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 III (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 include 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 December 6, 1993 to participate in the development, construction and operation of independent power generating facilities or related projects or facilities ("Independent Power Projects" or "Projects").
The Trust sold whole and fractional shares of beneficial interest in the Trust ("Investor Shares") pursuant to a private placement offering (the "Offering"), which terminated on May 31, 1995. Net of Offering fees, commissions and expenses, the Offering provided approximately $32.9 million of net funds available for investments in the development and acquisition of Projects. The Trust has 833 record holders of Investor Shares (the "Investors"). As described below in Item 1(c)(2), the Trust has invested substantially all of its net funds in the 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 14, 1994, the Trust notified the Securities and Exchange Commission of such election and registered the Investor Shares under the Securities Exchange Act of 1934, as amended (the "1934 Act"). On April 16, 1994, the election and registration became effective. On November 5, 2001, the Trust issued to 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") necessary as a result of such withdrawal, including, but not limited to, deleting the section of the Declaration requiring Independent Trustees. Consents were tabulated at the close of business on December 18, 2001. Based on such tabulation, a majority of Investor Shares consented to such withdrawal and amendments. On January 10, 2002, the Trust filed with the Securities and Exchange Commission a notification to withdraw its election to be treated as a "business development company." As a result of such withdrawal, the Trust now utilizes generally accepted accounting principles for operating companies.
The Trust is organized similarly to a limited partnership. Ridgewood Renewable Power LLC (the "Managing Shareholder"), a Delaware limited liability company, is the Managing Shareholder of the Trust. 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 Investor does not regularly elect the Managing Shareholder. 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. See Item 10. Directors and Executive Officers of the Registrant below for a further description of the management of the Trust.
The Trust is affiliated with the following trusts organized by the Managing Shareholder ("Other Power Trusts"):
o Ridgewood Electric Power Trust I ("Power I"); o Ridgewood Electric Power Trust II ("Power II"); 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 ("B Fund").
In addition, the Trust is affiliated with certain Delaware limited liability companies form by the Managing Shareholder ("Ridgewood LLCs") and for which the Managing Shareholder acts as Manager:
o Ridgewood Renewable PowerBank, LLC; o Ridgewood Renewable PowerBank II, LLC; 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.
(c) Narrative Description of Business.
(1) General Description.
The Trust has invested its funds in seven Projects or groups of Projects:
(i) a 5.7 megawatt cogeneration facility located in Byron, California (the "Byron Project"); (ii) an 8.5 megawatt cogeneration facility located in Atwater, California (the "San Joaquin Project"); (iii) a portfolio of 4 small cogeneration facilities located in California, New York and Massachusetts purchased from Eastern Utilities Associates,Inc. (the "On-site Cogeneration Projects"); (iv) an additional cogeneration project located at an airline food preparation facility in Los Angeles, California (the "El Segundo Project"); (v) Ridgewood/AES Power Partners, L.P., a joint venture that operated 5 small cogeneration projects in New York, which was sold in 2003; (vi) a 13.8 megawatt electric generation plant fueled by gas drawn from a sanitary landfill near Providence, Rhode Island (the "Providence Project"); and (vii) a portfolio of four power modules (each having a diesel engine and electric generator mounted on a skid with necessary control and transformer equipment) which are being marketed and operated by Hawthorne Power Systems, Inc., San Diego, California (the "Mobile Power Units").
(2) The Trust's Investments.
(i) San Joaquin Project and Byron Project.
On January 17, 1995, the Trust and a wholly-owned subsidiary acquired 100% of the existing partnership interests of JRW Associates, L.P., a California limited partnership which owns and operates an approximately 8.53 megawatt electric cogeneration facility located in the City of Atwater, Merced County, California (the "San Joaquin Project"). The aggregate cash purchase price paid by the Trust for 100% of the partnership interests was $4,900,000.
The San Joaquin 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 San Joaquin Project is used to provide steam to an adjacent food processing company under a long-term contract that also terminates in 2020.
Also in January 1995, the Trust formed Byron Power Partners, L.P., a California limited partnership (the "Byron Partnership"). On January 17, 1995, the Byron Partnership acquired through a merger all of the assets and business of Altamont Cogeneration Corporation, including an approximately 5.7-megawatt electric cogeneration facility located near the city of Byron, Alameda County, California (the "Byron Project"). The aggregate cash purchase price paid by the Trust for 100% of the partnership interests was $2,509,000.
