Item 1. Business.
Forward-looking statement advisory
This Annual Report on Form 10-K, as with some other statements made by Ridgewood Electric Power Trust I (the "Trust") from time to time, includes forward-looking statements. These statements discuss business trends and other matters relating to the Trust's future results and business. In order to make these statements, the Trust has had to make assumptions as to the future. It has also had to make estimates in some cases about events that have already happened, and to rely on data that may be found to be inaccurate at a later time. Because these forward-looking statements are based on assumptions, estimates and changeable data, and because any attempt to predict the future is subject to other errors, what happens to the Trust in the future may be materially different from the Trust's statements here.
The Trust therefore warns readers of this document that they should not rely on these forward-looking statements without considering all of the things that could make them inaccurate. The Trust's other filings with the Securities and Exchange Commission and its offering materials discuss many (but not all) of the risks and uncertainties that might affect these forward-looking statements.
Some of these are changes in political and economic conditions, federal or state regulatory structures, government taxation, spending and budgetary policies, government mandates, demand for electricity and thermal energy, the ability of customers to pay for energy received, supplies and prices of fuels, operational status of plant, mechanical breakdowns, availability of labor and the willingness of electric utilities to perform existing power purchase agreements in good faith.
By making these statements now, the Trust is not making any commitment to revise these forward-looking statements to reflect events that happen after the date of this document or to reflect unanticipated future events.
(a) General Development of Business.
The Trust was organized as a Delaware business trust on May 9, 1994. It was organized to acquire all of the assets and to carry on the business of Ridgewood Energy Electric Power, L.P. (the "Partnership"). The Partnership was a Delaware limited partnership, which was organized in March 1991 to participate in the development, construction and operation of independent power generating facilities ("Projects"). The Partnership raised $10.5 million in a single private offering conducted in late 1991 and early 1992. Substantially all of those funds were applied prior to 1995 to the purchase of interests in the Projects described below, to the funding of business ventures that were unsuccessful and to paying the fees and expenses of the Partnership's offering and the Partnership. On June 15, 1994, with the approval of the partners, the Partnership was combined into the Trust, which acquired all of the Partnership's assets and which became liable for all of the Partnership's obligations. In exchange for their interests in the Partnership, the investors in the Partnership received an equivalent number of Investor Shares (as defined below) in the Trust. The Partnership was dissolved.
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 May 26, 1994 the Trust notified the Securities and Exchange Commission of that election and registered its shares of beneficial interest (the "Investor Shares") under the Securities Exchange Act of 1934, as amended (the "1934 Act"). On July 15, 1994 the election and registration became effective. Subsequently, on November 5, 2001, the Trust issued to the owners of Investor Shares (the "Investors") a "Notice of Solicitation of Consents," in which the Trust sought the consent of the Investors to withdraw its election to be treated as a "business development company" under the 1940 Act and to make certain amendments to the Trust's Declaration of Trust ("Declaration") required due to such withdrawal, including, but not limited to, deleting the section of the Declaration requiring Independent Trustees. Consents were tabulated at the close of business on December 18, 2001. Based on such tabulation, a majority of Investor Shares consented to such withdrawal and amendments. On January 10, 2002, the Trust filed with the Securities and Exchange Commission a notification to withdraw its election to be treated as a "business development company." As a result of such withdrawal, the Trust now utilizes generally accepted accounting principles for operating companies.
The Trust is organized similarly to a limited partnership. Ridgewood Renewable Power LLC (the "Managing Shareholder"), a Delaware limited liability company, is the managing shareholder of the Trust. The Managing Shareholder has complete control of the day-to-day operation of the Trust. The Managing Shareholder is not regularly elected by the Investors. As a result, the Trust does not have a "board of directors" that oversees the day-to-day activities of the Trust and, accordingly, the Trust does not have an audit committee or a nominating committee and therefore, the Trust's Chief Executive Officer and Chief Financial Officer effectively perform the functions that an audit committee would otherwise perform.
Christiana Bank & Trust Company, a ("Christiana"), a Delaware trust company, is the Corporate Trustee of the Trust. The Corporate Trustee acts on the instructions of the Managing Shareholder and is not authorized to take independent discretionary action on behalf of the Trust.
In addition, the Trust is affiliated with the following trusts (collectively "Other Power Trusts"), which have been organized by the Managing Shareholder:
o Ridgewood Electric Power Trust II ("Power II"); o Ridgewood Electric Power Trust III ("Power III"); o Ridgewood Electric Power Trust IV ("Power IV"); o Ridgewood Electric Power Trust V ("Power V"); o The Ridgewood Power Growth Fund(the "Growth Fund"); o Ridgewood/Egypt Fund ("Egypt Fund"); and o The Ridgewood Power B Fund/Providence Expansion (the "B Fund").
The Trust also is affiliated with the following Delaware limited liability companies ("Ridgewood LLCs"), which have been organized by the Managing Shareholder:
o Ridgewood Renewable PowerBank LLC o Ridgewood Renewable PowerBank II LLC o Ridgewood Renewable PowerBank III LLC
With respect to the Ridgewood LLCs, the Managing Shareholder acts as the LLC's Manager.
(b) Financial Information about Industry Segments.
The Trust operates in only one industry segment: independent electric power generation.
(c) Narrative Description of Business.
(1) General Description.
The Trust was formed to participate in the development, construction and operation of independent electric power projects. Many of these projects are qualifying facilities or "QFs." Historically, producers of electric power in the United States consisted of regulated utilities serving end-use retail customers and certain industrial users that produced electricity to satisfy their own needs. The independent power industry in the United States was created by, among other things, the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). Generally, PURPA requires utilities to purchase electric power from QFs, including "cogeneration facilities" and "small power producers," and also exempts these QFs from most federal and state utility regulatory requirements. PURPA requires that the price paid by electric utilities for electricity produced by QFs is the utility's avoided cost of producing electricity (i.e., the incremental costs the utility would otherwise face to generate electricity itself or purchase electricity from another source). Pursuant to PURPA, and state implementation of PURPA, many electric utilities have entered into long-term Power Contracts with rates set by contract formula approved by state regulatory commissions.
Although one of the benefits of PURPA is the requirement imposed upon electric utilities to purchase QF electric power, there are nonetheless many QFs that do not have power contracts with electric utilities because, among other reasons, the power contract has expired or was "bought out" and current avoided cost is too low for the QF to sustain operations, the lack of a long-term market for the power produced by QFs, or the electric utilities' belief that state implementation of PURPA no longer requires such purchase of QF power. Southern California Edison Company ("SCE"), to whom the Brea Project sells electric energy, has taken such a position. SCE was being legally challenged by several QFs but the matter was not resolved and has generally been subsumed in the general electric energy procurement proceeding currently being conducted by the California Public Utilities Commission ("CPUC").
(2) Projects.
(i) Brea Project. The Trust owns and operates a 5-megawatt capacity electric generating facility fueled by methane and other burnable gases created by the decomposition of garbage in a landfill owned by the County of Orange, California (the "Brea Project"). Ridgewood Power Management, LLC ("RPM"), an affiliate of the Trust's Managing Shareholder, operates and manages the day-to-day activities of the Brea Project. RPM is reimbursed by the Trust for its actual costs incurred and allocable overhead expenses but is not otherwise compensated.
The Brea Project does not include the landfill gas collection system. Currently, GSF Energy LLC ("GSF") collects and sells landfill gas to the Brea Project pursuant to an Amended and Restated Landfill Gas Sale and Purchase Agreement ("Amended Gas Agreement"). GSF sells and collects such landfill gas pursuant to a gas lease agreement with the County of Orange. Pursuant to the Amended Gas Agreement, the Trust contracted with GSF for the rights to all of the landfill gas generated at the Orange County landfill until the year 2018. Because the Amended Gas Agreement is between GSF and the Brea Project and not with Orange County, if GSF were to cease operations at the landfill or if Orange County were to terminate the gas lease agreement with GSF, it is not clear whether Orange County is bound to recognize the Trusts rights to the landfill gas. The Trust is contemplating direct discussions with Orange County regarding this and other matters. Under the Amended Gas Agreement, the Trust pays GSF a fixed amount of $60,000 per month and a 9.5% royalty from the revenues generated by the Brea Project. The $60,000 fixed payment escalates at the Consumer Price Index ("CPI") and expires in 2005, at which time the Trust will pay GSF the greater of a 19% royalty from the revenues of the Brea Project or $720,000 annually. The Amended Gas Agreement also covered gas supplies to and revenues from the Olinda Project. However as further detailed below, the Olinda Project has been relocated by the Trust to Rhode Island.
The Brea Project is a QF. Electricity generated by the Brea Project, over and above its own requirements, is sold to SCE under a long-term power sales contract (a "Power Contract"). The energy price under the Power Contract is the higher of 5.8 cents per kilowatt-hour or SCE's avoided cost, which is an amount determined by a contract formula set forth in the Power Contract. The Power Contract permits either party to terminate it no earlier than the end of 2004 on 5 years' advance notice. On March 23, 2000, SCE provided such written notice to the Brea Project notifying that it was electing to terminate the Power Contract as of March 23, 2005. After such termination, the Brea Project, if it continues operating in light of certain environmental regulations (See Below), either will have to enter into another long-term power contract, if available, or sell its electric output in the competitive electric power market.
In addition to the difficulties associated with procuring a long-term power contract, the Brea Project is faced with the possible termination of its operations as of January 1, 2005 as a result of its inability to comply with certain environmental regulations. The Brea Project operates within the jurisdiction of the South Coast Air Quality Management District ("South Coast"), the air pollution control agency for Orange County and major portions of Los Angeles, San Bernardino and Riverside counties in Southern California. The South Coast promulgated Rule 1110-2 regarding air emissions from gaseous and liquid-fueled stationary engines which generally imposes very low air emissions levels on such engines, which include the generating engines used by and located at the Brea Project (the "Rule"). According to the Rule, existing, and to be installed, electric generating engines must be in compliance with the new emissions levels by January 1, 2005 or cease operations or, if operations continue, risk severe penalties from South Coast. The electric generating engines used by the Brea Project cannot, in their current configuration, comply with the Rule. RPM, on behalf of the Brea Project, informally requested from South Coast a temporary exemption of the Rule's application to Brea. South Coast rejected that request. Brea is considering formally seeking a variance from South Coast of the Rule's applicability. However, notwithstanding such efforts, the Brea Project essentially has three options with respect to the Rule (i) cease operations as of January 1, 2005, (ii) upgrade and/or repair the existing engines, if possible, to comply with the Rule's emissions levels, or (iii) repower the Brea Project with new engines capable of complying with the emissions levels. The Trust is seeking a workable alternative to ceasing its operations at the Brea Project and, as a result, RPM, on behalf of the Brea Project, has been investigating whether the existing engines can be upgraded or repaired to comply with the Rule's air emissions levels. To date, RPM has not been able to find any such solution that is or can be demonstrated to be both successful and economically feasible.
In addition, RPM has been investigating the feasibility of repowering the Brea Project with new engines and related equipment. A conservative estimate of the capital costs needed to complete such repowering are between $3,000,000 to $4,000,000. The problem, however, is that such capital will be difficult, if not impossible, to acquire without the Brea Project first securing an appropriately priced (in light of operating costs, debt service and profit margins) long-term electric power contract to replace the SCE Power Contract. The prospects of securing such a long-term power contract at reasonable prices are not encouraging. The primary reason is that the electric energy market in California is generally in a state of flux in that the CPUC has not yet completed its procurement proceeding or has determined how such procurement relates to the procurement of renewable energy.
Although California has passed and is currently adopting rules for a renewable portfolio standard ("RPS"), RPM does not believe that the California RPS will create any significant market for renewable energy credits ("RECs") or provide additional revenues from RECs to supplement renewable generator's revenues. Nevertheless, RPM, on behalf of the Brea Project, is participating in the RPS proceeding in California in an attempt to influence policy makers in California to revise the RPS. In addition to the RPS efforts, RPM is also attempting to influence legislation in California that will increase the tipping-fee paid by waste haulers that dump waste at California landfills. The intent is to use the tipping fee increase to subsidize the cost of electric generation from landfill gas. The basic premise behind RPM's efforts in California is to obtain through legislation (e.g., tipping fee) or regulation (e.g., RPS) subsidies or supplemental revenue such that the long-term all-in revenue from electric sales, subsidies (if any) and REC sales cumulatively are sufficient to procure and service the capital required to repower the Brea Project, as well as cover all operating costs and provide a reasonable return. See Section 4, Market Trends for more information on the California RPS.
