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 II (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 November 20, 1992 to participate in the development, construction and operation of independent power generating facilities ("Independent Power Projects" or "Projects"). Christiana Bank & Trust Company, a ("Christiana"), a Delaware trust company, is the Corporate Trustee of the Trust.
The Trust sold shares of beneficial interest in the Trust ("Investor Shares") in a private placement offering (the "Offering") which ended on January 31, 1994, at which time it had raised approximately $23.5 million. Net of offering fees, commissions and expenses, the Offering provided approximately $19.4 million of net funds available for investments in the development and acquisition of Projects. The Trust has 525 record holders of Investor Shares (the "Investors"). As described below in Item 1(c)(2), the Trust (and its subsidiaries) own interests in four Projects.
The Trust made an election to be treated as a "business development company" under the Investment Company Act of 1940, as amended (the "1940 Act"). On February 27, 1993, the Trust notified the Securities and Exchange Commission of such election and registered the Investor Shares under the Securities Exchange Act of 1934, as amended (the "1934 Act"). On April 29, 1993, the election and registration became effective. 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") as a result of such withdrawal, including, but not limited to, deletion of the provision of the Declaration requiring Independent Trustees. Consents were tabulated at the close of business on January 7, 2002. A total of 235.3775 Investor Shares were outstanding and entitled to be voted. Based on such tabulation, a two-third majority, as required by the Declaration of Trust, 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. In general, the Managing Shareholder has the powers of a general partner of a limited partnership. It has complete control of the day-to-day operation of the Trust. The Managing Shareholder is not regularly elected by the owners of the Investor Shares (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 organized by the Managing Shareholder (the "Other Power Trusts"):
o Ridgewood Electric Power Trust I ("Power I"); o Ridgewood Electric Power TrustIII ("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 Ridgewood Power B Fund/Providence Expansion (the "B Fund").
In addition, the Trust is affiliated with certain Delaware limited liability companies formed by the Managing Shareholder ("Ridgewood LLCs") and for which the Managing Shareholder acts as Manager. These LLCs are:
o Ridgewood Renewable PowerBank LLC; o Ridgewood Renewable Powerbank II, LLC; and o Ridgewood Renewable PowerBank III, LLC.
(b) Financial Information about Industry Segments.
The Trust operates in only one industry segment: investing in independent power generation and similar energy projects.
(c) Narrative Description of Business.
(1) General Description.
The Trust was formed to participate in the development, construction and operation of Projects that generate electricity or related forms of energy for sale to manufacturers, utilities and other users. The Trust also may invest in facilities related to those Projects.
(2) Projects.
(i) Berkshire Project and B-3 Project.
On January 4, 1994, the Trust made an approximately $2.3 million equity investment in Pittsfield Investors Limited Partnership ("PILP"), which was formed to acquire the Berkshire Project, including the assets and business of the Pittsfield Resource Recovery Facility. The Berkshire Project is a waste to energy plant located in Pittsfield, Massachusetts. The Berkshire Project, which has been operating since 1981, burns municipal solid waste supplied by the City of Pittsfield ("Pittsfield"), surrounding communities and other providers. The Trust's partners in the Berkshire Project were subsidiaries of Energy Answers Corporation ("EAC"). EAC made an equity investment of approximately $1.3 million in the Berkshire Partnership and also serves as manager and operator of the facility. In addition, on August 31, 1994, the Trust entered into the B-3 Limited Partnership, with affiliates of EAC, the same firm with which the Trust participated in the Berkshire Project. The Trust made an investment of approximately $4 million into the B-3 Limited Partnership to construct a municipal waste transfer station located in Columbia County, New York ("B-3 Project"). The B-3 Project is a waste transfer station where municipal waste collected from nearby towns by smaller, short haul trucks can be transferred to larger, long haul trucks for more efficient transportation of the waste to distant landfills.
The Trust was entitled to an annual preferred distribution of available cash flow, representing revenue from the Berkshire Project, (after funding debt service, debt service reserves and operating and maintenance expenses) in an amount equal to 15% of its investment. With respect to the B-3 Project, the Trust was entitled to receive a cumulative priority return on the Trust investment of 18% per annum, with any shortfalls being carried forward into subsequent years.
Distributions from the Berkshire Project ceased in the third quarter of 1998 and did not resume. In the third quarter of 1998, EAC informed the Trust that significant and undisclosed cost overruns in the construction of an ash handling system for the Berkshire Project had depleted the Project's funds. EAC further advised the Trust that distributions from Berkshire to the Trust were unlikely to resume. As a result of the expiration of certain key agreements at the end of 2004, the Berkshire Project's ability to continue operations thereafter was uncertain. As with the Berkshire Project, distributions from the B-3 Project were impaired by repeated extensions of the closing deadlines for some local landfills and capacity expansions at other local landfills. If waste can be cheaply deposited at local landfills, there is less demand for consolidating the waste for transfer to distant sites.
As a result of the financial difficulties experienced by both the Berkshire and B-3 Projects and the lack of distributions from either project, the Trust began negotiations with EAC in 2002 to either renegotiate certain aspects of the contractual documents that the Trust believed hindered operation and failed to properly motivate EAC or, in the alternative, sell its interest in the Berkshire Project and B-3 Project to EAC. Ultimately, the parties agreed to a sale.
On September 20, 2002 the Trust, sold 100% of its ownership interest in the B-3 Project and the Berkshire Project to EAC. The acquisition agreement provided for the sale of 100% of the Trust's ownership in the two projects in return for $1,200,000 cash and $5,000,000 of interest bearing promissory notes. The notes bear interest at a rate of 10% per annum, and will be repaid over a 17-year term. The notes are collateralized by all the assets of the partnerships. To date, EAC has made all required payments under the notes.
(ii) Monterey Project.
On January 9, 1995, the Trust purchased 100% of the equity interests in Sunnyside Cogeneration Partners, L.P., which owns a 5.5-megawatt cogeneration project located in Salinas, Monterey County, California (the "Monterey Project"). The aggregate purchase price was approximately $5.2 million including transaction costs. The Monterey Project has been operating since 1991 and uses natural gas fired reciprocating engines to generate electricity for sale to Pacific Gas and Electric Company ("PG&E") under a long term contract expiring in 2020 (the "Power Contract"). Thermal energy from the Monterey Project is used to provide warm water to an adjacent greenhouse under a long- term contract that also terminates in 2020. The Monterey Project is operated on behalf of the Trust by Ridgewood Power Management LLC ("RPM").
The Monterey Project is a "Qualifying Facility" or "QF" under the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). The independent power industry in the United States was created in large part by PURPA and other federal legislation passed in response to the energy crises of the 1970s. PURPA, among other things, requires utilities to purchase electric power from QFs, and also exempts these QFs from most federal and state utility regulatory requirements. In addition, the price paid by electric utilities under PURPA 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 QFs at rates set by contract formula approved by state regulatory commissions. The Monterey Project sells its output to PG&E under a Power Contract with a capacity and energy payment determined pursuant to a contract formula approved by the California Public Utilities Commission ("CPUC"). According to the Power Contract, the energy payment is based upon a benchmark energy price adjusted for changes over time in a gas index; the so- called "Short Run Avoided Cost Methodology" or SRAC. However, as described further below, the Monterey Project executed an Amendment to the Power Contract with PG&E, which provides that the Monterey Project will receive a fixed energy payment (as well as the required capacity payment) for a term of five (5) years, until approximately August 2006.
During calendar years 2000 and 2001, California experienced severe electric energy crises brought on my many factors including, but not limited to, implementation of flawed electric deregulation legislation. As a result of the energy crises, PG&E, among other things, experienced severe cash shortages and losses due primarily to the fact that it was required under the law to purchase electric energy at wholesale prices significantly above the regulated rates it could legally charge retail customers. As a result, PG&E filed for protection under the U.S. Bankruptcy Code in April of 2001. At the time of PG&E's bankruptcy filing, the Monterey Project had not been paid by PG&E for the electric energy and capacity it had delivered in the last several months of 2000 and the first few months of 2001. In addition, given PG&E's bankruptcy, the prospects for payment in the near future were extremely remote. However, the Monterey Project needed to have a reserve of cash to maintain operations and pay certain fixed costs that would be incurred regardless of whether it operated and sold to PG&E. Therefore, as further detailed in the Trust's Annual Report on Form 10K for the Year 2001, the Trust sold its PG&E receivables at a discount.