The Byron Project, like the San Joaquin Project, is fueled by natural gas and sells its electric output to PG&E under a Power Contract substantially similar to that of the San Joaquin Project (collectively the "Power Contracts"). The Power Contract for the Byron Project also expires in 2020. The Byron Project's heat output is used to evaporate brine from oil and gas wells, with payments by the Byron Project for the site lease offsetting the thermal host's payments for heat.
Both the San Joaquin and Byron Projects (collectively "NorCal Projects") are Qualifying Facilities ("QFs") pursuant to the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). Historically, producers of electric power in the United States consisted of regulated utilities serving end-use retail customers. PURPA, among other things, requires utilities to purchase electric power from QFs, including "cogeneration facilities" and "small power producers," and also exempts these QFs from most federal and state utility regulatory requirements. 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 rates set by contract formulae approved by state regulatory commissions. The NorCal Projects entered into such contracts with PG&E. The capacity and energy price paid by PG&E pursuant to the Power Contracts were determined pursuant to a contract formula approved by the California Public Utilities Commission ("CPUC") with the energy payment originally 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, both the NorCal Projects executed an Amendment to their Power Contract with PG&E, which provides that the Projects will receive a fixed energy payment (as well as the required capacity payment) for a term of five (5) years.
As a result of the California energy crises in 2000 and 2001, 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 Byron and San Joaquin Projects 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 and were ultimately forced to cease operations.
Subsequent to its bankruptcy filing, in an effort to get as many QFs back online as possible, PG&E sought and received approval from the 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 appeared to be 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. Finally, in order to execute an amendment with a fixed energy price, it was necessary to procure natural gas at a fixed price. The Byron and San Joaquin Projects were able to procure such fixed, five-year supply of natural gas from Coral Energy Services, Inc., ("Coral") a subsidiary of Shell Oil. Therefore, until approximately August 2006, the Byron and San Joaquin Projects will be operating under the Amendment, which is expected to result in positive cash flow to the Byron and San Joaquin Projects. 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.
(ii) On-site Cogeneration Projects
In September 1995, the Trust purchased the ownership interests in the On-site Cogeneration Projects, a portfolio of 35 small cogeneration Projects owned by affiliates of Eastern Utilities Associates, Inc. ("EUA"), for an aggregate purchase price of approximately $11.3 million. The Trust has invested an additional $1.4 million for capital improvements in the Projects and has expended additional amounts on remediation. The On-site Cogeneration Projects use natural gas fired turbines or reciprocating engines to provide electrical energy and/or heat for industrial uses or air conditioning purposes under contracts with a variety of industrial customers. The On-site Cogeneration Projects were located on 35 sites in California (18 sites), Connecticut (six sites), Massachusetts (two sites), New York (eight sites) and Rhode Island (one site).
Returns from the On-site Cogeneration Projects deteriorated and beginning in the third quarter of 1997 the Trust has closed most of the Projects. Because of closures and contract expirations, the Trust has recorded writedowns of $10.8 million relating to On-site Cogeneration Projects since their purchase.
The Massachusetts projects included the Globe Project, a 3.5 Megawatt turbine with backup diesel engines, located at a Fall River, Massachusetts's facility owned by Globe Manufacturing Corp. ("Globe"). On January 13, 2001, Globe filed a voluntary petition for bankruptcy in the United States Bankruptcy Court for the Northern District of Alabama, where Globe is headquartered. As part of the bankruptcy proceeding, Globe sold substantially all of its assets, including the Fall River facility. The Bankruptcy Court approved the sale. The Power Contract that the Trust has with Globe has been rejected by Globe in the Bankruptcy Court proceedings. Effectively the Power Contract has been terminated and the Trust has "rejection" damages claims against Globe, but given Globe's financial condition it is not likely that significant amounts of money will be available to pay such rejection damages. In 2002, the Trust sold the Globe Project equipment, but not the claim for rejection damages, for $250,000. The purchaser is responsible for, and has assumed all of the risk of, the equipment removal and transportation. The Trust has received full payment for the Globe Equipment.