Given the current prices for long-term electric power, the Brea Project must not only procure an acceptable long-term power contract but also receive either the tipping fee subsidy or the RPS benefit in order to either upgrade the engines or repower the Brea Project. As of the date hereof, the Trust cannot guarantee or predict whether an acceptable long-term power contract will be procured, or whether the tipping fee legislation will be enacted as described, or whether the California RPS will be successful. As a result, the possibility exists that the Trust will have to terminate operations at the Brea Project. Such termination will likely lead to, among other things, the loss of Brea's rights to the landfill gas generated at the Orange County landfill.
(ii) Olinda Project. In early 2001, the Trust decided to expand its operations at the Orange County Landfill by developing and installing a 2.5-megawatt electric generating facility fueled by methane gas (the "Olinda Project"). The total cost of the Olinda Project was approximately $3,000,000, half of which has been financed. The Olinda Project was designed and built by Stewart & Stevenson ("S&S"), an engineering and construction firm, for a cost of approximately $2,500,000. The Olinda Project was originally intended to receive its landfill gas from GSF pursuant to the Amended Gas Agreement.
The Olinda Project was completed substantially behind the schedule agreed to by S&S and Ridgewood Olinda, LLC, the owner of the Olinda Project. In addition, within several months of commercial operation, one of the electric generating machines installed by S&S experienced a catastrophic failure. Although S&S provided a temporary replacement engine to Ridgewood Olinda, the Olinda Project was subsequently shut-down in October of 2002 by the Orange County electrical inspector due to S&S's failure to install proper electrical switchgear or obtain a permit for the switchgear it did install. The engine failure and switchgear problems highlighted significant other failures of S&S including, but not limited to, S&S's failure to obtain final building permits, failure to deliver operating manuals or provide training, and numerous other problems or issues that have developed. The parties have settled these claims without litigation and as part of such settlement, S&S agreed to repair the damaged engine and provide other services with respect to the relocation of both Olinda engines to Rhode Island. (See below)
The Olinda Project began commercial operation on or about March of 2002 and sold its electric output in California to the California Power Authority ("CPA") pursuant to a short-term (ninety-day) power sales contract. Such short-term contract was extended by the CPA through December 31, 2002, along with several other contracts with renewable (biomass) generators. Prior to the expiration of such extension the CPA offered additional six-month extensions to several biomass generators but did not offer a similar extension to the Olinda Project. Despite significant efforts, the Olinda Project began the year 2003 without a long-term power contract and the prospect for obtaining such an acceptable contract were remote given the electric energy market in California. See, Section 4, Market Trends.
As a result of the poor long-term possibilities in California in 2003, the Trust relocated the electric generating equipment of the Olinda Project from California to Rhode Island, to the site of a new landfill gas project being developed by the Trust's affiliate, the B Fund. Olinda and the B Fund have entered into a lease agreement in which Olinda will receive from the B Fund as a lease payment approximately 15% of the net operating cash flow generated at the B Fund's landfill gas-fired facility.
(iii) Stillwater Project. In October 1991, the Trust acquired a 32.5% equity interest with respect to a 3.5 megawatt (nominal capacity) hydroelectric facility which was then under construction on the Hudson River in the village of Stillwater, New York (approximately 30 miles northeast of Albany) at the site of a pre-existing 800 foot wide masonry dam structure (the "Stillwater Project") for a purchase price of $750,000. The Stillwater Project commenced commercial operation in May 1993.
The Trust and affiliates of the general contractor and affiliates of the equipment supplier formed Stillwater Hydro Partners, L.P. ("SHP") to continue development of the Stillwater Project. The Trust's total investment was $1,162,000. Debt financing for the Project was provided by the CIT Group/Capital Equipment Financing Inc. ("CIT"). The CIT financing is a fixed rate 15-year term loan in the principal amount of approximately $8,995,000, with the final payment due in 2008. In addition to the fixed interest payments, CIT is also entitled to receive, as additional interest, 22.5% of the available cash flow of the Stillwater Project. The term loan is payable only by SHP, and is non-recourse to the Trust.
The Trust now owns a fixed preferred partnership interest entitling it to aggregate distributions of $1 million, plus a compound annual return of 12% thereon until paid in full. Over the nine-year schedule of annual payments, the Trust was to receive total payments, including the annual return, of approximately $1,720,000. SHP is required to apply substantially all of SHP's available cash flow after funding of debt service (up to a maximum amount each year) to satisfy the payment obligation to the Trust, with any shortfalls to be carried forward with interest into subsequent years.
The Stillwater Project's revenues are dependent upon water levels in the Hudson River, which have fluctuated significantly during the last several years. During low flow periods, generation is curtailed. For a variety of reasons, power output during high flow periods has not reached projected levels. In addition, even if water flow levels are optimal, the Project is unable to generate the full projected output of 3.5 megawatts of electricity because of a design defect. As a result, the Trust has only received a single partial payment of $126,000 in 1994 and does not expect to receive any additional payments for several years. Electricity generated by the Stillwater Project is sold to Niagara Mohawk Power Corporation under a long-term Power Contract, which expires in 2028.
(iv) Mobile Power Units. Effective August 1999, the Trust purchased two mobile electric generating units manufactured by Caterpillar Inc. (the "Units"). The Units combine a large diesel engine with a fuel tank, emission equipment, an electric generator and control equipment on a single skid and therefore can be moved to remote areas as a self-contained power plant. The owner of the Units is Ridgewood Mobile Power I, LLC, a wholly-owned subsidiary of the Trust. The Trust bought the Units from Hawthorne Power Systems, Inc. ("Hawthorne") of San Diego, California (a Caterpillar distributor). Hawthorne manages the Units, which are rented at fixed rates. Hawthorne receives 20% of the net rental revenues to compensate it for marketing and managing the Units. Due to the increase in competition and production of newer efficient models, the Trust experienced a decrease in rental revenue for the second consecutive year. As a result of the change in these market conditions, the forecasted revenues for the mobile power modules are not expected to be enough to recover the units' book value. In 2003 and 2002, the Trust recorded writedowns of $44,143 and $209,251, respectively, to reflect the units fair market value. In the third quarter of 2003, the Trust decided to make its mobile power modules available for sale.
Additional information regarding the Projects is found in the Notes to the Consolidated Financial Statements.
(3) Project Management and Operation
The Managing Shareholder has organized RPM to provide operating management for the Projects, and has assigned day-to-day management of the Brea Project and Olinda Project to RPM. These services are charged to the Projects at RPM's cost. See Item 10 - Directors and Executive Officers of the Registrant and Item 13 - Certain Relationships and Related Transactions for further information regarding the Operation Agreement and RPM and for the cost reimbursements received by RPM. The Stillwater Project is managed by its remaining equity partners. Hawthorne manages the Mobile Power Units.
Customers that accounted for more than 10% of the consolidated revenue to the Trust in each of the last three fiscal years are:
Calendar Year 2003 2002 2001 Southern California Edison 99.8% 97.3% 94.6%
(4) Market Trends.
In the year 2003 many states implemented or enacted renewable portfolio standards (RPS). For example, RPS legislation and regulations have been passed and are effective in, among other states, Massachusetts, Nevada, Texas, New Jersey, and Connecticut. Many other states are considering RPS legislation. The intent behind virtually all RPS programs is to provide added financial incentives to developers of renewable generation by requiring retail electric suppliers to purchase a certain percentage of renewable power or, alternatively, purchase the required number of "renewable energy credits" ("REC"), which are created as a result of such renewable generation. As a result of the RPS programs, developers of renewable generation can effectively receive two sources of revenue: one from the sale of the actual electric energy and one from the sale of RECs. Most RPS programs effectively separate the purchase of energy from the purchase of the "REC" and basically require electric energy suppliers to have the required number of RECs at the end of the compliance period, regardless of its energy supply portfolio. Combined, these two streams of income may be sufficient to attract and increase the development of new renewable generation.
The California RPS generally requires that retail electric sellers in the state increase the renewable generation in their electric supply portfolio by one (1%) percent per year, provided certain conditions are met, over a baseline level of renewable generation to be determined by the California Public Utilities Commission ("CPUC"). According to California's RPS, the annual incremental renewable generation procurement requirement continues until renewable generation comprises twenty (20%) percent of the aggregate electric supply to retail users in the state. Such 20% target must be achieved no later than December 31, 2017.
However, California adopted and is implementing an RPS that is different than most other state RPS programs. According to the California RPS legislation, electric utility purchases of renewable energy (or RECs) is part of the utilities annual procurement proceedings. Basically, the REC was not "separated" from the purchase of the renewable energy and, as a result, the procurement of renewable energy has been incorporated into the electric utilities long-term power procurement proceedings. In addition, the RPS legislation in California requires the utilities to pay no more for renewable energy than a "market referent price" determined by the CPUC and which is supposed to approximate the cost of energy from a new combined cycle natural gas-fired electric facility. Any "above market costs" of the renewable energy are to be funded from the "public goods charge", which is a limited fund administered by the California Energy Commission ("CEC"). As a result of this general framework, the implementation of the RPS in California is extremely complicated and involves many divisive issues that are not part of any other state RPS program including, without limitation, determining renewable generation market price referents, the utilities least cost, best fit strategy with respect to renewable generation, establishing initial renewable generation baselines, and reviewing and approving the investor-owned utilities ("IOU's") renewable procurement plans.
According to the RPS legislation, the CPUC and the CEC are to work collaboratively to make necessary findings, determine appropriate procedures and, ultimately, determine the methodology for renewable procurement by California's IOU's. The RPS legislation required that such collaborative effort be completed and implemented by the end of 2003. Both the CPUC and CEC are significantly behind schedule and it is questionable whether the RPS will be implemented in 2004.
RPM, as agent for the Brea Project, is participating in these proceedings. However, as a result of such participation, RPM has concluded that in the near term (next two years) the RPS program in California probably will not substantially assist renewable projects obtain profitable power contracts nor is it likely to facilitate the sale of any RECs generated by such renewable facilities. The reasons for such conclusion include, as mentioned, the fact that (i) California IOUs pay no more for renewable power than they would otherwise pay for non-renewable power, (ii) any excess above a fossil-fueled "benchmark" price be obtained from the CEC through the "public goods charge", (iii) there may not be sufficient "public goods charge" funds available for the predicted renewable supply, and (iv) the RPS legislation does not necessarily facilitate a RPS trading program such that a renewable generator could sell its energy to one customer and renewable attributes to another. As a result of these and other problems in California, the Trust, as mentioned earlier, relocated the Olinda Project's electric generating equipment to Providence, Rhode Island, to be part of a project being developed by its affiliate, the B Fund. The market for renewable power in New England is significantly more favorable than in California.
In addition to developments in California, the general trends in the electric power industry have continued to reflect an attitude of caution and restraint. Throughout the United States, memories of the California energy crises, Enron Corp.'s bankruptcy, proceedings before the Federal Energy Regulatory Commission ("FERC") regarding certain questionable practices of other energy producers and marketers, as well as the generally poor U.S. and world economy, have led many to call for a more regulated electric industry, with strict reporting requirements and cost of service regulation. However, many legislators, regulators and market participants have not disavowed deregulation.
(5) Competition
The Brea and Stillwater Projects, as described above, are not currently subject to competition because those Projects have entered into long-term Power Contracts to sell their output at specified prices, although the Brea Power Contract expires as of March 23, 2005, assuming that the Brea Project can comply with the South Coast's Rule. The Brea and Stillwater Projects, likewise, will be subject to competition to market its electricity output once the Power Contract expires or is terminated. However, as further detailed in Item 1(c)(4), the California RPS Standard, if implemented in a manner that is beneficial to renewable generation, may very well permit the Brea Project to repower to satisfy the Rule and market and sell its renewable power at favorable rates, although such outcome can not be assured due to certain other uncertainties including, but not limited to, the South Coast Rule. The process of deregulation in New York, where the Stillwater Project is located, is still uncertain and it is difficult to estimate the level of market competition that it would face in any such event. The Olinda Project is receiving lease payment from the B Fund. Although the B Fund has not yet procured a long-term contract for its electric power and is selling currently to the New England ISO and receiving the "spot price" for its power, the price for such power is approximately $.04/kwh and the sale of the REC is New England is also approximately $.04/kwh. These two revenue stream combine for a $.08/kwh, which is an economically attractive price, although there is no guarantee that these prices can be sustained or that an acceptable long-term power contract can be procured.