Subsequent to its bankruptcy filing, PG&E found itself under intense pressure to pay the QFs offline some amount of the outstanding balance owed and to renegotiate Power Contracts in order to get their electric generation back online and supply the electric starved State of California. Therefore, in an effort to get as many QFs back online as possible, PG&E sought and received approval from the California Public Utilities Commission ("CPUC") to offer each QF an agreement, and corresponding amendment to their Power Contracts, for a term of five (5) years, which would effectively replace, for such 5 year term, the variable SRAC formula for determining the energy price with a fixed energy price. Such amendment would allow the QF to operate at a price that was reasonable in light of the circumstances at that time. In addition, a QF that executed the amendment agreed that it would not institute, or proceed with outstanding, litigation against PG&E. The Monterey Project executed such amendment. However, in order to execute the amendment with a fixed energy price, it was necessary to procure natural gas at a fixed price. As a result of the sale of the PG&E receivables, the Monterey Project had sufficient cash available and was able to procure such supply of natural gas from Coral Energy Services, Inc., ("Coral") a subsidiary of Shell Oil. Therefore, until approximately August 2006, the Monterey Project will be operating under the Amendment, which is expected to result in positive cash flow to the Monterey Project. Thereafter, the Power Contract with the SRAC formula becomes the energy price and there is no guarantee that SRAC at that time will provide sufficient cash for the Monterey Project to operate profitably. However, under the Power Contract, the Monterey Project is also paid a capacity payment. Such payment, along with an SRAC based energy payment, even if somewhat low, should be enough for the Monterey Project to operate and have a positive cash flow. In addition to the gas supply agreement mentioned, Coral and the Byron and San Joaquin Projects have a master re-sale agreement, which also expires in August 2006. Such agreement enables the NorCal Projects not to take delivery and sell back certain of the natural gas to Coral once predetermined prices have been established. Certain re-sale pricing for 2004 has already been determined, which is in excess of the underlying cost.
(iii) California Pumping Project
In 1995, the Trust purchased a package of irrigation service engines (the "Pumping Project") located in Ventura County, California and also in 1995 the Trust bought additional engines from unaffiliated sellers. The Trust's total investment in the Pumping Project was approximately $952,000. RPM operates and manages the Pumping Project.
The Pumping Project has been operating since 1992 and uses 26 natural-gas-fired reciprocating engines with a rated equivalent capacity of 3 Megawatts to provide power for irrigation wells that furnish water for orchards of lemon and other citrus trees. The power is purchased by local farmers and farmers' co-operatives pursuant to electric services contracts. Presently, the Pumping Project's rates are approximately 85% of Southern California Edison Company's agricultural rate of 12.2 cents/kwh. The discount was provided because of the low natural gas prices experienced during most of 2002. However, natural gas prices have risen and the Pumping Project is considering lowering the discount to 90% of SCE's rate or even less, if natural gas prices continue to rise.
Power IV owns a package of similar engines located on different sites and operated under identical terms. The engines operate independently of each other and revenues and expenses for each Trust are segregated from those of the other.
(iv) San Diego Project.
The Trust acquired its interest in the San Diego Project on March 21, 1994, when it made an investment of approximately $2.3 million to acquire an 80% interest in the Project. The Trust made additional capital contributions, totaling approximately $1.2 million, to the Project to fund working capital and to purchase various leased equipment. On June 25, 1997 the Trust sold its entire interest in the San Diego Project to subsidiaries of NRG Energy, Inc. of Minneapolis, Minnesota ("NRG"). The sale price was $6,200,000 in both cash and notes. As of June 25, 2003, NRG has paid in full.
(3) Project Management and Operations.
The Managing Shareholder has organized RPM to provide operating management for the Projects, and has assigned day-to-day management of the Monterey Project and California Pumping 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 Party Transactions for further information regarding the Operation Agreement and RPM and for the cost reimbursements received by RPM.
The Monterey Project's revenue from its Power Contract consists of two components, energy payments and capacity payments. Energy payments are based on a facility's net electric output, with payment rates (other than during the 5 year amendment) usually indexed to the fuel costs of the purchasing utility or to general inflation indices. Capacity payments are based on either a facility's net electric output or its available capacity. Capacity payment rates vary over the term of a Power Contract according to various schedules.
The Pumping Project sells its power to the farmers on whose land its engines are situated under contracts terminable at any time on 60 days' prior notice to the Trust. Although the Trust is at risk if many customers concurrently terminate contracts, as might happen if an electric utility or other supplier were to offer substantially discounted rates, the Trust believes that it is currently a competitive supplier and that alternate customers can be secured in the event contracts are terminated.
The major costs of a Project while in operation will be debt service (if applicable), fuel, taxes, maintenance and operating labor. The ability to reduce operating interruptions and to have a Project's capacity available at times of peak demand are critical to the profitability of a Project. Accordingly, skilled management is a major factor in the Trust's business.
Electricity produced by a Project is delivered to the purchaser through transmission lines that are built to interconnect with the utility's existing power grid. Steam produced by a Project is conveyed directly to the user by pipeline and the energy produced by the engines in the Pumping Project is applied directly to pumps.
Generally, revenues from the sales of electric energy from a cogeneration facility will represent the most significant portion of the facility's total revenue. However, to maintain its status as a QF under PURPA, it is imperative that the Monterey Project continues to satisfy PURPA cogeneration requirements as to the amount of thermal products generated. See Item 1(c)(6) - Regulatory Matters, for an explanation of these requirements. Therefore, since the Monterey Project has only two customers (the electric energy purchaser and the thermal products purchaser), loss of either of these customers would have a material adverse effect on the Monterey Project.
Customers that accounted for more than 10% of consolidated revenue to the Trust in each of last three fiscal years are:
Calendar year 2003 2002 2001
Pacific Gas & Electric Co. 77.7% 69.0% 63.1%
(4) Market Trends
As a result of the energy crises experienced by California during the years 2000 and 2001, both the state legislature and the California Public Utilities Commission ("CPUC") have taken significant action by enacting legislation and implementing regulations, respectively, intended primarily to avoid a repeat of the energy crises by creating a more stable, efficient and economic energy market. For example, various legislation have been introduced in the California legislature that, if passed, would "re-regulate" the electric industry in that state and require that the California investor-owned utilities be the only seller of electric energy. However, there is significant opposition to such efforts and a variety of other legislative effort that could enhance competition are being introduced and considered. For example, the legislature enacted legislation designed to enhance, promote and encourage renewable generation in the state by implementing a renewable portfolio standard ("RPS"), which will require all California investor owned utilities ("IOUs"), as well as retail electric suppliers to have in their energy supply portfolio a certain percentage of renewable generation. This percentage increases over time until the requirement equals 20%. However, RPM, on behalf of some of the renewable projects owned by some of the Trust's affiliates, has been participating in the California RPS proceedings and believe that due its certain aspects of the legislation obtained by the IOUs and the power they exert over the CPUC, the RPS may not result in any significant increase in renewable generation. As a result of the RPS, which is not likely to result in increased generation, environmental requirements that may cause some generation to come off-line, as well as the poor economics of many large power developers which has caused them to cancel development, there is a possibility that once the economy of the U.S and California improve, electric generation will be in short supply. This could drive prices significantly higher.
In any event, these market changes do not significantly impact upon the Monterey Project, which currently has a Power Contract with PG&E, although market changes which strengthen PG&E benefit the Monterey Project over the long term by ensuring PG&E's ability to pay under such Power Contract.
(5) Competition
After the Power Contract expires in 2020 or terminates for other reasons, the Monterey Project under currently anticipated conditions would be free to sell its output on the competitive electric supply market, either in spot, auction or short-term arrangements or under long-term contracts if those Power Contracts could be obtained. There is no assurance that the Project could sell its output or do so profitably. Because the Project is fueled by natural gas normally purchased at market prices and because the Project is relatively small-scale, it might have cost disadvantages in competing against larger competitors that would enjoy economies of scale. The Trust is unable to anticipate whether thermal sales from cogeneration would offset any possible cost disadvantages in electric generation or whether in fact the Project would have cost disadvantages after the Power Contract ends in 2020. It is thus impossible to predict the profitability of the Project after the scheduled termination of the Power Contract.
There are a large number of participants in the independent power industry. Several large corporations specialize in developing, building and operating Independent Power Projects. Equipment manufacturers, including many of the largest corporations in the world, provide equipment and planning services and provide capital through finance affiliates. In addition, there are many smaller firms whose businesses are conducted primarily on a regional or local basis. Many of these companies focus on limited segments of the cogeneration and independent power industry and do not provide a wide range of products and services. There is significant competition among non-utility producers, subsidiaries of utilities and utilities themselves in developing and operating energy-producing projects and in marketing the power produced by such projects.