Two of the projects are still in operation. The Coca-Cola Project is located at a bottling plant of Coca-Cola Bottling Company of New York at Elmsford, New York and has a rated capacity of 1.3 Megawatts with a .6 Megawatt standby diesel generator set. The Marriott Project is located in Coronado, California with a rated capacity of .6 Megawatts.
RPM has management responsibility for the On-site Cogeneration Projects. See Item 10 -- Directors and Executive Officers of the Registrant.
(iii) Ridgewood El Segundo, LLC
In April 1998, the Trust purchased an additional cogeneration project located at a food preparation facility for the Los Angeles International Airport from a private developer. The project is located within one mile of an On-Site Cogeneration Project also owned by the Trust at the Airport. In September 2003, the food preparation facility ceased operations and the power contract expired thus, the Trust ceased the project's operations and is now attempting to sell the project's equipment.
(iv) Ridgewood/AES Power Partners, LLC.
The Trust engaged AES-NJ Cogen, Inc., a small operator of cogeneration plants ("AES") that is not affiliated with the Trust, to operate five of the smallest On-Site Cogeneration Projects. In September 1997 the Trust and AES created a joint venture, Ridgewood/AES Power Partners, L.P. ("Ridgewood AES") to develop additional small cogeneration projects in the New York metropolitan area. The Trust supplies capital and AES supplies development services. At December 31, 2002 Ridgewood AES owned five cogeneration projects at hotels and hospitals in New York and New Jersey.
In 2003, the Trust sold 100% of its ownership interest in Ridgewood AES to AES-NJ for $100,000 cash, a $150,000 interest bearing promissory note ("promissory note") and a $74,394 interest free note ("interest free note"}. The promissory note bears interest at a rate of 10% per annum, and will be repaid monthly over a four-year term. The interest free note will be repaid over a six-month term. For the year 2002, the Trust recorded a writedown of $67,000 to reflect the project's fair market value as determined by the terms of the sale agreement.
(v) Providence Project
The Trust and Power IV acquired in April 1996 all of the equity interest in an landfill gas-fired electric generating facility, located on land adjacent to the Central Landfill, near Providence, Rhode Island. The Trust invested $7.1 million in the Providence Project and Power IV supplied the remainder of the $20 million investment in the Project. The Trust owns 35.7% of the Providence Project and Power IV owns the remaining 64.3%. The acquisition cost was approximately $15.5 million (including a $3 million partial prepayment of Project debt as a condition of obtaining the lenders' consents and transaction costs) and the remainder of the investment by the programs represents funds applied to operating reserves, working capital and reserves for capital improvements and expansion. The Providence Project was encumbered by $5.4 million of debt that has been paid in full as of February 2004.
The Project burns methane gas generated by the decomposition of garbage and other waste in the landfill as fuel for a 13.8 Megawatt capacity electric generation plant. The facility has been in operation since 1990 and has a Power Contract for 12.0 Megawatts with New England Power Company ("NEP") that expires in 2020.
The Project leases the right to use the landfill site from the Rhode Island Resource Recovery Corporation, a state agency ("RIRRC"), for a royalty of 15% of net Project revenues , until the year 2006, thereafter 15% to 18% depending upon production. The Project in turn subleases those rights to Central Gas Limited Partnership ("Gasco"). Gasco, which is not affiliated with the Trust, had operated and maintained the piping system and other facilities to collect the methane gas from the Landfill and supply it to the Project. Gasco pays a fixed rent, computed on the basis of the Project's generating capacity, to the Project under the sublease, and the Project in turn buys its fuel from Gasco at a formula price per kilowatt-hour generated by the Project.