The Units compete against numerous other fleets of mobile power generation equipment on a regional and international level. Due to the increase in competition and production of newer efficient mobile models, the Trust experienced a decrease in rental revenue for the current year, thus, as described above and in the Notes, prompted a writedown of the Trust's investment in the Units.
6. Regulatory Matters.
The 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.
(i) Energy Regulation.
(A) PURPA. PURPA, and the adoption of regulations thereunder by FERC, provided incentives for the development of QFs meeting certain criteria. QFs are generally exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended, the Federal Power Act, as amended, and, except under certain limited circumstances, from state laws regarding rate or financial regulation. In order to be a QF, a cogeneration facility must (a) produce not only electricity but also a certain quantity of heat energy (such as steam) which is used for a purpose other than power generation, (b) meet certain energy efficiency standards when natural gas or oil is used as a fuel source and (c) not be controlled or more than 50% owned by an electric utility or electric utility holding company. Other types of Independent Power Projects, known as "small power production facilities," can be QF if they meet regulations respecting maximum size (in certain cases), primary energy source and utility ownership.
The exemptions from extensive federal and state regulation afforded by PURPA to QFs are important to the Trust and its competitors. The Trust believes that each of its Projects is a QF. If a Project loses its QF status, the utility can reclaim payments it made for the Project's non-qualifying output to the extent those payments are in excess of current avoided costs or the Project's Power Contract can be terminated by the electric utility.
(B) The 1992 Energy Act. The Comprehensive Energy Policy Act of 1992 (the "1992 Energy Act") empowered FERC to require electric utilities to make available their transmission facilities to and wheel power for Independent Power Projects under certain conditions and created an exemption for electric utilities, electric utility holding companies and other independent power producers from certain restrictions imposed by the Holding Company Act. Although the Trust believes that the exemptive provisions of the 1992 Energy Act will not materially and adversely affect its business plan, the Energy Act has resulted and may continue to result in increased competition in the sale of electricity.
(C) The Federal Power Act. The FPA grants FERC exclusive rate-making jurisdiction over wholesale sales of electricity in interstate commerce. Again, this will not affect the Trust's Projects unless they were to attempt sales to other customers.
(D) State Regulation. The Trust's Projects are not subject to material state economic regulation except for requirements in California and New York to supply the purchasing utility with information to confirm compliance with QF fuel use and efficiency requirements and to make the Projects available for audit and inspection to confirm QF compliance. The Trust believes that its Projects meet QF standards. States also have authority to regulate certain environmental, health and siting aspects of QFs.
(E) Mobile Power Units. The Mobile Power Units, as temporary on-site units operated by the electricity consumer, are not subject to economic regulation in California or most other jurisdictions.
(ii) Environmental Regulation.
The operation of Independent Power Projects is subject to extensive federal, state and local environmental laws and regulations. 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 also include wetlands preservation, fisheries protection (at the Stillwater Project) and noise regulation. These laws and regulations in many cases require a lengthy and complex process of renewing or obtaining licenses, permits and approvals from federal, state and local agencies. Obtaining necessary approvals can be time-consuming and difficult. Each Project requires technology and facilities that comply with federal, state and local requirements, which sometimes result in extensive negotiations with regulatory agencies. Meeting the requirements of each jurisdiction with authority over a Project may require modifications to existing Projects.
The Units, which do not have a fixed location, are subject to differing air quality standards that depend in part on the locations of use, the amount of time and time periods of use and the quantity of pollutants emitted. The Trust believes that the Units as used comply with all applicable air quality rules.
The Managing Shareholder expects that environmental and land use regulations may become more stringent or, at a minimum, remain constant. The Trust and the Managing Shareholder have developed a certain expertise and experience in obtaining necessary licenses, permits and approvals, but will nonetheless rely upon co-owners of the Stillwater Project and as to all Projects on qualified environmental consultants and environmental counsel retained by it to assist in evaluating the status of Projects regarding such matters.
(iii) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are subject to amendment or repeal. Future legislation and regulation is uncertain, and could have material effects on the Trust.
(d) Financial Information about Foreign and Domestic Operations and Export Sales.
The Trust has no foreign operations.
(e) Employees.
The employees of the Brea Project and the Olinda Project are employed by RPM, the Trust is administered by the Managing Shareholder 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.
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. All of the Projects are described in further detail at Item 1(c)(2).
Est.Amount Approximate of Land Square Project Location Land (acreage) Footage
Brea Brea, CA Leased 2 6,000
Still Stillwater, Leased .75 N/A Water NY and Licensed
Item 3.
Item 3. Legal Proceedings.
None.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
(a) Market Information.
The Trust has 105.5 Investor Shares. There is currently no established public trading market for the Investor Shares. As of the date of this Form 10-K, all such Investor Shares have been issued and are outstanding. There are no outstanding options or warrants to purchase, or securities convertible into, Investor Shares.
Investor Shares are restricted as to transferability under the Declaration. In addition, under federal laws regulating securities the Investor Shares have restrictions on transferability when they are held by persons in a control relationship with the Trust. Investors wishing to transfer Investor Shares should also consider the applicability of state securities laws. The Investor Shares have not been registered under the Securities Act of 1933, as amended (the "1933 Act"), or under any other similar law of any state (except for certain registrations that do not permit free resale) in reliance upon what the Trust believes to be exemptions from the registration requirements contained therein. Because the Investor Shares have not been registered, they are "restricted securities" as defined in Rule 144 under the 1933 Act.
(b) Holders.
As of the date of this Form 10-K, there are 234 holders of record of Investor Shares.
(c) Dividends.
The Trust made distributions as follows for the years ended December 31, 2003 and 2002:
Year ended Year ended December 31, December 31, 2003 2002 Total distributions to Investors $1,690,497 $1,052,499 Distributions per Investor Share 16,024 9,976 Total distributions to Managing Shareholder 17,076 10,631
The Trust's decision whether to make future distributions to Investors and their timing will depend on, among other things, the net cash flow of the Trust and retention of reasonable reserves as determined by the Trust to cover its anticipated expenses. See Item 7 Management's Discussion and Analysis.
Occasionally, distributions may include funds derived from the release of cash from operating or debt services reserves. Further, the Declaration authorizes distributions to be made from cash flows rather than income, or from cash reserves in some instances. For purposes of generally accepted accounting principles, amounts of distributions in excess of accounting income may be considered to be capital in nature. Investors should be aware that the Trust is organized to return net cash flow rather than accounting income to Investors.
Item 6.
Item 6. Selected Financial Data (all amounts in $).
The following data is qualified in its entirety by the financial statements presented elsewhere in this Annual Report on Form 10-K. As described in such financial statements, financial information for the years 1999 and 2000 have been restated to reflect the application of new accounting principles as a result of the Trust's election to terminate its status as a business development company.
Selected Financial Data As of and for the year ended December 31, 2003 2002 2001 2000 1999
Total Fund Information: Revenues $3,211,055 $3,352,189 $4,379,154 $3,259,562 $3,114,503 Net income(loss)(1,409,416) 101,827 1,454,876 1,487,998 799,717 (A) (B) Net assets (shareholders' equity) 3,694,937 6,811,926 7,773,229 6,318,353 6,323,075 Investments in Plant and Equipment (net of depreciation)1,513,422 4,671,615 4,922,297 2,688,320 2,920,044 Investment in Power Contract(net of amortization) 157,694 473,091 788,489 1,103,887 1,419,284 Total assets 4,937,723 8,291,849 9,386,999 6,507,720 6,543,322 Long-term obligations 652,607 952,607 1,227,674 -- -- Per Share: Revenues 30,436 31,774 41,509 30,896 29,521 Net income(loss) (13,359) 965 13,790 14,104 7,580 (A) (B) Net asset value 35,023 64,568 73,679 59,890 59,934 Distributions to Investors 16,024 9,976 -- 14,008 12,300
(A) Includes writedown of investment of $1,722,380 ($16,326 per Investor Share). (B) Includes writedown of investment of $422,019 ($4,000 per Investor Share).
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation.
Introduction
The following discussion and analysis should be read in conjunction with the Trust's financial statements and the notes thereto presented below. Dollar amounts in this discussion are generally rounded to the nearest $1,000.
Outlook
The Brea and Stillwater Projects are QFs under PURPA and currently sell their electric output to utilities under long-term Power Contracts expiring in 2005 and 2028, respectively. During the term of the Power Contracts, the utilities may or may not attempt to buy out the contracts prior to expiration. At the end of the Power Contracts, the Projects will become merchant plants and may be able to sell the electric output at then current market prices. There can be no assurance that future market prices will be sufficient to allow the Trust's Projects to operate profitably.
All available cash flow from the Stillwater Project is being used to meet debt service requirements. Distributions to the Trust will resume after repayment of the bonds. Assuming normal water flows and no operational failures, the bonds are expected to be repaid in 2008.
Additional trends affecting the independent power industry generally are described at Item 1(c)(4).
Significant Accounting Policies
The Trust's plant and equipment is recorded at cost and is depreciated over its estimated useful life. The estimate useful lives of the Trust's plant and equipment range from 5 to 20 years. A significant decrease in the estimated useful life of a material amount of plant and equipment could have a material adverse impact on the Trust's operating results in the period in which the estimate is revised and subsequent periods. The Trust evaluates the impairment of its long-lived assets (including power sales contracts) based on projections of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. Estimates of future cash flows used to test the recoverability of specific long-lived assets are based on expected cash flows from the use and eventual disposition of the assets. A significant reduction in actual cash flows and estimated cash flows may have a material adverse impact on the Trust's operating results and financial condition.
Results of Operations
The year ended December 31, 2003 compared to the year ended December 31, 2002. Power generation revenue decreased 2% to $3,203,000 in 2003 from $3,263,000 in 2002, primarily due to the decrease in power generation revenue from the Olinda Project. The Olinda project provided $372,000 in power generation revenue in 2002, but did not operate in 2003 due to mechanical problems and the lack of a power contract. Power generation revenue from the Brea project increased by $312,000 in the current year. The increase in revenue from the Brea project is attributable to the project operating more consistently in 2003 as compared to 2002, when the project experienced a temporary shut down due to mechanical problems. Rental revenue from the Trust's Caterpillar rental modules decreased by $82,000 or 92%, to $8,000 in 2003. The decrease in rental revenue is due to the increase in competition and production of newer efficient models.
Gross profit, which represents total revenues reduced by cost of sales, increased from $780,000 in 2002, to $944,000 in 2003. The increase is primarily the result of the Brea project experiencing greater repair and maintenance costs in 2002.
General and administrative expenses increased $181,000, or 72%, to $433,000 in 2003 from $252,000 in 2002. The increase is due to the professional fees incurred by the Trust on behalf of the Brea project. The Trust had retained professional firms to assist it in the researching and monitoring of the California legislation on renewable energy, with the intent of the Brea project qualifying as a renewable energy generation facility and becoming eligible to receive additional revenue for the sale of renewable energy attributes.
During 2002, the Trust recorded $72,000 of project development expenses relating to projects in California that it ultimately decided not to develop.
In 2003 the Trust recorded a write down in its investment in power generation projects of $1,772,000, of which, $1,728,000 is the write down of the Olinda project, which removed its engines and transferred them to the Ridgewood Providence expansion. The remaining $44,000 is related to the Caterpillar rental modules, for which in 2002, the Trust recorded a write down of $209,000.
The management fee paid to the Managing Shareholder decreased $10,000, or 13%, to $68,000 in 2003 from $78,000 in 2002, which reflects the Trust's lower net asset balance.
Income (loss) from operations decreased $1,499,000 to a loss of $1,330,000 in 2003 from income of $169,000 in 2002. The decrease in income is primarily the result of the increase in the write down in investments in power generation projects in 2003, partially offset by the decrease in repair and maintenance costs.
Other income (expense), net, increased $13,000, or 19%, to $80,000 in 2003 from $67,000 in 2002. Interest income decreased $24,000 in 2003 due to the lower cash balances and lower interest rates. Interest expense decreased $23,000 as a result of the lower principal balance on the Olinda project financing. In addition, the Trust recorded equity income from its investment in Stillwater of $37,000 in both 2003 and 2002.
Net income (loss) decreased $1,511,000, to a loss of $1,409,000 in 2003 from income of $102,000 in 2002. The decrease in net income is a result of the write down in investment in power generation projects, partially offset by the decrease in repair and maintenance costs.