The Trust is unable to accurately estimate the number of competitors but believes that there are many competitors at all levels and in all sectors of the industry. Many of those competitors, especially affiliates of utilities and equipment manufacturers, may be far better capitalized than the Trust.
(6) Regulatory Matters.
Projects are subject to energy and environmental laws and regulations at the federal, state and local levels in connection with development, ownership, operation, geographical location, zoning and land use of a Project and emissions and other substances produced by a Project. These energy and environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operates in compliance with such permits and approvals.
(i) Energy Regulation.
(i) Energy Regulation.
(A) PURPA. The enactment in 1978 of PURPA and the adoption of regulations thereunder by FERC provided incentives for the development of cogeneration facilities and small power production facilities meeting certain criteria. QFs under PURPA are generally exempt from the provisions of the Public Utility Holding Company Act of 1935, as amended (the "Holding Company Act"), the Federal Power Act, as amended (the "FPA"), and, except under certain limited circumstances, 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 QFs 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 1992 Energy Act may 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) Fuel Use Act. Projects may also be subject to the Fuel Use Act, which limits the ability of power producers to burn natural gas in new generation facilities unless such facilities are also coal-capable within the meaning of the Fuel Use Act. The Trust believes that the Monterey Project is coal-capable and thus qualifies for exemption from the Fuel Use Act.
(E) State Regulation. State public utility regulatory commissions have broad jurisdiction over Independent Power Projects which are not QFs under PURPA, and which are considered public utilities in many states. In states where the wholesale or retail electricity market remains regulated, Projects that are not QFs may be subject to state requirements to obtain certificates of public convenience and necessity to construct a facility and could have their organizational, accounting, financial and other corporate matters regulated on an ongoing basis. Although FERC generally has exclusive jurisdiction over the rates charged by a non-QF to its wholesale customers, state public utility regulatory commissions have the practical ability to influence the establishment of such rates by asserting jurisdiction over the purchasing utility's ability to pass through the resulting cost of purchased power to its retail customers. In addition, states may assert jurisdiction over the siting and construction of non-QFs and, among other things, issuance of securities, related party transactions and sale and transfer of assets. The actual scope of jurisdiction over non-QFs by state public utility regulatory commissions varies from state to state.
(ii) Environmental Regulation.
The construction and operation of Independent Power Projects are subject to extensive federal, state and local laws and regulations adopted for the protection of human health and the environment and to regulate land use. The laws and regulations applicable to the Trust and Projects in which it invests primarily involve the discharge of emissions into the water and air and the disposal of waste, but can also include wetlands preservation and noise regulation. These laws and regulations in many cases require a lengthy and complex process of renewing licenses, permits and approvals from federal, state and local agencies. Obtaining necessary approvals regarding the discharge of emissions into the air is critical to the development of a Project and can be time-consuming and difficult. Each Project requires technology and facilities that comply with federal, state and local requirements, which sometimes result in extensive negotiations with regulatory agencies. Meeting the requirements of each jurisdiction with authority over a Project may require modifications to existing Projects.
The Trust's Projects must comply with many federal and state laws and regulations governing wastewater and storm water discharges from the Projects. These are generally enforced by states under permits for point sources of discharges and by storm water permits. Under the Clean Water Act, such permits must be renewed every five years and permit limits can be reduced at that time or under re-opener clauses at any time. The Projects have not had material difficulty in complying with their permits or obtaining renewals. The Projects use closed-loop engine cooling systems, which do not require large discharges of coolant except for periodic flushing to local sewer systems under permit and do not make other material discharges to groundwater or streams.
The Trust's Monterey Project is subject to the reporting requirements of the Emergency Planning and Community Right-to-Know Act that require the Projects to prepare toxic release inventory release forms. These forms list all toxic substances on site that are used in excess of threshold levels so as to allow governmental agencies and the public to learn about the presence of those substances and to assess potential hazards and hazard responses. The Trust does not anticipate that this will result in any material adverse effect on it.
The Managing Shareholder expects that environmental and land use regulations may become more stringent. The Trust and the Managing Shareholder have developed a certain expertise and experience in obtaining necessary licenses, permits and approvals, but will nonetheless rely upon qualified environmental consultants and environmental counsel retained by it to assist in evaluating the status of Projects regarding such matters.
(iii) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are subject to amendment or repeal. Future legislation and regulation is uncertain, and could have material effects on the Trust.
(d) Financial Information about Foreign and Domestic Operations and Export Sales.
The Trust has invested in Projects located in California, Massachusetts and New York and has no foreign operations.
(e) Employees.
The operating personnel of the Monterey and Pumping Projects are employed by RPM and accordingly the Trust has no employees. The persons described below at Item 10 - Directors and Executive Officers of the Registrant serve as executive officers of the Trust and have the duties and powers usually applicable to similar officers of a Delaware corporation in carrying out the Trust business.
Item 2.
Item 2. Properties.
Pursuant to the Management Agreement between the Trust and the Managing Shareholder (described at Item 10(c) - Directors and Executive Officers of the Registrant - Management Agreement), the Managing Shareholder provides the Trust with office space at the Managing Shareholder's principal office at The Ridgewood Commons, 947 Linwood Avenue, Ridgewood, New Jersey 07450.
The following table shows the material properties (relating to Projects) owned or leased by the Trust's subsidiaries or partnerships in which the Trust has an equity interest. All of the Projects are described in further detail at Item 1(c)(2).
Square Ownership Ground Approximate Footage of Description Interests Lease Acreage Project(Actual of Project Location in Land Expiration of Land or Projected) Project
Monterey Monterey, Gas-fired cogen CA Leased 2020 2 10,000 eration facility
Pumping Ventura Cy, Leased N/A N/A N/A Natural gas Project CA or engines powering licensed irrigation pumps
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 sold 235.3775 Investor Shares of beneficial interest in the Trust in its private placement offering of Investor Shares, which closed on January 31, 1994. There is currently no established public trading market for the Investor Shares. As of the date of this Form 10-K, all such Investor Shares have been issued and are outstanding. There are no outstanding options or warrants to purchase, or securities convertible into, Investor Shares.
Investor Shares are restricted as to transferability under the Declaration, and are restricted under federal and state laws regulating securities when the Investor Shares are held by persons in a control relationship with the Trust. Investors wishing to transfer Investor Shares should also consider the applicability of state securities laws. The Investor Shares have not been and are not expected to be registered under the Securities Act of 1933, as amended (the "1933 Act"), or under any other similar law of any state in reliance upon what the Trust believes to be exemptions from the registration requirements contained therein. Because the Investor Shares have not been registered, they are "restricted securities" as defined in Rule 144 under the 1933 Act.
(b) Holders
As of the date of this Form 10-K, there are 525 record holders 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 $1,412,268 $823,824 Distributions per Investor Share $6,000 $ 3,500 Distributions to Managing Shareholder $14,265 $ 8,321
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 restricted cash. 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 that accounting income to Investors.
Item 6.
Item 6. Selected Financial Data.
The following data is qualified in its entirety by the financial statements presented elsewhere in this Annual Report on Form 10-K. 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 $2,706,744 $3,075,114 $2,374,396 3,530,580 2,507,166 Net income (loss) 272,710 255,529 (1,088,887) 218,437 (203,368) Net assets (shareholders' equity) 6,073,292 7,227,155 7,803,731 8,892,618 9,388,247 Investments in Plant and Equipment (net of depreciation) 1,570,880 1,798,352 2,003,302 2,221,614 2,446,494 Investment in Power Contract(net of amortization) 1,940,480 2,061,760 2,183,040 2,304,320 2,425,600 Total assets 6,307,760 7,561,005 8,216,155 9,595,529 10,311,744 Long-term Obligations -- -- -- -- -- Per Share: Revenues 11,500 13,065 10,087 15,000 10,652 Net income(loss) 1,159 1,086 (4,626) 928 (864) Net asset value 25,802 30,704 33,154 38,163 39,886 Distributions to Investors 6,000 3,500 -- 3,003 1,200
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
The following discussion and analysis should be read in conjunction with the Trust's financial statements and the notes thereto presented below. Dollar amounts in this discussion are generally rounded to the nearest $1,000.
Outlook
The Monterey Project is a QF as defined by PURPA and currently sells its electric output to PG&E under a Power Contract expiring in 2020. During the term of the Power Contract, the utility may or may not attempt to buy out the Power Contract prior to expiration. At the end of the Power Contract, the Monterey Project will become a merchant plant and may be able to sell the electric output at then current market prices. There can be no assurance that future market prices will be sufficient to allow the Monterey Project to operate profitably. See Item 1(c)(3) - Plant Operations for information concerning a potential challenge to the Project's Power Contract.