Throughout the Trusts' ownership of the Providence Project, certain situations have occurred at the landfill regarding Gasco's operation and maintenance of the gas collection system, which convinced the Trust and Power IV that the gas collection system could be operated and maintained more efficiently and economically and could provide higher quality, and greater quantities of, landfill gas. The resulting savings in costs and increase in quantity and quality of methane gas would benefit the Providence Project. In addition, RIRRC anticipated that the Central Landfill would be capable of providing landfill gas from new phases that could fuel an additional 12 MW. Therefore, on August 1, 2003, the Trust and Power IV concluded a transaction in which the operation and maintenance of the gas collection systems was transferred to Ridgewood Gas Services, LLC, ("RGS") which is owned by the Trust and Power IV in the same proportion to their ownership in the Providence Project. RGS is a cost reimbursement company whose operations are funded both by Gasco and the RIRRC. Pursuant to a Landfill Services Agreement with RGS, Gasco pays RGS for its operation of the gas collection system that is owned by Gasco. In addition, pursuant to a Landfill services Agreement with RIRRC, RGS operates and maintains the gas collection system owned by RIRRC and RIRRC funds the remainder of RGS' operations not funded by Gasco's payments. In addition, as part of the transaction, Ridgewood Rhode Island Generation, LLC, owned by the Trust's affiliate, the B Fund, has obtain rights to landfill gas from RIRRC and develop an additional 7.5 MW landfill gas-fired electric generation facility, which the B Fund estimates will be completed on or about June 1, 2004.
On January 17, 2003, the Providence Project received a "Statement of Qualification" from the Massachusetts Division of Energy Resources ("DOER") pursuant to the renewable portfolio standards ("RPS") adopted by Massachusetts. In 1997, Massachusetts enacted the Electric Restructuring Act of 1997 (the "Restructuring Act"). Among other things, the Restructuring Act requires that all retail electricity suppliers in Massachusetts (i.e. those entities supplying electric energy to retail end-use customers in Massachusetts) purchase a minimum percentage of their electricity supplies from qualified new renewable generation units powered by one of several renewable fuels, such as solar, biomass or landfill. Beginning in 2003, each such retail supplier must obtain at least one (1%) percent of its supply from qualified new renewable generation units. Each year thereafter, the requirement increases one-half of one percentage point until 2009, when the requirement equals four (4%) percent of each retail supplier's sales in that year. Subsequent to 2009, the increase in the percentage requirement will be determined and set by the DOER.
Now that the Providence Project has been qualified in Massachusetts, it may sell to retail electric suppliers the RPS Attributes associated with its electrical energy. Retail electric suppliers need to purchase RPS Attributes associated with renewable energy and not necessarily the energy itself. Thus, electrical energy and RPS Attributes are separable products and need not be sold or purchased as a bundled product. Retail electric suppliers in Massachusetts will then use the purchase of such RPS Attributes to demonstrate compliance with the Restructuring Act and RPS Regulations. The Trust, along with Power IV, V and the B Fund, completed a transaction with a major power marketer that does business in Massachusetts for the sale of the RPS Attributes generated by the Providence Project, as well as the RPS Attributes generated by Projects owned by Power IV, V and the B Fund. The transaction, which is confidential, provides such power marketer with six separate annual options to purchase such output in each year from 2004 through 2009. If the power marketer elects to not purchase the RPS Attributes in any year, the Providence Project is free to sell to other parties. Under the terms of the transaction, the prices to be received by the Providence Project for the RPS Attributes, if the power marketer elects to purchase, are very favorable.
However, only a portion of the Providence Project's output qualifies for RPS Attributes in Massachusetts. Because the Providence Project was in operation during the period 1995 through 1997, the average annual generation produced during those years does not qualify. Under the Massachusetts regulations, it is defined as the Providence Project's "Vintage Generation", amounts to approximately 86,000 MWhs per year, and the RPS Attributes associated with such annual amounts of generation do not qualify in Massachusetts. However, during 2004, the Providence Project became qualified to sell RPS Attributes in Connecticut. The Connecticut RPS program is different than the Massachusetts program in that it does not have a "Vintage" prohibition. Thus, the Providence Project can sell the 86,000 MWhs that are ineligible in Massachusetts into the Connecticut market. In fact, the Providence Project has entered into several short-term agreements with various power marketers to sell the RPS Attributes associated with such "Vintage Generation". The prices for the RPS Attributes in those agreements, although lower than current market, are beneficial to the Providence Project.