The year ended December 31, 2002 compared to the year ended December 31, 2001.
Power generation revenue decreased 21% to $3,263,000 in 2002 from $4,141,000 in 2001, primarily due to the decrease in power generation revenue from the Brea Project. Power generation revenue from the Brea Project decreased by $1,250,000, while the Olinda Project provided an increase of $372,000 in 2002. The decrease in revenue from the Brea project is attributable to the higher energy prices charged during the first half of 2001 as a result of the California energy crisis. Rental revenue from the Trust's Caterpillar rental modules decreased by $150,000 or 63%, to $89,000 in 2002. The decrease in rental revenue is due to the higher rental volume experienced in 2001, as a result of the California energy crisis.
Gross profit, which represents total revenues reduced by cost of sales, decreased from $2,450,000 in 2001, to $780,000 in 2002. The decrease is a result of the higher energy prices charged during the California energy crisis in 2001, as well as the Brea project experiencing greater repair and maintenance costs in 2002.
General and administrative expenses decreased $20,000, or 7%, to $252,000 in 2002 from $272,000 in 2001. The decrease primarily reflects the legal costs associated with the Brea Project's dispute with SCE in 2001.
The $480,000 of bad debt expense in 2001 is associated with the sale of the Brea Project's SCE receivables to AMROC.
During 2002, the Trust recorded $72,000 of project development expenses relating to projects in California that it ultimately decided not to develop. Also during 2002, the Trust recorded a write down of $209,000 relating to the Caterpillar rental modules.
The management fee paid to the Managing Shareholder decreased $9,000, or 10%, to $78,000 in 2002 from $87,000 in 2001, which reflects the Trust's lower net asset balance.
Income from operations decreased $1,441,000, or 90%, to $169,000 in 2002 from $1,610,000 in 2001 as a result of the decrease in revenues and the increase in repair and maintenance costs.
Other income (expense), net, decreased $88,000, or 57%, to $67,000 in 2002 from $155,000 in 2001. The decrease in expense is a result of costs incurred in issuing the "Notice of Solicitation of Consents" in 2001, offset by the increase in interest expense paid in 2002 on the Olinda Project long-term financing. In addition, the Trust recorded an equity loss from its investment in Stillwater of $29,000 in 2001 compared to income of $37,000 in 2002 reflecting higher revenues due to the increase in river flows. Interest income decreased $46,000 in 2002 due to the lower cash balances and lower interest rates.
Net income decreased $1,353,000, or 93%, to $102,000 in 2002 from $1,455,000 in 2001 as a result of the decrease in revenues and the increase in repair and maintenance costs.
Liquidity and Capital Resources
In 2003 and 2002, the Trust's operating activities generated $1,021,000 and $714,000 of cash, respectively. The increase in cash flow from operating activities is primarily due to the increase in gross profit and the timing of receipt/payment of assets and liabilities.
Cash used in investing activities in 2003 and 2002 was $192,000 and $257,000, respectively. Cash used in investing activities in 2003 and 2002 was for capital expenditures relating to the Olinda Project.
Cash used in financing activities in 2003 of $1,983,000 represented distributions to shareholders of $1,708,000 and payments of $275,000 to reduce long-term debt on the Olinda Project. Cash used in financing activities in 2002 of $1,315,000 represented distributions to shareholders of $1,063,000 and payments of $252,000 to reduce long-term debt on the Olinda Project.
Obligations of the Trust are generally limited to payment of a management fee to the Managing Shareholder and payments for certain administrative, accounting and legal services to third persons. Accordingly, the Trust has not found it necessary to retain a material amount of working capital. The Trust's significant long-term obligation is limited to $953,000 of long-term debt related to the Olinda Project, which is guaranteed by the Trust. Scheduled principal payments of the long-term debt are as follows:
2004 $300,000 2005 327,000 2006 326,000
On June 26, 2003, the Managing Shareholder of the Trust, entered into a $5,000,0000 Revolving Credit and Security Agreement with Wachovia Bank, National Association. The agreement allows the Managing Shareholder to obtain loans and letters of credit for the benefit of the trusts and funds that it manages. The agreement expires on June 30, 2004. On February 20, 2004, the Managing Shareholder and Wachovia Bank amended the agreement increasing the amount to $6,000,000 and extending the date of expiration to June 30, 2005. As part of the agreement, the Trust agreed to limitations on its ability to incur indebtedness, liens and provide guarantees.
The Brea Project has certain long-term obligations relating to its Gas Agreement with GSF (See Note 5 of the Consolidated Financial Statements) and its Power Contract with SCE. These obligations are not guaranteed by the Trust. The Trust and its subsidiaries anticipate that during 2004 their cash flow from operations will be sufficient to meet their obligations.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Qualitative Information About Market Risk.
The Trust's investments in financial instruments are short-term investments of working capital or excess cash. Those short-term investments are limited by its Declaration of Trust to investments in United States government and agency securities or to obligations of banks having at least $5 billion in assets. Because the Trust invests only in short-term instruments for cash management, its exposure to interest rate changes is low. The Trust has limited exposure to trade accounts receivable and believes that their carrying amounts approximate fair value.
The Trust's primary market risk exposure is limited interest rate risk caused by fluctuations in short-term interest rates. The Trust does not anticipate any changes in its primary market risk exposure or how it intends to manage it. The Trust does not trade in market risk sensitive instruments.
Quantitative Information About Market Risk
This table provides information about the Trust's financial instruments that are defined by the Securities and Exchange Commission as market risk sensitive instruments. These include only short-term U.S. government and agency securities and bank obligations. The table includes principal cash flows and related weighted average interest rates by contractual maturity dates.
December 31, 2003 Expected Maturity Date (U.S. $)
Bank Deposits and Certificates of Deposit $ 836,000 Average interest rate 1.04%
Item 8.
Item 8. Financial Statements and Supplementary Data.
A. Index to Consolidated Financial Statements
Report of Independent Accountants Report of Independent Accountants Consolidated Balance Sheets at December 31, 2003 and 2002 Consolidated Statements of Operations for the three years ended December 31, 2003 Consolidated Statements of Changes in Shareholders' Equity for the three years ended December 31, 2003 Consolidated Statements of Cash Flows for the three years ended December 31, 2003 Notes to Consolidated Financial Statements to
Financial Statements for Stillwater Hydro Partners, L.P.
Ridgewood Electric Power Trust I
Consolidated Financial Statements
December 31, 2003, 2002 and 2001
Report of Independent Accountants
Managing Shareholder and Shareholders' Ridgewood Electric Power Trust I
We have audited the accompanying consolidated balance sheet of Ridgewood Electric Power Trust I and subsidiaries (the "Trust") as of December 31, 2003 and the related consolidated statement of operations, changes in shareholders' equity and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ridgewood Electric Power Trust I and subsidiaries as of December 31, 2003, and the results of their operations and their cash flows for the year ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.
/s/ Perelson Weiner, LLP
New York, NY March 26, 2004
Report of Independent Accountants
To the Shareholders of Ridgewood Electric Power Trust I:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in shareholders' equity and cash flows present fairly, in all material respects, the financial position of Ridgewood Electric Power Trust I and its subsidiaries (the "Trust") at December 31, 2002, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Trust's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP Florham Park, NJ April 3, 2003
Ridgewood Electric Power Trust I Consolidated Balance Sheets - -------------------------------------------------------------------------------- December 31, --------------------------- 2003 2002 ----------- ------------ Assets: Cash and cash equivalents ........................ $ 835,739 $ 1,988,812 Trade receivables ................................ 447,156 440,199 Due from affiliates .............................. 45,354 48,354 Assets held for sale ............................. 243,349 -- Other current assets ............................. 36,863 45,911 ----------- -----------
Total current assets ...................... 1,608,461 2,523,276
Investment in Stillwater Hydro Partners, L.P. .... 635,576 598,867
Equipment held by Ridgewood Rhode Island Generation LLC .................... 1,000,000 --
Plant and equipment .............................. 2,710,725 5,917,134 Accumulated depreciation ......................... (1,197,303) (1,245,519) ----------- ----------- 1,513,422 4,671,615 ----------- -----------
Electric power sales contract .................... 2,207,778 2,207,778 Accumulated amortization ......................... (2,050,084) (1,734,687) ----------- ----------- 157,694 473,091 ----------- -----------
Other non-current assets ......................... 22,570 25,000 ----------- ----------- Total assets ............................. $ 4,937,723 $ 8,291,849 ----------- -----------
Liabilities and Shareholders' Equity: Liabilities: Current maturities of long-term debt ............. $ 299,921 $ 275,067 Accrued professional fees ........................ 92,208 61,281 Accrued fuel expense ............................. 191,616 189,158 Accounts payable and accrued expense ............. 4,545 -- Due to affiliates ................................ 1,810 1,810 ----------- ----------- Total current liabilities ............... 590,100 527,316
Long-term debt, less current portion ............. 652,686 952,607
Commitments and contingencies .................... -- --
Shareholders' Equity: Shareholders' equity (105.5 investor shares issued and outstanding) .............. 3,748,147 6,833,966 Managing shareholder's accumulated deficit (1 management shares issued and outstanding) .. (53,210) (22,040) ----------- ----------- Total shareholders' equity .............. 3,694,937 6,811,926 ----------- -----------
Total liabilities and shareholders' equity ............................. $ 4,937,723 $ 8,291,849 ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I Consolidated Statements of Operations - --------------------------------------------------------------------------------
Year Ended December 31, ------------------------------------------ 2003 2002 2001 ----------- ----------- ------------
Power generation revenue .......... $ 3,203,435 $ 3,262,789 $ 4,140,580 Rental revenue .................... 7,620 89,400 238,574 ----------- ----------- ----------- Total revenue .................. 3,211,055 3,352,189 4,379,154
Cost of sales, including depreciation and amortization of $649,768, $614,196 and $552,722 in 2003, 2002 and 2001 ............. 2,267,435 2,572,063 1,929,321 ----------- ----------- -----------
Gross profit ....................... 943,620 780,126 2,449,833 ----------- ----------- -----------
General and administrative expenses ......................... 432,763 252,466 272,337 Provision for bad debt expense ..... -- -- 480,252 Project development costs .......... -- 71,601 -- Write down of investments in power generation projects ........ 1,772,380 209,251 -- Management fee paid to managing shareholder ....... 68,118 77,734 87,406 ----------- ----------- ----------- Total other operating expenses .................... 2,273,261 611,052 839,995 ----------- ----------- -----------
Income (loss) from operations ...... (1,329,641) 169,074 1,609,838 ----------- ----------- -----------
Other income (expense): Interest income ................. 9,153 33,200 78,584 Interest expense ................ (95,811) (118,606) (10,852) Other expense ................... (29,826) (18,389) (193,379) Equity income (loss) from Stillwater Hydro Partners, L.P. 36,709 36,548 (29,315) ----------- ----------- ----------- Other expense, net ............ (79,775) (67,247) (154,962) ----------- ----------- -----------
Net (loss) income .................. $(1,409,416) $ 101,827 $ 1,454,876 ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I Consolidated Statements of Changes in Shareholders' Equity For the Years Ended December 31, 2003, 2002 and 2001 - --------------------------------------------------------------------------------
Managing Shareholders Shareholder Total ----------- ----------- ----------- Shareholders' equity (deficit), January 1, 2001 ............. $ 6,345,329 $ (26,976) $ 6,318,353
Net income for the year ....... 1,440,327 14,549 1,454,876 ----------- ----------- -----------
Shareholders' equity (deficit), December 31, 2001 ........... 7,785,656 (12,427) 7,773,229
Cash distributions ............ (1,052,499) (10,631) (1,063,130)
Net income for the year ....... 100,809 1,018 101,827 ----------- ----------- -----------
Shareholders' equity (deficit), December 31, 2002 ........... 6,833,966 (22,040) 6,811,926
Cash distributions ............ (1,690,497) (17,076) (1,707,573)
Net loss for the year ......... (1,395,322) (14,094) (1,409,416) ----------- ----------- -----------
Shareholders' equity (deficit), December 31, 2003 ........... $ 3,748,147 $ (53,210) $ 3,694,937 ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I Consolidated Statements of Cash Flows - --------------------------------------------------------------------------------
Year Ended December 31, ----------------------------------------- 2003 2002 2001 ----------- ----------- -----------
Cash flows from operating activities: Net income (loss) ............. $(1,409,416) $ 101,827 $ 1,454,876 ----------- ----------- -----------
Adjustments to reconcile net income (loss) to net cash flows from operating activities: Depreciation and amortization ................ 649,768 614,196 552,722 Writedown of investments in power generation project ................... 1,772,380 209,251 -- Equity in (earnings)/loss from unconsolidated Stillwater Hydro Partners, L.P. ...... (36,709) (36,548) 29,315 Changes in assets and liabilities: (Increase) decrease in trade receivables ........ (6,957) (211,241) 168,804 Decrease (increase) in other current assets ....... 9,048 (28,714) (3,825) Decrease (increase) in other non-current assets .. 2,430 (25,000) -- Decrease (increase) in accounts payable and accrued expenses .......... 4,545 -- (34,693) Increase (decrease) in accrued professional fees . 30,927 (3,426) -- Increase in accrued fuel expense .............. 2,458 139,158 -- Decrease (increase) in due to/from affiliates, net ........ 3,000 (45,963) (40,548) ----------- ----------- ----------- Total adjustments ......... 2,430,890 611,713 671,775 ----------- ----------- ----------- Net cash provided by operating activities ..... 1,021,474 713,540 2,126,651 ----------- ----------- -----------
Cash flows from investing activities: Capital expenditures .......... (191,907) (257,367) (2,471,301) ----------- ----------- ----------- Net cash used in investing activities ............. (191,907) (257,367) (2,471,301) ----------- ----------- -----------
Cash flows from financing activities: Proceeds from long-term debt ............... -- -- 1,500,000 Payments to reduce long-term debt .............. (275,067) (252,272) (20,054) Cash distributions to shareholders ............ (1,707,573) (1,063,130) -- ----------- ----------- ----------- Net cash (used in) provided by financing activities . (1,982,640) (1,315,402) 1,479,946 ----------- ----------- -----------
Net (decrease) increase in cash and cash equivalents ..... (1,153,073) (859,229) 1,135,296 Cash and cash equivalents, beginning of year ............... 1,988,812 2,848,041 1,712,745 ----------- ----------- ----------- Cash and cash equivalents, end of year ..................... $ 835,739 $ 1,988,812 $ 2,848,041 ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust I Notes to the Consolidated Financial Statements - --------------------------------------------------------------------------------
1. Organization and Purpose
Nature of Business Ridgewood Energy Electric Power, L.P. (the "Partnership") was formed as a Delaware limited partnership on March 6, 1991 by Ridgewood Renewable Power LLC (formerly Ridgewood Power Corporation), acting as the general partner. On June 15, 1994, with the approval of the partners, the Partnership merged all of its assets and liabilities into a newly formed trust, called Ridgewood Electric Power Trust I (the "Trust"). Effective July 25, 1994, the Trust elected to be treated as a "business development company" ("BDC") under the Investment Company Act of 1940 (the "1940 Act") and registered its shares under the Securities Act of 1934. In connection with this transaction, the Trust issued 105.5 shares in exchange for outstanding Partnership units. Ridgewood Renewable Power LLC is the sole managing shareholder ("Managing Shareholder").