The Berkshire Project receives revenue in the form of tipping fees for waste delivered to the facility and from steam sold under a long-term contract, which expires in 2004. Tipping fees are based on spot market prices, which may fluctuate from time to time. The Project's steam customer may or may not extend its purchases beyond the year 2004.
The Columbia Project receives revenue in the form of tipping fees for waste delivered to the facility by local waste haulers and transferred to long haul trucks for delivery to distant landfills. The Project's profit margins are affected by the level of competition from national waste management companies operating in the same region and the availability of other sources of waste disposal.
The Pumping Project owns irrigation well pumps in Ventura County, California, which supply water to farmers. The demand for water pumped by the project varies inversely with rainfall in the area.
Additional trends affecting the independent power industry generally are described at Item 1(c)(4) - Market Trends.
Significant Accounting Policies
The Trust's plant and equipment is recorded at cost and is depreciated over its estimated useful life. The estimated useful lives of the Trust's plant and equipment range from 3 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 $368,000, or 12%, to $2,707,000 in 2003 compared to $3,075,000 in 2002. The decrease is primarily due to the higher precipitation experienced in Southern California, thus reducing the California Pumping project's operations, in addition to the reduced rates charged to its customers as a result in the change in current market conditions in California.
Gross profit, which represents total revenues reduced by cost of sales, decreased by $115,000 to a gross profit of $29,000 in 2003. The decrease is primarily the result of the lower revenues and corresponding decrease in cost of sales from the California Pumping projects.
General and administrative expenses decreased $116,000, or 45%, to $142,000 in 2003 from $258,000 in 2002. The decrease is partially attributed to the professional fees incurred in the sale of B-3 and PILP projects in 2002.
In 2002, the Trust recovered $157,000 relating to PG&E revenues from prior years, which had been treated as uncollectible due to PG&E's filing for bankruptcy protection.
The management fee paid to the Managing Shareholder decreased by $9,000, or 8%, to $108,000 in 2003 from $117,000 reflecting the lower net assets of the Trust.
Loss from operations increased $147,000, to $221,000 in 2003 from $74,000 in 2002, primarily due to the decrease in gross profit from the California Pumping projects.
Other income, net, increased by $165,000, to $494,000 in 2003 from $329,000 in 2002. The increase is primarily due to the Trust recording an unrealized gain of $488,000, in the current year, for the increase in the market price of natural gas , partially offset by the $190,000 of cash received in 2002 from the 1999 settlement of the Waukesha-Pierce litigation, as well as the $104,000 of equity income received from the B-3 project, which was sold in 2002.
Net income increased $17,000,to $273,000 in 2003 from $256,000 in 2002. The increase in income is a result of the unrealized gain on gas purchase contracts partially offset by decrease in gross profit from the California Pumping projects in addition to the $190,000 of other income received in 2002 from the Waukesha-Pierce litigation and the $104,000 of equity income received from the B-3 project.
The year ended December 31, 2002 compared to the year ended December 31, 2001.
Power generation revenue increased $704,000, or 30%, to $3,075,000 in 2002 compared to $2,3748,000 in 2001. The increase is primarily due to the Monterey project operating on its normal schedule in 2002 as compared to 2001 when the plant was idle from February to August due to PG&E's failure to pay the project for power delivered since December 1, 2000, as a result of the California energy crisis.
Gross profit, which represents total revenues reduced by cost of sales, increased by $96,000 to a gross profit of $144,000 in 2002 from a gross loss of $460,000 in 2001. The increase is a result of an increase in energy generation.
General and administrative expenses decreased $81,000, or 24%, to $258,000 in 2002 from $339,000 in 2001. The decrease primarily reflects the legal costs associated with the Monterey Project's dispute with PG&E that ended in 2001 with a favorable result for the project.
The $127,000 of bad debt expense in 2001 is associated with the sale of the Monterey Project's PG&E receivables to AMROC. In 2002, the Trust recovered $157,000 relating to prior year PG&E revenues.
The management fee paid to the Managing Shareholder decreased by $60,000, or 34%, to $117,000 in 2002 from $177,000 reflecting the lower net assets of the Trust.
Loss from operations decreased $1,030,000, or 93%, to $74,000 in 2002 from $1,104,000 in 2001 as a result of the increase in revenues and the decrease in operating expenses.
Other income, net, increased by $314,000, to $329,000 in 2002 from $15,000 in 2001. The increase is primarily due to the $190,000 of cash received in 2002 from the 1999 settlement of the Waukesha-Pierce litigation, as well as the costs incurred in 2001 in issuing the "Notice of Solicitation of Consents" to investors.
Net income increased $1,296,000,to $207,000 in 2002 from a net loss of $1,089,000 in 2001. The increase in income is a result of the increase in revenues and the decrease in operating expenses.
Liquidity and Capital Resources
In 2003 and 2002, the Trust's operating activities provided $618,000 and $81,000 of cash, respectively.
Cash generated from investing activities in 2003 was $678,000 compared $1,925,000 in 2002. The decrease is primarily due to the $1,224,000 received from the transfer of the B-3 and PILP projects in 2002.
Cash used by financing activities of $1,427,000 and $832,000 in 2003 and 2002, respectively, represents distributions to shareholders.
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.
In August 2003, the Trust issued through its bank a standby letter of credit, in the amount of $504,000 to secure the gas purchases for the Monterey project. The Trust used Managing Shareholder's credit facility to collateralize the letters of credit.
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 Monterey Project has certain long-term obligations relating to its Gas Agreement with Coral (See Note 5 of the Consolidated Financial Statements) and its Power Contract with PG&E. These long-term 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 $1,218,000 Average interest rate 1.04%
Item 8.
Item 8. Financial Statements and Supplementary Data.
A. Index to Consolidated Financial Statements
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
Ridgewood Electric Power Trust II
Consolidated Financial Statements
December 31, 2003, 2002 and 2001
Report of Independent Accountants
Managing Shareholder and Shareholders' Ridgewood Electric Power Trust II
We have audited the accompanying consolidated balance sheet of Ridgewood Electric Power Trust II 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 II 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 II:
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 II 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 II Consolidated Balance Sheets - --------------------------------------------------------------------------------
December 31, ----------------------------- 2003 2002 ----------- ------------ Assets: Cash and cash equivalents .................... $ 1,218,009 $ 1,348,825 Restricted cash .............................. -- 550,000 Trade receivables ............................ 224,497 255,082 Current portion of note receivable from sale of investment ..................... -- 277,528 Due from affiliates .......................... 16,628 14,512 Current portion of unrealized gain on gas purchase contract ................... 217,583 -- Other current assets ......................... 41,569 47,151 ----------- -----------
Total current assets .................. 1,718,286 2,493,098
Notes receivable from transfer of investment in Limited Partnership interests under contractual agreements .... 807,795 1,207,795
Plant and equipment .......................... 3,441,432 3,441,432 Accumulated depreciation ..................... (1,870,552) (1,643,080) ----------- ----------- 1,570,880 1,798,352 ----------- -----------
Electric power sales contract ................ 3,032,000 3,032,000 Accumulated amortization ..................... (1,091,520) (970,240) ----------- ----------- 1,940,480 2,061,760 ----------- -----------
Unrealized gain on gas purchase contract, net of current portion ................... 270,319 -- ----------- -----------
Total assets ......................... $ 6,307,760 $ 7,561,005 ----------- -----------
Liabilities and Shareholders' Equity: Liabilities: Accounts payable and accrued expenses ........ $ 2,371 $ 156,036 Accrued fuel expense ......................... 81,679 71,833 Accrued professional fees .................... 66,561 58,138 Due to affiliates ............................ 83,857 47,883 ----------- ----------- Total current liabilities ........... 234,468 333,890
Commitments and contingencies ................ -- --
Shareholders' Equity: Shareholders' equity (235.3775 investor shares issued and outstanding) .... 6,213,803 7,356,088 Managing shareholder's accumulated deficit (1 management share issued and outstanding) ................... (140,511) (128,973) ----------- ----------- Total shareholders' equity .......... 6,073,292 7,227,115 ----------- ----------- Total liabilities and shareholders' equity .............. $ 6,307,760 $ 7,561,005 ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II Consolidated Statements of Operations - --------------------------------------------------------------------------------
Year Ended December 31, ------------------------------------------- 2003 2002 2001 ----------- ----------- -------------
Power generation revenue ......... $ 2,706,744 $ 3,075,114 $ 2,374,396