(vi) Mobile Power Units
In August 1999 the Trust purchased five Caterpillar unified power modules (the "Mobile Power Units") for $1,696,000. The Units combine a large diesel engine with a fuel tank, emission equipment, an electric generator and control equipment on a single skid and therefore can be moved to remote areas as a self-contained power plant. The owner of the Units is Ridgewood Mobile Power III, LLC, a wholly-owned subsidiary of the Trust. The Trust bought the Units from Hawthorne Power Systems, Inc. ("Hawthorne") of San Diego, California (a Caterpillar distributor). Hawthorne added the Units to its own rental fleet of similar equipment and rents them to contractors, engineering firms and other industrial or commercial customers who need emergency, temporary or peak power supplies. The Trust receives 80% of the net rental revenues and is responsible for major maintenance; Hawthorne receives 20% of the net rental revenues to compensate it for marketing and managing the rentals. Due to the increase in competition and production of newer efficient models, the Trust experienced a decrease in rental revenue for the second consecutive year. As a result of the change in these market conditions, the forecasted revenues for the mobile power modules are not expected to be enough to recover the units' book value. In 2003 and 2002, the Trust recorded writedowns of $87,465 and $460,697, respectively, to reflect the units fair market value. In the third quarter of 2003, the Trust decided to make its mobile power units available for sale. Shortly after making the mobile power units available for sale, the Trust sold one module for $171,000.
(3) Project Operation.
Revenue from the San Joaquin, Byron and Providence Projects primarily comes from Power Contracts with the local electric utilities. In addition, with respect to the Providence Project, additional revenues are obtained through sale of the RPS Attributes. With respect to the Power Contracts, the pricing provisions have two components, energy payments and capacity payments. Energy payments are based on a facility's net electric output, with payment rates usually indexed to the fuel costs of the purchasing utility or to general inflation indices. Capacity payments are based on either a facility's net electric output or its available capacity. Capacity payment rates vary over the term of a Power Contract according to various schedules. Pricing for the sale of RPS Attributes is generally based upon the market prices for such attributes at the time of the negotiation of the sale.
The Mobile Power Units are managed by Hawthorne and rented at fixed rates. Their major costs are capital recovery and maintenance; operating costs are borne by the customer. Electricity generated from the Mobile Power Units is generally used by the renter on-site. If there were a shortage of electric generation capacity, the Units could be rented as additional peak generation capacity by a utility or electricity seller, subject to local environmental limitations. The Mobile Power Units are rented at fixed prices per month and are operated by the renter. Rental periods typically range from one to six weeks.
The Managing Shareholder organized RPM to provide operating management for the Projects. See Item 10 -- Directors and Executive Officers of the Registrant and Item 13 -- Certain Relationships and Related Transactions for further information regarding the Operation Agreement with RPM and for the cost reimbursements received by RPM.
Electricity produced by a Project is typically delivered to the purchaser through transmission lines that are built to interconnect with the utility's existing power grid or, in the On-site Cogeneration Projects, by direct connections.
Generally, revenues from the sales of electric energy from a cogeneration facility will represent the most significant portion of the facility's total revenue. However, to maintain their status as a QF under PURPA, it is imperative that each cogeneration Project continue to satisfy PURPA cogeneration requirements as to the amount of thermal products generated. Therefore, since the Byron and San Joaquin cogeneration Projects have only two customers (the electric energy purchaser and the thermal products purchaser), and because it may be impractical to obtain replacement purchasers of either the electrical or thermal output, loss of either of these customers would likely have a material adverse effect on the Trust.
Customers that accounted for more than 10% of consolidated revenue to the Trust in each of the last three fiscal years are:
Calendar year 2003 2002 2001 Pacific Gas & Electric Co. (San Joaquin & Byron Projects) 72.3% 76.5% 53.1% Coca Cola Bottling Plant of New York (Coca Cola Project) 18.1% 12.5% 17.4%
Note that the financial statements of the Providence Project are not consolidated with those of the Trust and, accordingly, its revenues are not considered to be operating revenues.
In order to commence operations, most Projects require a variety of permits, including zoning and environmental permits. Inability to obtain such permits will likely mean that a Project will not be able to commence operations, and even if obtained, such permits must usually be kept in force in order for the Project to continue its operations.
Compliance with environmental laws is also a material factor in the independent power industry. The Trust believes that capital expenditures for, and other costs of, environmental protection have not materially disadvantaged its activities relative to other competitors and will not do so in the future. See Item 1(c)(6) -- Business -- Narrative Description of Business -- Regulatory Matters.