In November 2001, through a proxy solicitation the Trust requested investor consent to end the BDC status. On December 18, 2001, the consents were tabulated and more than 50% of the investor shares consented to the elimination of the BDC status. Accordingly, the Trust is no longer an investment company under the 1940 Act.
The Trust invests in independent power generation facilities and other power generation assets. These independent power generation facilities include small power production facilities which produce electricity from landfill gas and water.
Christiana Bank & Trust Company, a Delaware trust company, is the Corporate Trustee of the Trust. The Corporate Trustee acts on the instructions of the Managing Shareholder and is not authorized to take independent discretionary action on behalf of the Trust.
2. Summary of Significant Accounting Policies
Principles of consolidation The consolidated financial statements include the accounts of the Trust and its controlled subsidiaries. All material intercompany transactions have been eliminated.
The Trust uses the equity method of accounting for its investments in affiliates which are 50% or less owned if the Trust has the ability to exercise significant influence over the operating and financial policies of the affiliates but does not control the affiliate. The Trust's share of the operating results of the affiliates is included in the Consolidated Statements of Operations.
Use of estimates The preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, requires the Trust to make estimates and judgments that affect the reported amounts of assets, liabilities, sales and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, the Trust evaluates its estimates, including provision for bad debts, carrying value of investments, amortization/depreciation of plant and equipment and intangible assets, and recordable liabilities for litigation and other contingencies. The Trust bases its estimates on historical experience, current and expected conditions and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
New Accounting Standards and Disclosures
SFAS 143 In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143, Accounting for Asset Retirement Obligations, on the accounting for obligations associated with the retirement of long-lived assets. SFAS 143 requires a liability to be recognized in the consolidated financial statements for retirement obligations meeting specific criteria. Measurement of the initial obligation is to approximate fair value, with an equivalent amount recorded as an increase in the value of the capitalized asset. The asset will be depreciated in accordance with normal depreciation policy and the liability will be increased for the time value of money, with a charge to the income statement, until the obligation is settled. SFAS 143 is effective for fiscal years beginning after June 15, 2002. The Trust adopted SFAS 143 effective January 1, 2003, with no material impact on the consolidated financial statements.
SFAS 145 In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Correction. SFAS No. 145 eliminates extraordinary accounting treatment for reporting gain or loss on debt extinguishment, and amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The Trust adopted SFAS 145 effective January 1, 2003, with no material impact on the consolidated financial statements.
SFAS 146 In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires recording costs associated with exit or disposal activities at their fair values when a liability has been incurred. The Trust adopted SFAS 146 effective January 1, 2003, with no material impact on the consolidated financial statements.
FIN 45 In November 2002, the FASB issued FASB Interpretation No. 45 ("FIN 45"), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees and Indebtedness of Others." FIN 45 elaborates on the disclosures to be made by the guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also requires that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002; while the provisions of the disclosure requirements are effective for financial statements of interim or annual reports ending after December 15, 2002. The Trust adopted FIN 45 with no material impact to the consolidated financial statements.
FIN 46 In December 2003, the FASB issued FASB Interpretation No. 46, (Revised December 2003) "Consolidation of Variable Interest Entities" ("FIN 46") which changes the criteria by which one company includes another entity in its consolidated financial statements. FIN 46 requires a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity's activities or entitled to receive a majority of the entity's residual returns or both. The consolidation requirements of FIN 46 apply immediately to variable interest entities created after December 31, 2003, and apply in the first fiscal period ending after March 15, 2004, for variable interest entities created prior to January 1, 2004. The Trust adopted the disclosure provisions of FIN 46 effective December 31, 2002, with no material impact to the consolidated financial statements. The Trust will implement the full provisions of FIN 46 effective January 1, 2004 and does not anticipate a material impact to the consolidated financial statements.
SFAS 149 In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Trust adopted SFAS 149 effective July 1, 2003, with no material impact on the consolidated financial statements.
SFAS 150 In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for classifying and measuring certain financial instruments with characteristics of both liabilities and equity. The Trust adopted SFAS 150 effective July 1, 2003, with no material impact on the consolidated financial statements.
Significant Accounting Policies
Cash and cash equivalents The Trust considers all highly liquid investments with maturities of three months or less when purchased, to be cash and cash equivalents. Cash and cash equivalents consist of commercial paper and funds deposited in bank accounts. Cash balances with banks as of December 31, 2003, exceed insured limits by approximately $820,000.
Trade receivables Trade receivables are recorded at invoice price and do not bear interest. No allowance for bad debt expense was provided based upon historical write-off experience, evaluation of customer credit condition and the general economic status of the customer.
Impairment of Long-Lived Assets and Intangibles In accordance with the provisions of SFAS No. 144, Accounting for the Impairment of Long-Lived Assets to be Disposed Of, the Trust evaluates long-lived assets, such as fixed assets and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is made by comparing the carrying value of an asset to the estimated undiscounted cash flows attributable to that asset. If an impairment has occurred, the impairment loss recognized is the amount by which the carrying value exceeds the discounted cash flows attributable to the asset or the estimated fair value of the asset.
Plant and equipment Plant and equipment, consisting principally of electrical generating equipment, is stated at cost. Major renewals and betterments that increase the useful lives of the assets are capitalized. Repair and maintenance expenditures that increase the efficiency of the assets are expensed as incurred. The Trust periodically assesses the recoverability of plant and equipment, and other long-term assets, whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
Depreciation is recorded using the straight-line method over the useful lives of the assets, which are 5 to 20 years with a weighted average of 14 and 16 years at December 31, 2003 and 2002, respectively. During 2003, 2002 and 2001, the Trust recorded depreciation expense of $334,370, $298,798, and $237,324, respectively.
Electric Power Sales Contract A portion of the purchase price of the Brea Project was assigned to the electric power sales contract and is being amortized over the life of the contract (7 years) on a straight-line basis. The electric power sales contract is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. During 2003, 2002 and 2001, the Trust recorded amortization expense of $315,398 each year.
Revenue recognition Power generation revenue is recorded in the month of delivery, based on the estimated volumes sold to customers at rates stipulated in the power sales contract. Adjustments are made to reflect actual volumes delivered when the actual information subsequently becomes available. Billings to customers for power generation generally occurs during the month following delivery. Final billings do not vary significantly from estimates. Interest income is recorded when earned.
Supplemental cash flow information Total interest paid during the years ended December 31, 2003, 2002 and 2001 was $95,811, $118,606 and $10,852, respectively.
In the fourth quarter of 2003, the Trust recorded $1,000,000 in Equipment held by Ridgewood Rhode Island Generation LLC and $243,349 in Assets held for sale. Accordingly, the Trust reduced Plant and equipment $1,243,349.
Significant Customer and Supplier During 2003, 2002 and 2001, the Trust's largest customer, Southern California Edison ("SCE"), accounted for 100%, 97% and, 95%, respectively of total revenues. In early 2001, SCE experienced severe financial difficulty, see Note 8 for additional discussion. During 2003, 2002 and 2001, the Trust purchased 100% of its gas from one supplier.
Income taxes No provision is made for income taxes in the accompanying consolidated financial statements as the income or losses of the Trust are passed through and included in the tax returns of the individual shareholders of the Trust. At December 31, 2003 and 2002, the Trust's net assets had a tax basis of $5,010,723 and $7,605,812, respectively.
Reclassification Certain items in previously issued consolidated financial statements have been reclassified for comparative purposes. This had no effect on income or loss.
3. Projects
Brea Power Partners, L.P. (known as the Brea Project) In October 1994, the Trust invested in a limited partnership ("Brea Partnership"), which acquired a 5 megawatt gas-fired electric generating facility and related landfill gas processing facility in Brea, California. On June 1, 1997, the Trust purchased the general and other limited partnership interests in Brea to increase its ownership in the Brea Project to 100%. The aggregate purchase price of the Trust's investments totaled $5,916,879 including, the assumption of liabilities and acquisition costs.
Electricity generated by the Brea Project, over and above its own requirements, is sold to SCE under a Power Contract. The Power Contract may be terminated by either party no earlier than the end of 2004 on 5 years' advance notice. On March 23, 2000, SCE provided such written notice to the Brea Project notifying the Brea Project it was electing to terminate the Power Contract as of March 23, 2005. After such termination, the Brea Project will sell its electric output in the competitive electric power market The landfill gas is produced from a landfill owned by the County of Orange, California and is collected and sold by GSF Energy, L.L.C. ("GSF") under a gas lease agreement between GSF and the County of Orange.
In addition to procuring a long-term power contract, the Brea Project is faced with the possible termination of its operations as of January 2005 as a result of its inability to comply with certain environmental regulations. The Brea Project operates within the jurisdiction of the South Coast Air Quality Management District ("South Coast"), the air pollution control agency for Orange County in Southern California. South Coast promulgated Rule 1110-2 (the "Rule") regarding air emissions from gaseous and liquid-fueled stationary engines which generally imposes very low air emissions levels on such engines, which include the generating engines used by and located at the Brea Project. According to the Rule, existing, or to be installed, electric generating engines must be in compliance with the new emissions levels by January 2005 or cease operations or, if operations continue, risk severe penalties from South Coast. The electric generating engines used by the Brea Project cannot, in their current configuration, comply with the Rule. The Brea Project requested from South Coast an extension of the Rule's application, but South Coast has rejected the project's request. As a result, the Brea Project essentially has three options with respect to the Rule (i) cease operations as of January 2005, (ii) upgrade and/or repair the existing engines, if possible, to comply with the Rule's emissions levels, or (iii) repower the Brea Project with new engines capable of complying with the emissions levels. The Trust is seeking a workable alternative to ceasing its operations at the Brea Project and, as a result, has been investigating whether the existing engines can be upgraded or repaired to comply with the Rule's air emissions levels. As of December 31, 2003, the Trust has not currently been able to find any such solution that is or can be demonstrated to be both successful and economically feasible. At December 31, 2003, the Trust believes that the anticipated cash flows and salvage value of the project are sufficient to support the carrying value of the Brea Project. The Trust will continue to research possible solutions and will record a valuation adjustment, if warranted, when alternatives, or lack thereof, become more determinable.