Cost of sales, including depreciation and amortization of $348,752, $348,662 and $346,209 in 2003, 2002,and 2001 2,677,817 2,931,122 2,834,668 ----------- ----------- -----------
Gross profit (loss) .............. 28,927 143,992 (460,272) ----------- ----------- -----------
General and administrative expenses ....... 141,708 257,739 338,815 Provision for bad debt (recoveries) expense .......... -- (156,938) 127,130 Management fee paid to managing shareholder ......... 108,407 117,058 177,337 ----------- ----------- ----------- Total other operating expenses ....... 250,115 217,859 643,282 ----------- ----------- -----------
Loss from operations ............. (221,188) (73,867) (1,103,554) ----------- ----------- -----------
Other income (expense): Interest income ............... 21,692 56,641 99,848 Interest expense .............. -- (3,506) -- Unrealized gain on gas purchase contract 487,902 -- -- Equity income from B-3 Limited Partnership ......... -- 104,497 43,459 Other income ................. -- 190,331 -- Other expense ................ (15,696) (18,567) (128,640) ----------- ----------- ----------- Other income (expense), net . 493,898 329,396 14,667 ----------- ----------- -----------
Net income(loss) ................. $ 272,710 $ 255,529 $(1,088,887) ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II 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 ..... $ 9,004,936 $ (112,318) $ 8,892,618
Net loss for the year ........ (1,077,998) (10,889) (1,088,887) ----------- ----------- -----------
Shareholders' equity (deficit), December 31, 2001 ... 7,926,938 (123,207) 7,803,731
Cash distributions .... (823,824) (8,321) (832,145)
Net income for the year 252,974 2,555 255,529 ----------- ----------- -----------
Shareholders' equity (deficit), December 31, 2002 ... 7,356,088 (128,973) 7,227,115
Cash distributions .... (1,412,268) (14,265) (1,426,533)
Net income for the year 269,983 2,727 272,710 ----------- ----------- ------------
Shareholders' equity (deficit), December 31, 2003 ... $ 6,213,803 $ (140,511) $ 6,073,292 ----------- ----------- ------------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II Consolidated Statements of Cash Flows - --------------------------------------------------------------------------------
Year Ended December 31, ------------------------------------------- 2003 2002 2001 ----------- ----------- ------------- Cash flows from operating activities: Net income (loss) ........... $ 272,710 $ 255,529 $(1,088,887) ----------- ----------- -----------
Adjustments to reconcile net income (loss) to net cash flows from operating activities: Depreciation and amortization ............... 348,752 348,662 346,209 Equity in earnings from unconsolidated B-3 Limited Partnership ....... -- (104,497) (43,459) Unrealized gain on gas purchase contract........... (487,902) -- -- Changes in assets and liabilities: Decrease (increase) in restricted cash ....... 550,000 (347,430) (202,570) Decrease in trade receivables ....... 30,585 12,788 634,802 Decrease (increase) in other current assets ... 5,582 (11,242) (15,477) Increase (decrease) in accounts payable and accrued expenses .... (153,665) 148,702 (14,425) Increase (decrease) in accrued fuel expense . 9,846 (95,566) (134,228) Increase in accrued professional fees ....... 8,423 2,662 -- Increase (decrease) in due to/from affiliates, net .... 33,858 (128,644) (155,860) ----------- ----------- ----------- Total adjustments ....... 345,479 (174,565) 414,992 ----------- ----------- ----------- Net cash provided by (used in) operating activities 618,189 80,964 (673,895) ----------- ----------- -----------
Cash flows from investing activities: Distributions from B-3 Limited Partnership .... -- 200,000 200,000 Cash received from transfer of investments, net ..... -- 1,224,097 -- Proceeds from notes receivable .......... 677,528 522,938 482,861 Capital expenditures ........ -- (22,432) (6,617) ----------- ----------- ----------- Net cash provided by investing activities ... 677,528 1,924,603 676,244 ----------- ----------- ----------- Cash flows from financing activities: Cash distributions to shareholders ......... (1,426,533) (832,145) -- ----------- ----------- ----------- Net cash used in financing activities .. (1,426,533) (832,145) -- ----------- ----------- ----------- Net (decrease) increase in cash and cash equivalents ......... (130,816) 1,173,422 2,349 Cash and cash equivalents, beginning of year ......... 1,348,825 175,403 173,054 ----------- ----------- ----------- Cash and cash equivalents, end of year ................. $ 1,218,009 $ 1,348,825 $ 175,403 ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust II Notes to Consolidated Financial Statements - --------------------------------------------------------------------------------
1. Organization and Purpose
Nature of business Ridgewood Electric Power Trust II (the "Trust") was formed as a Delaware business trust on November 20, 1992. The managing shareholder of the Trust is Ridgewood Renewable Power LLC (formerly Ridgewood Power Corporation). The Trust began offering shares on January 4, 1993 and discontinued its offering of shares on January 31, 1994.
The Trust was organized to invest in independent power generation facilities and in the development of these facilities. These independent power generation facilities include cogeneration facilities which produce electricity and thermal energy and other power plants that use various fuel sources (except nuclear). The power plants sell electricity and, in some cases, thermal energy to utilities and industrial users under long-term contracts.
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.
Business Development Company Effective April 29, 1993, 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 Exchange Act of 1934.
In November 2001, through a proxy solicitation the Trust requested investor consent to end the BDC status. On January 7, 2002, the consents were tabulated and more than two-thirds 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.
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, resulting in the Trust recording an asset at fair value and an unrealized gain of $487,902 on its gas purchase and re-sale agreements.
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 when purchased of three months or less, 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 $1,180,000.
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 3 to 20 years with a weighted average of 15 years at December 31, 2003 and 2002. During 2003, 2002 and 2001, the Trust recorded depreciation expense of $227,472, $227,382 and $224,929, respectively.
Electric Power Sales Contract A portion of the purchase price of the Monterey Project was assigned to the electric power sales contract and is being amortized over the life of the contract (25 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 $121,280 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 $0, $3,506 and $0, respectively.
Significant Customer and Supplier During 2003, 2002 and 2001, the Trust's largest customer, Pacific Gas and Electric Company ("PG&E"), accounted for 78%, 69% and 63%, respectively of total revenues. In early 2001, PG&E experienced severe financial difficulty, see Note 10 for additional discussion. During 2003, 2002 and 2001, the Trust purchased 100% of the Monterey Projects gas supply 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 $10,038,615 and $11,051,680, 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
Sunnyside Cogeneration Partners, L.P. (known as the Monterey project) On January 9, 1995, the Trust acquired 100% of the existing partnership interests of Sunnyside Cogeneration Partners, L.P., which owns and operates a 5.5 megawatt electric cogeneration facility, located in Monterey County, California. The aggregate purchase price was $5,198,058 including transaction costs. Electricity is sold to PG&E under a long term contract expiring in 2020.
The acquisition of the Monterey Project was accounted for as a purchase and the results of operations of the Monterey Project have been included in the Trust's consolidated financial statements since the acquisition date. The purchase price was allocated to the net assets acquired, based on their respective fair values. Of the purchase price, $3,032,000 was allocated to the electric power sales contract and is being amortized over the life of the contract (25 years).
In August 2001, PG&E and the Monterey Project entered into an amendment to the electric power sales contract for a term of five years, which would effectively replace, for such 5 year term, the variable formula for determining the energy price with a fixed energy price. See Note 10 - Pacific Gas and Electric Company Financial Crisis, for developments affecting the Monterey Project.
On December 31, 1998 the Trust, through subsidiaries, filed a legal complaint in the Superior Court of California for Monterey County against Waukesha-Pierce, Inc. and subsidiaries, alleging that the subsidiaries had not disclosed the existence of an obligation of the Monterey project to Pacific Gas and Electric Company and therefore breached a warranty in the acquisition agreement. The claim was for approximately $273,000 plus interest and expenses. Waukesha-Pierce, Inc. was included in the proceeding as a contractual guarantor. On January 17, 1999, a separate action against Waukesha-Pierce, Inc. was filed by the Trust's subsidiaries in the United States District Court for the Northern District of Texas to enforce the guaranty. The parties agreed to dismiss the Texas case without prejudice before material proceedings resulted. The California case was settled in March 2000; Waukesha-Pierce Inc. agreed to pay the Project approximately $190,000 and to cooperate with the Project in the potential FERC proceedings involving the Monterey project discussed above and the Trust agreed to cooperate with Waukesha-Pierce in releasing funds due from PG&E to Waukesha-Pierce. In May 2002, the Project received settlement proceeds of $190,306.