(4) Market Trends
The Trust's Byron and San Joaquin plants are located in California. In the years 2000 and 2001, California experienced severe energy crises. As a result, both the state legislature and the CPUC have taken significant action by enacting legislation and implementing regulations, respectively, intended primarily to avoid a repeat of the crises by creating a more stable, efficient and economic energy market. 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 overtime until the requirement equals 20%. In addition to the RPS, California enacted legislation that will streamline the time required for and the costs of new electric power plant permitting and construction. Finally, legislation has been enacted that will fundamentally change the manner in which California IOUs procure electric energy for their customers. The CPUC is currently engaged in the rule-making process that will implement these and many other requirements of the legislation. However, because the Byron and San Joaquin projects are currently under a long-term fixed price contract with PG&E, which although having declared bankruptcy is emerging a much stronger company, many of the trends in California will have little impact upon these projects.
In the year 2003 many states implemented or enacted renewable portfolio standards (RPS). For example, RPS legislation and regulations have been passed and are effective in, among other states, Massachusetts, Nevada, Texas, New Jersey, and Connecticut. Many other states are considering RPS legislation. The intent behind virtually all RPS programs is to provide added financial incentives to developers of renewable generation by requiring retail electric suppliers to purchase a certain percentage of renewable power or, alternatively, purchase the required number the renewable energy credits" ("REC"), which are created as a result of such renewable generation. As a result of the RPS programs, developers of renewable generation can effectively receive two sources of revenue: one from the sale of the actual electric energy and one from the sale of RECs. Most RPS programs effectively separate the purchase of energy from the purchase of the "REC" and basically require electric energy suppliers to have the required number of RECs at the end of the compliance period, regardless of its energy supply portfolio. Combined, these two streams of income may be sufficient to attract and increase the development of new renewable generation. As indicated earlier, the Providence Project is currently selling RECs in the Massachusetts and Connecticut market. As more and more states in the New England region and surrounding areas of the Country adopt these RPS regulations, RECs, such as those generated by the Providence Project, may be in short supply and will be more valuable until new renewable generation comes on line to supply the market.
(5) Competition
The San Joaquin, Byron and Providence Projects, as described above, are not currently subject to competition because those Projects have entered into long-term agreements to sell their output at specified prices. However, if the Power Contracts were terminated for any reason, these Projects could be subject to future competition to market its electricity output. However, the Trust believes that in the near term, until additional generation resources are completed and brought on-line, these Projects could sell their output at reasonable prices, although for a variety of factors, including the volatility of natural gas prices, unexpected legislation and litigation, there is no guarantee that they may be able to do so.
There are a large number of participants in the independent power industry. Several large corporations specialize in developing, building and operating Projects. There is significant competition among non-utility producers, subsidiaries of utilities and utilities themselves in developing and operating energy-producing projects and in marketing the power produced by such projects. The Trust is unable to accurately estimate the number of competitors but believes that there are many competitors at all levels and in all sectors of the industry. Many of those competitors, especially affiliates of utilities and equipment manufacturers, may be far better capitalized than the Trust.
Competition to market its energy products is generally not a factor in the current operations of the Trust since the major Projects in which it invested have entered into long-term agreements to sell their output at specified prices. However, a particular Project could be subject to future competition to market its energy products if its Power Contract expires or is terminated because of a default or failure to pay by the purchasing utility or other purchaser due to bankruptcy or insolvency of the purchaser or because of the failure of a Project to comply with the terms of the Power Contract; regulatory changes; loss of a cogeneration facility's status as a QF due to failure to meet minimum steam output requirements; or other reasons. It is impossible at this time to estimate the level of marketing competition that the Trust would face in any such event.
The Units compete against numerous other fleets of mobile power generation equipment on a regional and international level. To some extent local or governmental electricity utilities also compete to provide short-term electricity in less remote areas. Hawthorne owns many units in its rental fleet but has agreed to market the Trust's Units on a basis at least as favorable at it does for its own equipment. Demand for the Units is heavily dependent on the level of construction and civil engineering work in the Southern California area and on the availability of equipment from vendors, other area rental fleets and, to a limited extent, from outside-of-area fleets. Demand can be very volatile. Further, after one year, Hawthorne can cancel the marketing agreement on 5 days' notice.
(iv) Potential Legislation and Regulation.