Ridgewood Mobile Power I, LLC (a wholly owned subsidiary) Effective August 1999, the Trust acquired two Caterpillar mobile power modules with a total capacity of 2.35 megawatts for $710,241. These modules are rented to domestic and international customers. As per an agreement with Hawthorne Power Systems ("Hawthorne"), the Trust pays Hawthorne, a California company that maintains a large fleet of similar rental modules, a fee of 20% of gross rental revenues to arrange and administer the rental of the units. The revenue from these modules is included as rental revenue and Hawthorne's fee is included in cost of sales in the Consolidated Statements of Operations.
Due to the increase in competition and production of newer efficient models, the Trust experienced a decrease in rental revenue for the second consecutive year. As a result of the change in these market conditions, the forecasted revenues for the mobile power modules are not expected to be enough to recover the units' book value. In 2003 and 2002, the Trust recorded writedowns of $44,143 and $209,251, respectively, to reflect the units fair market value. The writedowns have been presented as a separate line item under other operating expenses in the Consolidated Statements of Operations. In the third quarter of 2003, the Trust decided to make its mobile power modules available for sale. Accordingly, the remaining net book value of $243,349, as of December 31, 2003, is reflected as Assets held for sale on the accompanying Consolidated Balance Sheet.
Ridgewood Olinda, LLC (known as the Olinda Project) In April 2001, the Trust formed Ridgewood Olinda, LLC. Ridgewood Olinda, LLC, (`Ridgewood Olinda") contracted with an unaffiliated engineering and construction firm ("the firm") to construct a $3,000,000 2.5 megawatt expansion to the Brea Project. The construction of the new addition was completed in the second quarter of 2002.
The Olinda Project began commercial operation on or about May of 2002 and had been selling its electric output in California to the California Power Authority ("CPA") pursuant to a short-term (ninety-day) power sales contract. The short-term contract was extended by the CPA through December 31, 2002, along with several other contracts with renewable (biomass) generators. Prior to the expiration of the extension, the CPA offered additional six-month extension to several biomass generators but did not offer a similar extension to the Olinda Project. In addition, the Olinda Project submitted a proposal to SCE in response to SCE's request for proposals for short-term procurement. The Olinda Project offered to sell SCE power pursuant to a five-year contract at prices favorable to Olinda, but slightly above prices apparently submitted by other renewable generators. SCE did not accept the Olinda Project's proposal.
Within several months of commercial operation, one of the electric generating machines installed by the firm experienced a catastrophic failure. Although the firm provided a replacement engine to Ridgewood Olinda, the Olinda Project was subsequently shut-down in October of 2002 by the Orange County electrical inspector due to the firm's failure to install a proper electric switchgear or obtain a permit for the installed switchgear. The engine failure and switchgear problems highlighted significant other failures of the firm, including, but not limited to, the firm's failure to obtain final building permits, failure to deliver operating manuals or provide training, and numerous other issues.
In the second quarter of 2003, Ridgewood Olinda and the firm agreed that the firm would refurbish and recondition the engines to their original state. In return, Ridgewood Olinda would pay $200,000 of the remaining $250,000 it owed the firm under the original agreement. In the third quarter, Ridgewood Olinda made the final payment of $200,000.
As a result of the problems experienced at the Olinda Project site in Southern California including, but not limited to, the construction problems with the engineering and construction firm and the fact that the Olinda Project did not have a power contract, the Trust elected to relocate the electric generating equipment of the Olinda Project, to the site of a new landfill gas development of the Trust's affiliate, the Ridgewood Power B Fund/ Providence Expansion. Accordingly, the Olinda project had its engines removed from its facility for refurbishment and reconditioning during the third quarter of 2003. Upon completion of the overhaul, the engines were transferred to Rhode Island, where they are being installed in the Ridgewood Rhode Island generation facility, the new landfill gas development site of the Ridgewood Power B Fund/ Providence Expansion.
As of October 1, 2003, Ridgewood Olinda entered into a lease agreement with Ridgewood Rhode Island Generation LLC, (a subsidiary of the Ridgewood Power B Fund/ Providence Expansion) whereby Ridgewood Olinda will receive 15% of the available cash flows (as defined) of the Ridgewood Rhode Island generation facility. The agreement will remain in effect as long as the Ridgewood Rhode Island generation facility is in operation. Any payments received arising from the agreement will be treated as a reduction of the carrying value of the segregated asset until said asset has been bought down to zero, or until circumstances have changed sufficiently whereby it would be appropriate for the Trust to recognize income, if any, on the transaction.
As a result of the relocation and installation of the Olinda project's engines in Rhode Island, the Trust recorded a write down of approximately $1,728,000 in the third quarter of 2003 with $1,000,000 representing the remaining estimated fair value of the project.
Stillwater Hydro Partners, L.P. On October 31, 1991, the Trust acquired, for $1,000,000, a 32.5% general partner's interest in a limited partnership whose sole business is the construction, ownership and operation of a 3.5 megawatt hydroelectric facility, located on the Hudson River in Stillwater, New York (the "Stillwater Project"). At the time of the investment, the project was under construction and commenced operations in May 1993. Electricity generated by the Stillwater Project is sold to the Niagara Mohawk Power Corporation under a long-term Power Contract that expires in 2028.
On May 16, 1994, the Trust, as stipulated in the limited partnership agreement, elected to exchange its general partner interest for a 32.5% limited partnership interest, which includes a priority distribution of available cash flow from the project in the aggregate amount of $1,000,000. Such distribution is payable from available cash flows in nine annual installments together with cumulative interest at 12% per year, which were scheduled to begin in May 1995. To date, no payments have been received and any future proceeds will be recorded in income on an as received basis.
The ultimate ability of the project to meet its payment obligations to the Trust is dependent on the actual operating performance of the Stillwater Project, which, in turn, is largely dependent upon water levels in the Hudson River. Since 1995, water levels in the Hudson River basin have frequently been below normal. Due to the low water levels, the operating results of the project were insufficient to meet its debt payments, and accordingly, no distributions were made to the Trust since 1994. As a result, all available cash flow from the Stillwater Project is being applied to meet its debt service requirements. Until the current debt service requirements are paid, it appears likely that most, if not all, of the payments due to the Trust will be carried forward into subsequent years.
The Trust accounts for its investment in the Stillwater Project under the equity method of accounting. The Trust's equity in the income/loss of the Stillwater Project has been included in the consolidated financial statements since acquisition, subject to certain adjustments.
Summarized financial information for the Stillwater Project is as follows:
Balance Sheet Information
As of December 31, ----------------------- 2003 2002 ---------- ----------
Current assets .............. $ 270,014 $ 225,380 Non-current assets .......... 8,187,390 8,549,483 ---------- ---------- Total assets ................ $8,457,404 $8,774,863 ---------- ----------
Current liabilities ......... $ 871,637 $ 783,911 Long-term debt .............. 3,871,054 4,404,898 Other non-current liabilities 2,751,000 2,615,292 Equity ...................... 963,713 970,762 ---------- ---------- Total liabilities and equity $8,457,404 $8,774,863 ---------- ----------
Adjusted Trust share ........ $ 635,576 $ 598,867 ---------- ----------
Statement of Operations Information
For the Year Ended December 31, ----------------------------------------- 2003 2002 2001 ----------- ----------- -----------
Revenue ............ $ 1,310,630 $ 1,384,041 $ 1,262,217 ----------- ----------- ----------- Operating expenses . 696,732 709,994 723,886 Other expense ...... 620,947 681,643 748,532 ----------- ----------- ----------- Total expenses ..... 1,317,679 1,391,637 1,472,418 ----------- ----------- ----------- Net loss ........... $ (7,049) $ (7,546) $ (210,201) ----------- ----------- -----------
Adjusted Trust Share $ 36,709 $ 36,548 $ (29,315) ----------- ----------- -----------
4. Long-Term Debt
In August 2001, Ridgewood Olinda, LLC entered into an agreement, effective December 2001, to borrow $1,500,000. The proceeds from the loan were used to finance the 2.5 megawatt expansion of the Olinda facility. The collateralized non-recourse notes are due in monthly installments of $30,906, including interest at 8.68%. Final payment is due on November 30, 2006. The loan is collateralized by the equipment that was originally installed at the Olinda facility, which has now been transferred to Rhode Island.
Following is a summary of long-term debt at December 31, 2003 and 2002:
2003 2002 ----------- ----------- Senior collateralized non-recourse notes $ 952,607 $ 1,227,674 payable Less - current maturity ................ (299,921) (275,067) ----------- ----------- Total long-term debt ................... $ 652,686 $ 952,607 ----------- -----------
Remaining scheduled repayments of long-term debt principal are as follows:
Year Ended December 31, Repayment - ------------ --------- 2004 $299,921 2005 327,022 2006 325,664 -------- Total $952,607 --------
5. Commitments
The Brea project has a long-term agreement to purchase landfill gas from its supplier. The agreement expires in December 2018 and is adjusted annually for inflation through December 31, 2004.
Future minimum purchases under the agreement as of December 31, 2003 are as follows:
Year Ended December 31, Purchases ------------ --------- 2004 $ 774,266 2005 720,000 2006 720,000 2007 720,000 2008 720,000 Thereafter 7,200,000 ------------ Total $ 10,854,266 ------------
6. Transactions With Managing Shareholder and Affiliates
The Trust entered into a management agreement with the Managing Shareholder, under which the Managing Shareholder renders certain management, administrative and advisory services and provides office space and other facilities to the Trust. As compensation to the Managing Shareholder, the Trust pays the Managing Shareholder an annual management fee equal to 1% of the prior year's net assets of the Trust payable monthly. During 2003, 2002 and 2001, the Trust paid management fees to the Managing Shareholder of $68,118, $77,734 and $87,406, respectively.
Under the Declaration of Trust, the Managing Shareholder is entitled to receive each year 1% of all distributions made by the Trust (other than those derived from the disposition of Trust property) until the shareholders have been distributed a cumulative amount equal to 15% per annum of their equity contribution. Thereafter, the Managing Shareholder is entitled to receive 20% of the distributions for the remainder of the year. The Managing Shareholder is entitled to receive 1% of the proceeds from dispositions of Trust properties until the shareholders have received cumulative distributions equal to their original investment ("Payout"). After Payout, the Managing Shareholder is entitled to receive 20% of all remaining distributions of the Trust.
As a result of the distributions paid in January of 2004, the Trust's cumulative distributions have reached Payout. Accordingly, the Managing Shareholder received, and will continue to receive, 20% of the distributions of the Trust.
The Managing Shareholder and affiliates own, in the aggregate, 3.0 investor shares of the Trust with a cost of $273,000. The Trust granted the Managing Shareholder a single Management Share representing the Managing Shareholder's management rights and rights to distributions of cash flow.
Under an Operating Agreement with the Trust, Ridgewood Power Management LLC ("Ridgewood Management"), an entity related to the Managing Shareholder through common ownership, provides management, purchasing, engineering, planning and administrative services to the projects operated by the Trust. Ridgewood Management charges the projects at its cost for these services and for the allocable amount of certain overhead items. Allocations of costs are on the basis of identifiable direct costs or in proportion to amounts invested in projects managed by Ridgewood Management. During the year ended December 31, 2003, 2002 and 2001, Ridgewood Management charged the Brea Project $129,716, $181,563 and $165,083, respectively, for overhead items allocated in proportion to the amount invested in projects managed. During the year ended December 31, 2003, 2002 and 2001, Ridgewood Management charged the Olinda Project $9,277, $14,214 and $0, respectively, for overhead items allocated in proportion to the amount invested in projects managed. Ridgewood Management also charged the Brea and Olinda projects for all of the direct operating and non-operating expenses incurred during the period.
From time to time, the Trust records short-term payables and receivables from other affiliates in the ordinary course of business. The amounts payable and receivable do not bear interest. At December 31, 2003 and 2002, the Trust had short-term receivables from affiliates in the amounts of $45,354 and $48,354, respectively.