Pump Services Company, LP (a wholly owned subsidiary, known as California Pumping Project) In 1995, the Trust acquired a package of natural gas and diesel engines, which drive deep irrigation well pumps in Ventura County, California. The engines' shaft horsepower-hours are sold to farmers at a discount from the price of equivalent kilowatt hours of electricity. The operator pays for fuel, maintenance, repair and replacement. The project has an equivalent of 2 megawatts of power.
B-3 Limited Partnership (known as the Columbia project) On August 31, 1994, the Trust made a limited partnership investment in this partnership, which was formed to construct and operate a municipal waste transfer station, located in Columbia County, New York. The project commenced operations in January 1995.
In exchange for its investment, the Trust was entitled to receive annually a preferred distribution of available net cash flow from the facility equal to 18% of its investment. In the event that in any given year available net cash flow from the project does not at least equal the amount of the preferred minimum return, the amount of such shortfall was payable on a priority basis out of any available net cash flow in subsequent years. The Trust was also be entitled to receive additional distributions from any net cash flow in excess of the 18% return on its investment. The aggregate purchase price of the Trust's investment in the partnership was $3,975,240. The Trust received distributions of $200,000 from the project for each of the years ended December 31, 2002 and 2001, respectively.
Due to the protective rights of the other partner and in accordance with Emerging Issues Task Force ("EITF") 96-16 "Investor's Accounting for an Investee When the Investor Has a Majority of the Voting Interest but the Minority Shareholder or Shareholders Have Certain Approval or Veto Rights", the Trust's 50.5% ownership in the B-3 Limited Partnership was accounted for under the equity method of accounting. The Trust's equity in the earnings of the B-3 Project has been included in the consolidated financial statements since acquisition in accordance with the terms in the partnership agreement.
The partnership agreement required income (loss) earned by the partnership to be allocated and distributed to the partners as follows: 1. Gross income is allocated as distributions declared have been allocated to the partners. 2. The difference between distributions declared and net income before depreciation is allocated to the partners according to partnership interests. 3. Depreciation expense is allocated to the partners proportionally according to their original capital contributions to the partnership.
On January 4, 1994, the Trust made a limited partnership investment in the Pittsfield Investors Limited Partnership ("PILP"), a facility that burns municipal solid waste located in Pittsfield, Massachusetts. The Trust wrote off its investment in PILP in 1998.
On September 20, 2002, the Trust, sold 100% of its ownership interest in the B-3 Limited Partnership and PILP, to EAC Operations, Inc., the other limited partner of both entities. The acquisition agreement provides for the sale of 100% of the Trust's ownership in the two partnerships in return for $1,200,000 cash and $5,000,000 of interest bearing promissory notes. The notes bear interest at a rate of 10% per annum, and will be repaid monthly over a 17 year term, of which the first two years of payments will consist of interest only. The notes are collateralized by all the assets of the partnerships.
The purchase price for the B-3 Project was $3,400,000, of which $400,000 was paid in cash at the time of closing. The purchase price for PILP was $2,800,000, of which $800,000 was paid in cash at the time of closing.
Recovery of interest and principal under the promissory notes is dependent solely upon the operating results of the limited partnership investments sold. Consequently, in accordance with SEC Staff Accounting Bulletin Topic 5E, the Trust has not recorded a gain on the sale of its ownership interest. The cash proceeds received were recorded as a reduction of its investment in the limited partnership investments and interest and principal received under the promissory note will continue to be recorded as a reduction of the note receivable balance until the carrying value has been reduced to zero. In the event the divested business incur operating losses in future periods, a corresponding reduction in the note receivable will be recorded as a valuation allowance.
As of September 20, 2002, the carrying value of the Trust's share in the B-3 Limited Partnership, was $1,253,016. The carrying value of the note at December 31, 2003 was $807,195.
Summarized financial information for the B-3 Limited Partnership is as follows:
Statement of Operations Information
(Unaudited) For the Year Period ended Ended -------------- ------------ September 20, December 31, 2002 2001 -------------- ------------ Revenue ................... $4,477,725 $5,948,082 Operating expense ......... 4,343,054 5,889,936 ---------- ---------- Net income ................ $ 134,671 $ 58,146 ---------- ----------
Trust share ............... $ 104,497 $ 43,459 ---------- ----------
4. Note Receivable from Sale of Investment
On June 25, 1997, the Trust sold its entire interest in a chilled water facility to subsidiaries of NRG Energy, Inc. ("NRG"). As part of the consideration, the Trust received an 8% promissory note in the amount of $2,700,000 payable monthly over six years. In 2003, the Trust received the final payments under the promissory note.
5. Commitments and Contingencies
The Monterey project has a long-term operating ground lease. The lease expires May 2021.
Future minimum lease payments as of December 31, 2003 are as follows:
Year Ended December 31, Repayment ------------ --------- 2004 $ 12,396 2005 12,396 2006 12,396 2007 12,396 Thereafter 165,280 --------- Total $ 227,260 ---------
Rent expense for each of the years ended December 31, 2003, 2002 and 2001 was $12,396.
The Monterey project has a long-term agreement to purchase natural gas from its supplier at a fixed price throughout the term, which as of December 31, 2003, is below market prices. The agreement expires in August 2006.
Future minimum purchases under the agreement as of December 31, 2003 are as follows:
Year Ended December 31, Purchases ------------ --------- 2004 $ 893,187 2005 1,365,903 2006 910,602 --------- Total $ 3,169,692 ---------
In order to hedge exposure to commodity price risks and to maximize the impact of the increase in natural gas prices, the Trust entered into a master re-sale agreement with its supplier of natural gas to the Monterey project. The master re-sale agreement, which expires in August 2006, compels the supplier to repurchase from the Trust any natural gas the Trust chooses not to take delivery of if a predetermined re-sale price has been established. As of December 31, 2003, a re-sale price to the supplier, in excess of the underlying cost of the natural gas, has been established for 2004. In 2003, the Trust has recorded an unrealized gain of $487,902 in accordance with SFAS 149 utilizing re-sale prices committed for and fair value prices for re-sale prices uncommitted for.
In addition to the letter of credit discussed in Note 6, the gas supply agreement is collateralized by the Monterey Projects trade accounts receivable.
6. Line of Credit Facility and Letters of Credit
On June 26, 2003, Ridgewood Renewable Power LLC, 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.
In August 2003, the Trust issued through its bank a standby letter of credit, in the amount of $504,000 to secure the gas purchases for the Monterey project. The Trust used Ridgewood Renewable Power's credit facility to collateralize the letters of credit.
7. 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 to the managing shareholder an annual management fee equal to 1.5% of the prior year's net asset value of the Trust payable monthly. During 2003, 2002 and 2001, the Trust paid management fees to the managing shareholder of $108,407 and $117,058 $177,337, 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.
Where permitted, in the event the managing shareholder or an affiliate performs brokering services in respect of an investment acquisition or disposition opportunity for the Trust, the managing shareholder or such affiliate may charge the Trust a brokerage fee. Such fee may not exceed 2% of the gross proceeds of any such acquisition or disposition. No such fees have been incurred through December 31, 2003.
The managing shareholder owns 1.45 investor shares of the Trust with a cost of $121,800. 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 power generation projects operated by the Trust. Ridgewood Management charges the project at its cost for these services and for the allocable amount of certain overhead items. Allocations of costs are on the basis of identifiable direct costs, time records or in proportion to amount invested in projects managed by Ridgewood Management. During the year ended December 31, 2003, 2002 and 2001, Ridgewood Management charged Sunnyside Cogeneration Partners $120,252, $132,810 and $153,354, respectively, for overhead items allocated in proportion to the amount invested in projects managed. During the years ended December 31, 2003, 2002 and 2001, Ridgewood Management charged the California Pumping Project $21,141, $20,973 and $77,103, respectively, for overhead items allocated in proportion to the amount invested in projects managed. Ridgewood Management also charged Sunnyside Cogeneration Partners and the California Pumping Project for all of the direct operating and non-operating expenses incurred during the periods.
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 outstanding payables of $83,148 and $47,883, respectively, to Ridgewood Management. At December 31, 2003 and 2002, the Trust had short-term receivables from affiliates in the amounts of $16,628 and $14,512, respectively.
8. 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 letter of credit does not differ materially from its carrying value.
9. Financial Information by Business Segment
The Trust's business segments were determined based on similarities in economic characteristics and customer base. The Trust's principal business segments consist of wholesale and retail.
Common services shared by the business segments are allocated on the basis of identifiable direct costs, time records or in proportion to amount invested in projects managed by Ridgewood Management.
