire an operating facility, located in Pittsfield, Massachusetts. The facility, which has been operating since 1981, burns municipal solid waste supplied by the City of Pittsfield and surrounding communities. The facility has a long-term supply agreement with the City of Pittsfield, which expires in November 2004, under which the City makes payments to the facility for receiving the waste. The facility generates additional revenue by selling steam produced from the waste burning process to a nearby paper mill under a long-term contract, which expires in November 2004.
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Ridgewood Electric Power Trust II Notes to Financial Statements
In exchange for its investment, the Trust is entitled to receive annually a preferred distribution from available cash from the facility equal to 15% of its investment. In the event that in any given year available net cash flow from the project does not cover the amount of the preferred minimum return, the amount of such shortfall is payable on a priority basis out of any available net cash flow in subsequent years. The Trust may be entitled to receive additional distributions from any additional net cash flow. As of December 31, 1996 and 1995, the total cost of the Trust's investment in the partnership was $2,347,330. The Trust received distributions of $351,451, $446,888 and $481,588 from the project in 1996, 1995 and 1994, respectively.
RSD Power Partners, L.P. (known as the San Diego project)
On March 21, 1994, the Trust made a limited partnership investment in the partnership, which was formed to acquire an operating facility, located in San Diego, California. The facility, which has been operating since 1972, sells chilled water used in the central air conditioning of 13 commercial, retail and government office buildings connected by a closed underground pipeline loop owned and used exclusively by the San Diego project.
In exchange for its investment, the Trust is entitled to receive annually the greater of either 80% of net profits from the project or a preferred minimum return of 25% on its total investment. In the event in any given year all net profits from the project do not cover the amount of the preferred minimum return, the amount of such shortfall is payable on a priority basis out of any net profits in subsequent years. As of December 31, 1996 and 1995, the total cost of the Trust's investment in the partnership was $3,507,275. The Trust received distributions of $618,080, $1,027,412 and $435,000 from the project in 1996, 1995 and 1994, respectively.
B-3 Limited Partnership (known as the Columbia project)
On August 31, 1994, the Trust made a limited partnership investment in this partnership, which was formed to construct and operate a municipal waste transfer station, located in Columbia County, New York. The project commenced operations in January 1995.
In exchange for its investment, the Trust is entitled to receive annually a preferred distribution of available net cash flow from the facility equal to 18% of its investment. In the event in any given year available net cash flow from the project does not cover the amount of the preferred minimum return, the amount of such shortfall is payable on a priority basis out of any available net cash flow in subsequent years. The Trust may be entitled to receive additional distributions from any additional net cash flow. As of December 31, 1996 and 1995, the total cost of the Trust's investment in the partnership was $4,001,843 and $3,941,412, respectively. The Trust received distributions of $515,000 and $510,000 from the project in 1996 and 1995, respectively.
Sunnyside Cogeneration Partners, L.P. (known as the Monterey project)
On January 9, 1995, the Trust acquired 100% of the existing partnership interests of Sunnyside Cogeneration Partners, L.P., which owns and operates a 5.5 megawatt electric cogeneration facility, located in Monterey County, California. The initial cost of the investment was $5,308,467, which consisted of $3,782,000 of cash, $226,467 of due diligence and other costs, and electric power equipment valued at $1,300,000. The original cost of the equipment contributed by the Trust was $1,599,940. In 1994, the Trust wrote down the value of the equipment by $299,940. The Trust received distributions of $757,498 and $606,536 from the project in 1996 and 1995, respectively.
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Ridgewood Electric Power Trust II Notes to Financial Statements
California Pumping Project
On March 31, 1995, the Trust acquired a package of natural gas fueled diesel engines which drive deep irrigation well pumps in Ventura County, California. The engines' shaft horsepower- hours are 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. Total investment at December 31, 1996 and 1995, was $951,667 for an equivalent of 299.8 kilowatts of power. The operator pays for fuel, maintenance, repair and replacement. The Trust received distributions of $129,179 and $105,742 from the project in 1996 and 1995, respectively.
Investments in project development limited partnerships
The Trust made investments in several limited partnerships with other major participants in the power industry to provide access to investments in larger projects in which these participants would take the leading role in the acquisition or development of such projects. In 1994, the Trust wrote off its investment in these limited partnerhsips of $1,065,798.
RE Power Partners, L.P. (known as the Blue Ridge project)
In 1993, the Trust entered into a limited partnership agreement to provide construction funding of a 3 megawatt natural gas-fueled cogeneration project. During 1994, after further review of the project the Trust decided not to proceed with the construction funding. Total costs, excluding equipment written down separately and transferred to the Sunnyside Cogeneration Partners, L.P., incurred by the Trust and subsequently written off in 1994 totaled $331,552.
5. Transactions With Managing Shareholder And Affiliates
The Trust also pays to the managing shareholder a distribution and offering fee in an amount up to 5% 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 the year ended December 31, 1994, the Trust paid fees for these services to the managing shareholder of $148,500. These fees were recorded as a reduction in shareholders' capital contributions.
The Trust pays to the managing shareholder an investment fee of 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 year ended December 31, 1994, the Trust paid investment fees to the managing shareholder of $59,400.
The Trust entered into a management agreement with the managing shareholder, under which the managing shareholder renders certain management, administrative and advisory services and provides office space and other facilities to the Trust. As compensation to the managing shareholder, the Trust pays the managing shareholder an annual management fee equal to 2.5% of the net asset value of the Trust payable monthly upon the closing of the Trust. For the years ended December 31, 1996, 1995 and 1994, the Trust paid management fees to the managing shareholder of $328,952, $494,023 and $494,820, respectively.
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Ridgewood Electric Power Trust II Notes to Financial Statements
Under the Declaration of Trust, the managing shareholder is entitled to receive each year 1% of all distributions made by the Trust (other than those derived from the disposition of Trust property) until the shareholders have been distributed in respect of the year an amount equal to 15% 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"). In all cases, 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 were paid through December 31, 1996.
The managing shareholder purchased 1.45 shares of the Trust for $121,800. Through the closing of the Trust's offering on January 3, 1994, commissions and placement fees of $248,807 were earned by Ridgewood Securities Corporation, an affiliate of the managing shareholder.
In 1996, under an Operating Agreement with the Trust, Ridgewood Power Management Corporation ("Ridgewood Management"), an entity related to the managing shareholder through common ownership, provides management, purchasing, engineering, planning and administrative services to the power generation project operated by the Trust. Ridgewood Management charges the project at its cost for these services and for the allocable amount of certain overhead items. Allocations of costs are on the basis of identifiable direct costs, time records or in proportion to amount invested in projects managed by Ridgewood Management. During the year ended December 31, 1996, Ridgewood Management charged the Monterey project $60,139 for overhead items allocated in proportion to the amount invested in projects managed, and charged the Monterey project for all of the remaining direct operating and non-operating expenses incurred during the period.