7. Fair Value of Financial Instruments
At December 31, 2003 and 2002, the carrying value of the Trust's cash and cash equivalents, trade receivables, and accounts payable and accrued expenses approximates their fair value. The fair value of the long-term debt, calculated using current rates for loans with similar maturities, does not differ materially from its carrying value.
8. Sale of Trade Receivables
In January 2001, SCE informed the Brea Project, as well as numerous other unaffiliated electric generating facilities in California, that it was temporarily suspending payments to such facilities due to SCE's severe financial problems. SCE did not pay the Brea Project for energy and capacity delivered to SCE for the months of November and December 2000, January and February 2001. In April 2001, the Brea Project entered into an agreement with a financial institution whereby it sold, irrevocably and without recourse, its undivided interest in all eligible trade accounts receivables for those months. Costs associated with the sale of receivables of $480,252 in 2001, primarily related to the discount and loss on sale, is included in provision for bad debt expense in the Consolidated Statements of Operations. SCE is current in its payments for energy and capacity delivered after February 2001.
B. Supplementary Financial Information (Unaudited)
Selected Quarterly Financial Data for the years ended December 31, 2003 and 2002.
------------------------------------------------------- First Second Third Fourth Quarter Quarter Quarter Quarter - ------------------ ----------- ----------- ----------- ----------- Revenue .......... $ 731,000 $ 706,000 $ 1,072,000 $ 702,000 Income (loss) from operations ...... 117,000 (132,000) (1,366,000) 51,000 Net income (loss) 100,000 (127,000) (1,386,000) 4,000
--------------------------------------------------- First Second Third Fourth Quarter Quarter Quarter Quarter - ------------------ ---------- ---------- ---------- ---------- Revenue .......... $ 539,000 $ 845,000 $1,235,000 $ 733,000 Income (loss) from operations ...... (43,000) (87,000) 447,000 (148,000) Net income (loss) (69,000) (194,000) 402,000 (37,000)
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
The Trust dismissed PricewaterhouseCoopers LLP as its independent accountants on January 14, 2004 and appointed Perelson Weiner LLP as successor, as reported in the Trust's Current Report on Form 8-K dated January 20, 2004, incorporated herein by reference. There were no disagreements with PricewaterhouseCoopers LLP for the years ended December 31, 2002 and 2001 or for the interim period through January 20, 2004, whether or not resolved, on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of PricewaterhouseCoopers LLP would have caused them to make reference thereto in their report on the financial statements for such years.
Item 9A.
Item 9A. Controls and Procedures
Within the 90 days prior to the filing date of this Report, the Trust's Chief Executive Officer and Chief Financial Officer conducted an evaluation of the effectiveness and design of the Trust's disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer each concluded that the disclosure controls and procedures were effective.
There have been no significant changes in the internal controls or in other factors that could significantly affect these controls subsequent to the date that they completed their evaluation.
The term "disclosure controls and procedures" is defined in Rule 13a-15(e) of the Exchange Act as "controls and other procedures designed to ensure that information required to be disclosed by the issuer in the reports, files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the [Securities and Exchange] Commission's rules and forms." The Trust's disclosure controls and procedures are designed to ensure that material information relating to the consolidated subsidiaries is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding the required disclosures.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
(a) General.
As Managing Shareholder of the Trust, Ridgewood Renewable Power LLC has direct and exclusive discretion in management and control of the affairs 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.
(b) Managing Shareholder.
Ridgewood Power Corporation was incorporated in February 1991 as a Delaware corporation for the primary purpose of acting as a managing shareholder of business trusts and as a managing general partner of limited partnerships. It organized the Trust and acted as managing shareholder until April 1999. On or about April 21, 1999 it was merged into the current Managing Shareholder, Ridgewood Power LLC. In December of 2002, Ridgewood Power, LLC changed its name to Ridgewood Renewable Power, LLC. Robert E. Swanson is the controlling member, sole manager and President of the Managing Shareholder. All of the equity in the Managing Shareholder is owned by Mr. Swanson or by family trusts. Mr. Swanson has the power on behalf of those trusts to vote or dispose of the membership equity interests owned by them.
The Managing Shareholder has also organized the Other Power Trusts as Delaware business trusts or other Delaware limited liability companies. Ridgewood Renewable Power LLC is the managing shareholder of the Other Power Trusts and the manager of the Ridgewood LLCs. The business objectives of these trusts and LLCs are similar to those of the Trust.
A number of other companies are affiliates of Mr. Swanson and the Managing Shareholder. Each of these also was organized as a corporation that was wholly-owned by Mr. Swanson. In April 1999, most of them were merged into limited liability companies with similar names and Mr. Swanson became the sole manager and controlling owner of each limited liability company.
The Managing Shareholder is an affiliate of Ridgewood Energy Corporation ("Ridgewood Energy"), which has organized and operated 48 limited partnership funds and one business trust (of which 25 have terminated) and which had total capital contributions in excess of $190 million. The programs operated by Ridgewood Energy have invested in oil and natural gas drilling and completion and other related activities. Other affiliates of the Managing Shareholder include Ridgewood Securities, an NASD member, which has been the placement agent for the private placement offerings of the eight trusts and three LLCs sponsored by Ridgewood Renewable Power, LLC and the funds sponsored by Ridgewood Capital, which assists in offerings made by the Managing Shareholder and which is the sponsor of privately offered venture capital funds. Each of these companies is controlled by Robert E. Swanson, who is their sole director or manager.
Set forth below is certain information concerning Mr. Swanson and other executive officers of the Managing Shareholder.
Robert E. Swanson, age 57, has served as Chief Executive Officer of the Trust since its inception in 1991 and as Chief Executive Officer of RPM, the Other Power Trusts and the Ridgewood LLCs since their respective inceptions. Mr. Swanson has been President and registered principal of Ridgewood Securities and became the Chairman of the Board of Ridgewood Capital on its organization in 1998. He also is Chairman of the Board of the Ridgewood Capital Venture Partners I, II, III and IV venture capital funds ("Ridgewood Venture Funds"). In addition, he has been President and sole stockholder of Ridgewood Energy since its inception in October 1982. Prior to forming Ridgewood Energy in 1982, Mr. Swanson was a tax partner at the former New York and Los Angeles law firm of Fulop & Hardee and an officer in the Trust and Investment Division of Morgan Guaranty Trust Company. His specialty is in personal tax and financial planning, including income, estate and gift tax. Mr. Swanson is a member of the New York State and New Jersey bars, the Association of the Bar of the City of New York and the New York State Bar Association. He is a graduate of Amherst College and Fordham University Law School.
Randall Holmes, age 56, has served as the President and Chief Operating Officer of the Managing Shareholder, RPM, the Trust, the Other Power Trusts and the Ridgewood LLCs since January 1, 2004. Prior to that, he served as the primary outside counsel to and has represented the Managing Shareholder and its affiliates since 1991. Mr. Holmes has over 30 years of acquisition, development, financing and operating experience in the electric generation and other industries. Mr. Holmes previously was counsel to Downs Rachlin Martin PLLC in Vermont ("DRM"), to DeForest & Duer in New York and to Chadbourne & Parke in New York. Mr. Holmes was also President of the Pepsi-Cola Operating Company of Chesapeake and Indianapolis and was Vice President of Advanced Medical Technologies. He was also a Partner with the New York law firm of Barrett Smith Schapiro Simon & Armstrong where he specialized in financing transactions, acquisitions and tax planning. DRM is one of the primary outside counsel to the Trust, Managing Shareholder and their affiliates. Immediately prior to being appointed President and Chief Operating Officer, Mr. Holmes was counsel to DRM. He has maintained a minor consulting relationship with DRM in which he may act as a paid advisor to DRM on certain matters that are unrelated to Ridgewood. Such relationship will not require a significant amount of Mr. Holmes' time and it is expected that such relationship will not adversely affect his duties as President and Chief Operating Officer.
Robert L. Gold, age 45, has served as Executive Vice President of the Managing Shareholder, RPM, the Trust, the Other Power Trusts and the Ridgewood LLCs since their respective inceptions. He has been President of Ridgewood Capital since its organization in 1998. As such, he is President of the Ridgewood Venture Funds. He has served as Vice President and General Counsel of Ridgewood Securities Corporation since he joined the firm in December 1987. Mr. Gold has also served as Executive Vice President of Ridgewood Energy since October 1990. He served as Vice President of Ridgewood Energy from December 1987 through September 1990. For the two years prior to joining Ridgewood Energy and Ridgewood Securities, Mr. Gold was a corporate attorney in the law firm of Cleary, Gottlieb, Steen & Hamilton in New York City where his experience included mortgage finance, mergers and acquisitions, public offerings, tender offers, and other business legal matters. Mr. Gold is a member of the New York State bar. He is a graduate of Colgate University and New York University School of Law.
Daniel V. Gulino, age 43, has been Senior Vice President and General Counsel of the Managing Shareholder, RPM, the Trust, Other Power Trusts and the Ridgewood LLCs since August 2000. He began his legal career as an associate for Pitney, Hardin, Kipp & Szuch, a large New Jersey law firm, where his experience included corporate acquisitions and transactions. Prior to joining Ridgewood, Mr. Gulino was in-house counsel for several large electric utilities, including GPU, Inc., Constellation Power Source, Inc., and PPL Resources, Inc., where he specialized in non-utility generation projects, independent power and power marketing transactions. Mr. Gulino also has experience with the electric and natural gas purchasing of industrial organizations, having worked as in-house counsel for Alumax, Inc. (now part of Alcoa) where he was responsible for, among other things, Alumax's electric and natural gas purchasing program. Mr. Gulino is a member of the New Jersey State Bar and Pennsylvania State Bar. He is a graduate of Fairleigh Dickinson University and Rutgers University School of Law - - Newark.
Christopher I. Naunton, 39, has been the Vice President and Chief Financial Officer of the Managing Shareholder, RPM, the Trust, Other Power Trusts and the Ridgewood LLCs since April 2000. From February 1998 to April 2000, he was Vice President of Finance of an affiliate of the Managing Shareholder. Prior to that time, he was a senior manager at the predecessor accounting firm of PricewaterhouseCoopers LLP. Mr. Naunton's professional qualifications include his certified public accountant qualification in Pennsylvania, membership in the American Institute of Certified Public Accountants and the Pennsylvania Institute of Certified Public Accountants. He holds a Bachelor of Science degree in Business Administration from Bucknell University (1986).
Mary Lou Olin, age 51, has served as Vice President of the Managing Shareholder, RPM, Ridgewood Capital, the Trust, Other Power Trusts and the Ridgewood LLCs since their respective inceptions. She has also served as Vice President of Ridgewood Energy since October 1984, when she joined the firm. Her primary areas of responsibility are investor relations, communications and administration. Prior to her employment at Ridgewood Energy, Ms. Olin was a Regional Administrator at McGraw-Hill Training Systems where she was employed for two years. Prior to that, she was employed by RCA Corporation. Ms. Olin has a Bachelor of Arts degree from Queens College.
(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 administrative and service expenses necessary to perform the foregoing obligations. The Trust will pay all other expenses of the Trust, including transaction expenses, valuation costs, expenses of preparing and printing periodic reports for Investors and the Commission, postage for Trust mailings, Commission fees, interest, taxes, legal, accounting and consulting fees, litigation expenses and other expenses properly payable by the Trust. The Trust will reimburse the Managing Shareholder for all such Trust expenses paid by it.
As compensation for the Managing Shareholder's performance under the Management Agreement, the Trust is obligated to pay the Managing Shareholder an annual management fee described below at Item 13 -- Certain Relationships and Related Transactions.
Each Investor consented to the terms and conditions of the initial Management Agreement by subscribing to acquire Investor Shares in the Trust. The Management Agreement is subject to termination at any time on 60 days' prior notice by a majority in interest of the Investors or the Managing Shareholder. The Management Agreement is subject to amendment by the parties with the approval of a majority in interest of the Investors.
(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) Corporate Trustee
The Corporate Trustee of the Trust is Christiana Bank & Trust Company. Legal title to Trust Property is in the name of the Trust. Christiana Bank is also a trustee of the Other Power Trusts. The principal office of Christiana Bank is 1314 King Street, Wilmington, DE 19801.