The financial data for business segments are as follows:
Wholesale -------------------------------------------- 2003 2002 2001 ----------- ----------- ------------ Revenue ....................... $ 2,104,050 $ 2,122,189 $ 1,498,420 Depreciation and amortization ................ 245,159 245,718 245,813 Operating income (loss) ....... 115,945 442,677 (794,616) Total assets .................. 4,033,297 3,838,577 4,026,379 Capital expenditures -- -- 6,617
Retail -------------------------------------------- 2003 2002 2001 ----------- ----------- ------------ Revenue ....................... $ 602,694 $ 952,925 $ 875,976 Depreciation and amortization .................. 103,593 102,944 100,396 Operating income (loss) ....... (94,224) 17,289 15,544 Total assets .................. 255,984 321,862 488,289 Capital expenditures .......... -- 22,432 --
Corporate -------------------------------------------- 2003 2002 2001 ----------- ----------- ------------ Revenue ....................... $ -- $ -- $ -- Depreciation and amortization ................ -- -- -- Operating loss ................ (242,909) (533,833) (324,482) Total assets 2,018,479 3,400,566 3,701,487 Capital expenditures .......... -- -- --
Total -------------------------------------------- 2003 2002 2001 ----------- ----------- ------------ Revenue ....................... $ 2,706,744 $ 3,075,114 $ 2,374,396 Depreciation and amortization ................ 348,752 348,662 346,209 Operating loss ................ (221,188) (73,867) (1,103,554) Total assets 6,307,760 7,561,005 8,216,155 Capital expenditures .......... -- 22,432 6,617
10. Pacific Gas and Electric Company Financial Crisis
Due to financial difficulties, PG&E did not pay in full for electrical energy and capacity delivered by the Monterey Project in December 2000 and January 2001. Accordingly, the Monterey Project was unable to pay its natural gas supplier for the gas delivered for those months. In late January of 2001, the gas supplier requested assurance of payment before it would agree to provide natural gas during February. Due to PG&E's financial crises and its inability to pay, the Monterey Project was unable on its own to provide an acceptable assurance or to pay the arrears and, as a result, the supplier refused to provide natural gas beyond February 6, 2001 and the Trust shut down the Monterey Project. Many qualified facilities under contract with PG&E suffered the same fate and were temporarily forced to shut operations because of PG&E's failure to pay for energy and capacity delivered. On April 6, 2001, as a result of its financial problems, PG&E filed for protection under the U.S. Bankruptcy laws.
In April 2001, the Monterey 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 December 2000 and January 2001. Costs associated with the sale of receivables of $127,130 in 2001, primarily related to the discount and loss on sale, are included in provision for bad debt expense in the Consolidated Statements of Operations.
In August 2001, PG&E and the Monterey Project entered into an amendment to the electric power sales contract for a term of five years, which would effectively replace, for such 5 year term, the variable formula for determining the energy price with a fixed energy price. Also in August 2001, the Monterey Project entered into a five year fixed price natural gas supply agreement with Coral Energy Services, Inc., a subsidiary of Shell Oil.
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 ................. $ 669,000 $ 607,000 $ 759,000 $ 672,000 Income (loss) from operations ............. 18,000 (73,000) (101,000) (65,000) Net income (loss) ....... 24,000 (70,000) 160,000 159,000
--------------------------------------------------- First Second Third Fourth Quarter Quarter Quarter Quarter --------- -------- --------- --------- Revenue ................ $ 737,000 $ 771,000 $ 900,000 $ 667,000 Income (loss) from operations ............ (22,000) (17,000) 27,000 (62,000) Net income (loss) ...... (69,000) 281,000 (23,000) 67,000
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 over the last 17 years (of which 25 have terminated) and which had total capital contributions in excess of $190 million. The programs operated by Ridgewood Energy have invested in oil and natural gas drilling and completion and other related activities. Other affiliates of the Managing Shareholder include Ridgewood Securities Corporation ("Ridgewood Securities"), an NASD member which has been the placement agent for the private placement offerings of the eight trusts sponsored by the Managing Shareholder and the funds sponsored by Ridgewood Energy; Ridgewood Capital Management LLC ("Ridgewood Capital"), which assists in offerings made by the Managing Shareholder and which is the sponsor of six privately offered venture capital funds (the Ridgewood Capital Venture Partners, Ridgewood Capital Venture Partners II and Ridgewood Capital Venture Partners III funds); Ridgewood Power VI LLC ("Power VI"), which is a managing shareholder of the Growth Fund, and RPM. Each of these companies is controlled by Robert E. Swanson, who is their sole director or manager.
Set forth below is certain information concerning Mr. Swanson and other executive officers of the Managing Shareholder.
Robert E. Swanson, age 57, has also 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 (collectively "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 Corporation, Mr. Gold was a corporate attorney in the law firm of Cleary, Gottlieb, Steen & Hamilton in New York City where his experience included mortgage finance, mergers and acquisitions, public offerings, tender offers, and other business legal matters. Mr. Gold is a member of the New York State bar. He is a graduate of Colgate University and New York University School of Law.
Daniel V. Gulino, age 43, is Senior Vice President and General Counsel of the Managing Shareholder, RPM, Ridgewood Capital, the Trust, Other Power Trusts and the Ridgewood LLCs. 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, is 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, the 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 all administrative and service expenses necessary to perform the foregoing obligations. The Trust will pay all other expenses of the Trust, including transaction expenses, valuation costs, expenses of preparing and printing periodic reports for Investors and the Commission, postage for Trust mailings, Commission fees, interest, taxes, legal, accounting and consulting fees, litigation expenses and other expenses properly payable by the Trust. The Trust will reimburse the Managing Shareholder for all such Trust expenses paid by it.
As compensation for the Managing Shareholder's performance under the Management Agreement, the Trust is obligated to pay the Managing Shareholder an annual management fee described below at Item 13 -- Certain Relationships and Related Transactions.
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 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 executive officers of the Trust are identical to those of the Managing Shareholder.
The officers have the duties and powers usually applicable to similar officers of a Delaware business corporation in carrying out Trust business. Officers act under the supervision and control of the Managing Shareholder, which is entitled to remove any officer at any time. Unless otherwise specified by the Managing Shareholder, the President of the Trust has full power to act on behalf of the Trust. The Managing Shareholder expects that most actions taken in the name of the Trust will be taken by Mr. Swanson and the other principal officers in their capacities as officers of the Trust under the direction of the Managing Shareholder rather than as officers of the Managing Shareholder.
(e) 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
To the knowledge of the Trust, there were no violations of the reporting requirements of section 16(a) of the 1934 Act by officers and directors of the Trust in the last fiscal year.
(g) RPM.
As discussed above at Item 1 - Business, RPM has assumed day-to-day management responsibility for the Monterey Project, effective January 1, 1996 and operating responsibility for the Pumping Project in October 1998 and had assumed certain responsibilities for the San Diego Project in early 1997 until its sale. Like the Managing Shareholder, RPM is controlled by Robert E. Swanson. It has entered into an "Operation Agreement" with certain of the Trust's subsidiaries, effective January 1, 1996, under which RPM, under the supervision of the Managing Shareholder, provides the management, purchasing, engineering, planning and administrative services for those Projects that were previously furnished by employees of the Trust or by unaffiliated professionals or consultants and that were borne by the Trust or Projects as operating expenses. To the extent that those services were provided by the Managing Shareholder and related directly to the operation of the Project, RPM charges the Trust at its cost for these services and for the Trust's allocable amount of certain overhead items. RPM shares space and facilities with the Managing Shareholder and its Affiliates. To the extent that common expenses can be reasonably allocated to RPM, the Managing Shareholder may, but is not required to, charge RPM at cost for the allocated amounts and such allocated amounts will be borne by the Trust and other programs. Common expenses that are not so allocated are borne by the Managing Shareholder.
The Managing Shareholder does not charge RPM for the full amount of rent, utility 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; all 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, although it may be authorized to act on behalf of the subsidiaries that own Projects.
The Operation Agreement does not have a fixed term and is terminable by RPM, by the Managing Shareholder or by vote of a majority of interest of Investors, on 60 days' prior notice. The Operation Agreement may be amended by agreement of the Managing Shareholder and RPM; however, no amendment that materially increases the obligations of the Trust or that materially decreases the obligations of RPM shall become effective until at least 45 days after notice of the amendment, together with the text thereof, has been given to all Investors.
The executive officers of RPM are the same as those of the Managing Shareholder 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 10U.
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 235.3775 Investor Shares (approximately $23.5 million of gross proceeds) of beneficial interest in the Trust pursuant to a private placement offering under Rule 506 of Regulation D under the Securities Act. The offering closed on January 31, 1994. Further details concerning the offering are set forth above at Item 1 -- Business.