All federal, state and local laws and regulations, including but not limited to PURPA, the Holding Company Act, the 1992 Energy Act and the FPA, are subject to amendment or repeal. Future legislation and regulation is uncertain, and could have material effects on the Trust.
(6) Regulatory Matters.
Projects are subject to energy and environmental laws and regulations at the federal, state and local levels in connection with development, ownership, operation, geographical location, zoning and land use of a Project and emissions and other substances produced by a Project. These energy and environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with such permits and approvals.
(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.
The 1992 Energy Act created the "exempt wholesale generator" category for entities certified by FERC as being exclusively engaged in owning and operating electric generation facilities producing electricity for resale. Exempt wholesale generators remain subject to FERC regulation in all areas, including rates, as well as state utility regulation, but electric utilities that otherwise would be precluded by the Holding Company Act from owning interests in exempt wholesale generators may do so. Exempt wholesale generators, however, may not sell electricity to affiliated electric utilities without express state approval that addresses issues of fairness to consumers and utilities and of reliability.
(C) The Federal Power Act. The FPA grants FERC exclusive rate-making jurisdiction over wholesale sales of electricity in interstate commerce. The FPA provides FERC with ongoing as well as initial jurisdiction, enabling FERC to revoke or modify previously approved rates. Such rates may be based on a cost-of- service approach or determined through competitive bidding or negotiation. While QFs under PURPA are exempt from the rate-making and certain other provisions of the FPA, non-QFs are subject to the FPA and to FERC rate-making jurisdiction.
(D) Fuel Use Act. Larger Projects may also be subject to the Fuel Use Act, which limits the ability of power producers to burn natural gas in new generation facilities unless such facilities are also coal-capable within the meaning of the Fuel Use Act. The Trust believes that the Byron and San Joaquin Projects are coal-capable and thus qualify for exemption from the Fuel Use Act.
(E) State Regulation. State public utility regulatory commissions have broad jurisdiction over Independent Power Projects which are not QFs under PURPA, and which are considered public utilities in many states. 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.
(F) Mobile Power Units. The Units, as temporary on-site units operated by the electricity consumer, are not subject to economic regulation in California or most other jurisdictions. If a Unit were rented by a regulated utility, that utility might be subject to economic regulation but the rental fee for the Unit would probably not be directly regulated. There might be an indirect regulatory effect to the extent that the utility was regulated as to the rental price it would be authorized to pay. Under current conditions in California, this is unlikely.
(ii) Environmental Regulation.
The construction and operation of Independent Power Projects are subject to extensive federal, state and local laws and regulations adopted for the protection of human health and the environment and to regulate land use. The laws and regulations applicable to the Trust and Projects in which it invests primarily involve the discharge of emissions into the water and air and the disposal of waste, but can also include wetlands preservation and noise regulation. These laws and regulations in many cases require a lengthy and complex process of renewing licenses, permits and approvals from federal, state and local agencies. Obtaining necessary approvals regarding the discharge of emissions into the air is critical to the development of a Project and can be time-consuming and difficult. Each Project requires technology and facilities, which comply with federal, state and local requirements, which sometimes result in extensive negotiations with regulatory agencies. Meeting the requirements of each jurisdiction with authority over a Project may require modifications to existing Projects.
The Providence Project operates filtration and condensation equipment for the purpose of removing contaminants from the landfill gas supply. The condensate is further treated and then discharged to a local treatment plant under an NPDES permit. The contaminants removed from the condensate are incinerated at an approved facility. The Trust believes that these discharges and contaminants are being disposed of in compliance with NPDES and other requirements.
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.
The Mobile Power Units, which do not have a fixed location, are subject to differing air quality standards that depend in part on the locations of use, the amount of time and time periods of use and the quantity of pollutants emitted. The Trust believes that the Units as used comply with applicable air quality rules.
(d) Financial Information about Foreign and Domestic Operations and Export Sales.
The Trust has investments in Projects located in California, Massachusetts, New York and Rhode Island and has no foreign operations.
(e) Employees.
The Projects are operated by RPM and accordingly the Trust has no employees. The persons described below at Item 10 - Directors and executive officers of the Managing Shareholder and RPM serve as executive officers of the Trust and have the duties and powers usually applicable to similar officers of a Delaware corporation in carrying out the Trust business.
Item 2.