The Trust has relied and will continue to rely on the Managing Shareholder and engineering, legal, investment banking and other professional consultants (as needed) and to monitor and report to the Trust concerning the operations of Projects in which it invests, to review proposals for additional development or financing, and to represent the Trust's interests. The Trust will rely on such persons to review proposals to sell its interests in Projects in the future.
(f) Section 16(a) Beneficial Ownership Reporting Compliance
All individuals subject to the requirements of Section 16(a) have complied with those reporting requirements during 2003.
(g) RPM.
As discussed above at Item 1 - Business, RPM assumed day-to-day management responsibility for the Brea Project, effective June 1, 1997. Like the Managing Shareholder, RPM is wholly owned by Robert E. Swanson. RPM also provided management services to the Olinda Project. RPM charges the Trust at its cost for these services and for the Trust's allocable amount of certain overhead items. RPM shares space and facilities with the Managing Shareholder and its affiliates. To the extent that common expenses can be reasonably allocated to RPM, the Managing Shareholder may, but is not required to, charge RPM at cost for the allocated amounts and such allocated amounts will be borne by the Trust and other programs. Common expenses that are not so allocated will be borne by the Managing Shareholder.
The Managing Shareholder does not charge RPM for the full amount of rent, utilities, supplies and office expenses allocable to RPM. As a result, RPM's charges for its services to the Trust are likely to be materially less than its economic costs and the costs of engaging comparable third persons as managers. RPM will not receive any compensation in excess of its costs.
Allocations of costs are made either on the basis of identifiable direct costs, time records or in proportion to each program's investments in Projects managed by RPM; and allocations are made in a manner consistent with generally accepted accounting principles.
RPM does not provide any services related to the administration of the Trust, such as investment, accounting, tax, investor communication or regulatory services, nor will it participate in identifying, acquiring or disposing of Projects. RPM does not have the power to act in the Trust's name or to bind the Trust, which will be exercised by the Managing Shareholder or the Trust's officers.
The Operation Agreement does not have a fixed term and is terminable by RPM, by the Managing Shareholder or by vote of a majority in interest of Investors, on 60 days' prior notice. The Operation Agreement may be amended by agreement of the Managing Shareholder and RPM; however, no amendment that materially increases the obligations of the Trust or that materially decreases the obligations of RPM shall become effective until at least 45 days after notice of the amendment, together with the text thereof, has been given to all Investors.
The executive officers of RPM are the same as the officers for the Managing Shareholder, as set forth above.
(h). Code of Ethics.
The Managing Shareholder has adopted a Code of Ethics in March 2004 for itself, the Trust, Other Power Trusts, Ridgewood LLCs and affiliates. The Code of Ethics is attached hereto as Exhibit 10P.
Item 11.
Item 11. Executive Compensation.
The Managing Shareholder compensates its officers without additional payments by the Trust. The Trust will reimburse RPM at cost for services provided by RPM's employees. Information as to the fees payable to the Managing Shareholder and certain affiliates is contained at Item 13 - Certain Relationships and Related Transactions.
Christiana, 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 105.5 Investor Shares (approximately $10.5 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 March 31, 1992. Further details concerning the offering are set forth above at Item 1 - -Business. No person beneficially owns 5% or more of the Investor Shares.
The Managing Shareholder of the Trust, purchased for cash in the offering 1 Investor Share, equal to .9 of 1% of the outstanding Investor Shares, and Mr. Swanson purchased an additional 2.1 Investor Shares. The total cost of the 3.0 Investor Shares was $273,000. By virtue of its purchase of that Investor Share, Ridgewood Power is entitled to the same ratable interest in the Trust as all other purchasers of Investor Shares. No other 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 Ridgewood Power in its capacity as the Managing Shareholder (excluding its interest in the Trust attributable to Investor Shares it acquired in the offering). The management rights of Ridgewood Power are described in further detail above at Item 1 - Business and in Item 10 - Directors and Executive Officers of the Registrant. Its beneficial interest in cash distributions of the Trust and its allocable share of the Trust's net profits and net losses and other items attributable to the Management Share are described in further detail below at Item 13.
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable reserves that 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 received annual distributions equal to 15% of their Capital Contributions (a "15% Priority Distribution") and thereafter any remaining distributions will be allocated 80% to the 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 2003 and 2002, the Trust made distributions to the Managing Shareholder (which is a member of the Board of the Trust) as stated at Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters. In addition, the Trust and its subsidiaries paid fees and reimbursements to the Managing Shareholder and its affiliates as follows:
2003 2002 2001 2000 1999 Paid to Managing Shareholder $68,118 $77,734 $87,406 $70,083 $76,332 Cost reimbursement RPM $2,176,067 $2,418,929 $1,842,315 $1,255,007 $1,334,451
The management fee, payable monthly under the Management Agreement at the annual rate of 1% of the Trust's prior year net asset value (until June 1994, of the Trust's total capital contributions), began on the closing of the offering 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. Payroll and other costs of operation of the Trust's Projects are reimbursements to RPM, which do not exceed its actual costs, are described at Item 10(g) - Directors and Executive Officers of the Registrant -- RPM.
Other information in response to this item is reported in response to Item 11 -- Executive Compensation, which information is incorporated by reference into this Item 13.
Item 14.
Item 14. Principal Accountant Fees and Services
Audit Fees
The aggregate audit fees billed for professional services rendered by Perelson Weiner LLP for the audit of the Company's annual financial statements for the year ended December 31, 2003 were approximately $26,000. The aggregate audit fees billed for professional services rendered by PricewaterhouseCoopers LLP for the audit of the Company's annual financial statements and financial statements included in the Company's Quarterly Reports on Form 10-Q for the years ended December 31, 2003 and 2002 were approximately $17,000 and $31,000, respectively.
Tax Fees
The aggregate fees billed for all tax services rendered by Perelson Weiner LLP for the year ended December 31, 2003 were approximately $28,000. There were no tax services rendered by PricewaterhouseCoopers LLP for the years ended December 31, 2003 and 2002. Tax services principally include tax compliance, tax advice and planning (including foreign tax services, as well as tax planning strategies for the preservation of net operating loss carryforwards).
Audit Related Fees
None.
All Other Fees
None.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
The following documents are filed as part of this report:
(a) Financial Statements.
See the Index to Financial Statements in Item 8 hereof.
(b) Reports on Form 8-K.
The Registrant filed a Form 8-K with the Commission on January 20, 2004 indicating that the Trust changed its Certifying Accountants by dismissing PricewaterhouseCoopers LLP and engaging Perselson Weiner LLP.
(c) Exhibits.
2A. Acquisition Agreement, by and between GSF Energy, L.L.C. and Olinda, L.L.C., dated as of May 31, 1997. Incorporated by reference to Exhibit 2A in Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
2B. Letter, dated as of May 31, 1997, supplementing Acquisition Agreement. Incorporated by reference to Exhibit 2B in Registrant's Current Report on Form 8-K dated June 1, 1997.
3A. Certificate of Trust of the Registrant is incorporated by reference to Exhibit 3A of Registrant's Registration Statement which was filed with the Commission on May 26, 1994.
3B. Declaration of Trust of Registrant is incorporated by reference to Exhibit 3B of Registrant's Registration Statement which was filed with the Commission on May 26, 1994.
3C. Agreement of Limited Partnership of Ridgewood Energy Electric Power, L.P. dated as of March 6, 1991 is incorporated by reference to Exhibit 3C of Registrant's Registration Statement which was filed with the Commission on May 26, 1994.
10A. Management Agreement between the Registrant and Ridgewood Power Corporation is incorporated by reference to Exhibit 10A of Registrant's Registration Statement which was filed with the Commission on May 26, 1994.
10B. Stillwater Hydro Partners L.P. Amended and Restated Agreement of Limited Partnership dated as of July 29, 1991 and letter of amendment thereof dated as of May 16, 1994 is incorporated by reference to Exhibit 10B of Registrant's Registration Statement which was filed with the Commission on May 26, 1994.
10C. Power Purchase Agreement dated as of September 19, 1989 between Stillwater Hydro Partners L.P. and Niagara Mohawk Power Corporation and amendment thereof dated as of August 28, 1990 is incorporated by reference to Exhibit 10C of Registrant's Registration Statement which was filed with the Commission on May 26, 1994.
10D. RW Power Partners L.P. Agreement and Restated Agreement of Limited Partnership dated as of October 1, 1992 among Ridgewood Energy Electric Power, L.P., Ridgewood Power Corporation and WE GEN, Inc. is incorporated by reference to Exhibit 10D of Registrant's Registration Statement which was filed with the Commission on May 26, 1994.
10E. The Registrant has terminated the agreement designated 10E in its prior Annual Reports on Form 10-K.
10F. The Registrant has terminated the agreement designated 10F in its prior Annual Reports on Form 10-K.
10G. Agreement of Limited Partnership of Brea Power Partners, L.P. dated as of October 12, 1994 by and between Brea Power (I), Inc., GSF Energy Inc. and Ridgewood Electric Power Trust I is incorporated by reference to Registrant's Form 8-K filed with the Commission on October 27, 1994.
10H. Agreement, dated as of January 16, 1997, by and between RW Power Partners, L.P. and Virginia Electric Power Company Incorporated by reference to Exhibit 10H in the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997.
10I. Amendment to Transaction Documents, dated as of May 31, 1997, by and among GSF Energy, L.L.C., Brea Power Partners, L.P. and Ridgewood Electric Power Trust I. Incorporated by reference to Exhibit 10I in Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
10J. Parallel Generation Agreement, by and between Southern California Edison Company and GSF Energy, Inc. (Brea Power Partners, L.P., assignee), as amended. Incorporated by reference to Exhibit 10J in Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
10K. Partial Assignment and Assumption Agreement, dated as of November 29, 1994, by and between GSF Energy, Inc. and Brea Power Partners, L.P. Incorporated by reference to Exhibit 10K in Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
10L. Amended and Restated Gas Lease Agreement, dated as of December 14, 1993, by and between the County of Orange, California and GSF Energy, Inc., as modified. Incorporated by reference to Exhibit 10L in Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
10M. Gas Sale and Purchase Agreement, dated November 29, 1994 by and between GSF Energy, Inc. and Brea Power Partners, L.P. Incorporated by reference to Exhibit 10M in Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
10N. Support Agreement, dated as of November 29, 1994, by and among Brea Power Partners, L.P., the Trust and GSF Energy, Inc. Incorporated by reference to Exhibit 10N in Registrant's Amendment No. 1 to Current Report on Form 8-K dated June 1, 1997.
10O. Amended and Restated Gas Sale and Purchase Agreement, dated June 11, 2001, by and between GSF Energy, LLC and Ridgewood Power Management, LLC, on behalf of Brea Power Partners, L.P. and Ridgewood Olinda, LLC.
10P. Code of Ethics, adopted March 1, 2004.
23.1 Consents of independent accountants.
99.1. Certifications under Section 906 of the Sarbanes-Oxley Act.
Exhibits and schedules to these exhibits are omitted, and lists of the omitted documents are found in their tables of contents. The Registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to these exhibits to the Commission upon request.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
RIDGEWOOD ELECTRIC POWER TRUST I (Registrant)
By:/s/ Robert E. Swanson Chief Executive Officer April 14, 2004
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 Chief Executive Officer April 14, 2004 Robert E. Swanson
By:/s/ Christopher Naunton Vice President and April 14, 2004 Christopher Naunton Chief Financial Officer
RIDGEWOOD RENEWABLE POWER LLC Managing Shareholder April 14, 2004 By:/s/ Robert E. Swanson Chief Executive Officer Robert E. Swanson
CERTIFICATION PURSUANT TO RULE 13A-14 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Robert E. Swanson, Chief Executive Officer of Ridgewood Electric Power Trust I ("registrant"), certify that:
1. I have reviewed this annual report on Form 10-K of the registrant;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the Annual Report is being prepared;
(b) Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in the Annual Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by the Annual Report based on such evaluation; and
(c) Disclosed in the Annual Report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and senior management:
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
Date: April 14, 2004 /s/ Robert E. Swanson Robert E. Swanson Chief Executive Officer
CERTIFICATION PURSUANT TO RULE 13A-14 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Christopher I. Naunton, Chief Financial Officer of Ridgewood Electric Power Trust I ("registrant"), certify that:
1. I have reviewed this annual report on Form 10-K of the registrant;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the Annual Report is being prepared;
(b) Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in the Annual Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by the Annual Report based on such evaluation; and
(c) Disclosed in the Annual Report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and senior management:
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
Date: April 14, 2004 /s/ Christopher I. Naunton Christopher I. Naunton Chief Financial Officer