The Managing Shareholder purchased for cash of $121,800 in the offering 1.45 Investor Shares (.6 of 1% of the outstanding Investor Shares). The Managing Shareholder was issued one Management Share in the Trust representing the beneficial interests and management rights of the Managing Shareholder in its capacity as such (excluding its interest in the Trust attributable to Investor Shares it acquired in the offering). Additional information concerning the management rights of the Managing Shareholder is at Item 1 - Business and at Item 10 -- Directors and Executive Officers of the Registrant. Its beneficial interest in cash distributions of the Trust and its allocable share of the Trust's net profits and net losses and other items attributable to the Management Share are described in further detail below at Item 13
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable reserves which the Trust deems necessary to cover anticipated Trust expenses, is to be distributed to the Investors and the Managing Shareholder (collectively, the "Shareholders"), from time to time as the Trust deems appropriate. Prior to Payout (the point at which Investors have received cumulative distributions equal to the amount of their capital contributions), each year all distributions from the Trust, other than distributions of the revenues from dispositions of Trust Property, are to be allocated 99% to the Investors and 1% to the Managing Shareholder until Investors have been distributed during the year an amount equal to 15% of their total capital contributions (a "15% Priority Distribution"), and thereafter all remaining distributions from the Trust during the year, other than distributions of the revenues from dispositions of Trust Property, are to be allocated 80% to Investors and 20% to the Managing Shareholder. Revenues from dispositions of Trust Property are to be distributed 99% to Investors and 1% to the Managing Shareholder until Payout. In all cases, after Payout, Investors are to be allocated 80% of all distributions and the Managing Shareholder 20%.
For any fiscal period, the Trust's net profits, if any, other than those derived from dispositions of Trust Property, are allocated 99% to the Investors and 1% to the Managing Shareholder until the profits so allocated offset (1) the aggregate 15% Priority Distribution to all Investors and (2) any net losses from prior periods that had been allocated to the Shareholders. Any remaining net profits, other than those derived from dispositions of Trust Property, are allocated 80% to the Investors and 20% to the Managing Shareholder. If the Trust realizes net losses for the period, the losses are allocated 80% to the Investors and 20% to the Managing Shareholder until the losses so allocated offset any net profits from prior periods allocated to the Shareholders. Any remaining net losses are allocated 99% to the Investors and 1% to the Managing Shareholder. Revenues from dispositions of Trust Property are allocated in the same manner as distributions from such dispositions. Amounts allocated to the Investors are apportioned among them in proportion to their capital contributions.
On liquidation of the Trust, the remaining assets of the Trust after discharge of its obligations, including any loans owed by the Trust to the Shareholders, will be distributed, first, 99% to the Investors and the remaining 1% to the Managing Shareholder, until Payout, and any remainder will be distributed to the Shareholders in proportion to their capital accounts.
In 2003 and 2002, as stated at Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters, as well as in prior years, the Trust made distributions to the Managing Shareholder (which is a member of the Board of the Trust) as stated at Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters. In addition, the Trust and its subsidiaries paid fees and reimbursements to the Managing Shareholder and its affiliates as follows:
2003 2002 2001 2000 1999
Managing Shareholder $108,407 $117,058 $177,727 $ -0- $55,607 RPM Cost Reimbursements 2,486,469 2,862,273 2,955,915 3,032,954 2,841,952
The management fee, payable monthly under the Management Agreement at the annual rate of 2.5% of the Trust's prior year net asset value, began on the date the first Project was acquired and compensates the Managing Shareholder for certain management, administrative and advisory services for the Trust. Under the Declaration of Trust, the annual rate fell to 1.5% per year beginning February 1, 1999. Beginning April, 1999, the Managing Shareholder waived the fee. Effective January 1, 2001, it resumed payment of the management fee at the 1.5% of net asset value annual rate.
In addition to the foregoing, the Trust reimbursed the Managing Shareholder at cost for expenses and fees of unaffiliated persons engaged by the Managing Shareholder for Trust business. Payroll and other costs of operation of the Trust's Projects are reimbursed to RPM. The reimbursements to RPM, which do not exceed its actual costs and allocable overhead, are described at Item 10(g) - Directors and Executive Officers of the Registrant -- RPM.
Other information in response to this item is reported in response to Item 11 -- Executive Compensation, which information is incorporated by reference into this Item 13.
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 $20,000 and $32,000, 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 $25,000. 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 PrcewaterhouseCoopers LLP and engaging Perselson Weiner LLP.
(c) Exhibits
3A. Certificate of Trust of the Registrant, is incorporated by reference to Exhibit 3A to the Registrant's Registration Statement on Form 10 filed with the Commission on February 27, 1993.
3B. Amended and Restated Declaration of Trust of the Registrant, is incorporated by reference to Exhibit 4 to the Quarterly Report on Form 10Q of the Registrant for the quarter ended September 30, 1993.
10A. Management Agreement dated as of January 4, 1993 between the Registrant and Ridgewood Power Corporation, is incorporated by reference to Exhibit 10 to the Registrant's Registration Statement on Form 10 filed with the Commission on February 27, 1993.
10B. Limited Partnership Agreement of Pittsfield Investors Limited Partnership (without exhibits), is incorporated by reference to Exhibit 2(i) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10C. Asset Purchase Agreement between EAC Systems, Inc. and Vicon Recovery Associates ("Vicon") dated as of December 23, 1992 (the "Asset Purchase Agreement") (without exhibits), is incorporated by reference to Exhibit 2(ii) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10D. First Amendment of Asset Purchase Agreement dated as of December 30, 1993 (without exhibits), is incorporated by reference to Exhibit 2(ii) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10E. Lease dated as of September 1, 1979 between the City of Pittsfield, Massachusetts (acting by and through its Industrial Development Financing Authority), is incorporated by reference to Exhibit 2(iv) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10F. Amended and Restated Solid Waste Disposal and Resource Recovery Agreement dated August 6, 1979 by and among the City of Pittsfield, Vicon and others (together with amendments dated October 26, 1984, July 28, 1989 and December 29, 1993), is incorporated by reference to Exhibit 2(v) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
10G. Steam Purchase Agreement by and between Crane & Co., Inc. and Vicon dated as of February 1, 1979 (with amendments), is incorporated by reference to Exhibit 2(vi) to the Form 8-K of Registrant filed with the Commission on January 19, 1994.
The Registrant is no longer a party to former Exhibits 10H through 10M because of its sale of the San Diego Project. See Exhibits 10P-R.
10N. Acquisition Agreement dated as of January 9, 1995 among Sunnyside Cogen, Inc., and NorCal Sunnyside Inc., as Sellers, and RW Monterey, Inc. and Ridgewood Electric Power Trust II, as Purchasers, is incorporated by reference to Exhibit 2(i) to the Form 8K of Registrant filed with the Commission on February 16, 1995.
10O. Acquisition Agreement, dated as of March 31, 1995, by and among the Trust and its subsidiary, Pump Services Corporation, as purchasers and Donald C. Stewart, Union Energy Corp. and Donald A. Sherman as sellers. Incorporated by reference to Exhibit 10O to the Annual Report on Form 10-K of the Registrant for the year ended December 31, 1995.
10P. Partnership Interest Purchase Agreement, dated as of June 25, 1997, by and among the Trust, RSD Power Corp., NRG San Diego, Inc., and NRG del Coronado, Inc. Incorporated by reference to Exhibit 2.A. of the Current Report on Form 8-K of the Registrant, dated June 25, 1997. Exhibits and schedules are omitted, and a list of the omitted documents is found at page 20 of the agreement. The Registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the Partnership Interest Purchase Agreement to the Commission upon request.
10Q. Purchase Money Promissory Note. Incorporated by reference to Exhibit 2.B. of the Current Report on Form 8-K of the Registrant, dated June 25, 1997.
10R. Security and Pledge Agreement, dated as of June 25, 1997, by and among the Trust, RSD Power Corp., NRG San Diego, Inc., and NRG del Coronado, Inc. Incorporated by reference to Exhibit 2.C. of the Current Report on Form 8-K of the Registrant, dated June 25, 1997.
10S. Master Sale Agreement, dated August 8, 2001, by and between Sunnyside Cogeneration Partners, L.P. and Coral Energy Resources, L.P. (the terms of the actual transaction are subject to confidentiality provisions).
10T. Acquisition Agreement, dated September 20, 2002, by and between the Trust and EAC Operations, Inc.
10U. Code of Ethics, adopted March 1, 2004.
99.1. Certifications under Section 906 of the Sarbanes-Oxley Act.
The Registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to agreements filed as 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 II (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 II ("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 II ("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