Item 2. Properties.
Pursuant to the Management Agreement between the Trust and the Managing Shareholder (described at Item 10(c)), the Managing Shareholder provides the Trust with office space at the Managing Shareholder's principal office at The Ridgewood Commons, 947 Linwood Avenue, Ridgewood, New Jersey 07450.
The following table shows the material properties (relating to Projects) owned or leased by the Trust's subsidiaries or partnerships in which the Trust has an interest. The On-site Cogeneration Projects are located on the hosts' sites and generally do not occupy material amounts of space. All of the Projects are described in further detail at Item 1(c)(2).
Approximate Approx- Square Descrip- Ownership Ground imate Footage of tion Interests Lease Acreage Project (Actual of Project Location in Land Expiration of Land or Projected) Project
Byron Byron, Leased 2021 2 28,000 Gas-fired California cogeneration facility
San Joaquin Atwater, Leased 2021 1 25,000 Gas-fired California cogeneration facility
Providence Providence, Leased 2020 4 10,000 Landfill Rhode Island gas-fired generation facility
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 391.8444 Investor Shares of beneficial interest in the Trust in its private placement offering of Investor Shares , which closed on May 31, 1995. There is currently no established public trading market for the Investor Shares. As of the date of this Form 10-K, all such Investor Shares have been issued and are outstanding. There are no outstanding options or warrants to purchase, or securities convertible into, Investor Shares.
Investor Shares are restricted as to transferability under the Declaration. In addition, under federal laws regulating securities the Investor Shares have restrictions on transferability when persons in a control relationship with the Trust hold the Investor Shares. Investors wishing to transfer Shares should also consider the applicability of state securities laws. The Investor Shares have not been and are not expected to be registered under the Securities Act of 1933, as amended (the "1933 Act"), or under any other similar law of any state (except for certain registrations that do not permit free resale) in reliance upon what the Trust believes to be exemptions from the registration requirements contained therein. Because the Investor Shares have not been registered, they are "restricted securities" as defined in Rule 144 under the 1933 Act.
(b) Holders
As of the date of this Form 10-K, there are 833 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, 2003 December 31, 2002 Total distributions to Investors $1,175,538 $ -- Distributions per Investor Share $ 3,000 $ -- Distributions to Managing Shareholder $ 11,874 $ --
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 $7,257,996 $7,848,594 $6,383,067 $9,590,113 $9,735,514 Net income(loss) 1,622,699 (1,356,396)(1,482,487)(2,521,130) 1,091,759 (A) (B) (C) (D) Net assets (shareholders' equity) 14,708,565 14,273,278 15,629,674 17,112,161 21,414,406 Investments in Plant and Equipment(net of deprec.) 5,016,351 6,632,404 7,863,053 8,468,270 11,904,223 Investment in Power Contract(net of amort.) 1,147,840 1,219,580 1,291,320 1,363,060 1,434,800 Tot. Assets 15,199,350 15,589,236 17,480,795 18,919,336 21,255,421 Long-term obligations -- -- 250,000 -- -- Per Share: Revenues 18,523 20,030 16,290 24,474 24,845 Net income(loss) 4,141 (3,462) (3,783) (6,434) 2,786 (A) (B) (C) (D) Net asset value 37,537 36,426 39,887 43,671 54,650 Distributions to Investors 3,000 -- -- 4,500 6,006
(A) Includes writedowns of investments of $143,179 ($365 per Investor Share). (B) Includes writedowns of investments of $579,550 ($1,479 per Investor Share). (C) Includes writedowns of investments of $2,780,083 ($7,095 per Investor Share). (D) Includes $1,581,308 of income from arbitration award ($4,036 per Investor Share)
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 Providence, San Joaquin and Byron Projects are "Qualified Facilities" as defined under the Public Utility Regulatory Policies Act of 1978 and currently sell their electric output to utilities under long-term contracts expiring in 2020. During the term of the contracts, the utilities may or may not attempt to buy out the contracts prior to expiration. At the end of the contracts, the Projects will become merchant plants and may be able to sell the electric output at then current market prices. There can be no assurance that future market prices will be sufficient to allow the Projects to operate profitably.
Additional trends affecting the independent power industry generally are described at Item 1 - Business.
Significant Accounting Policies
The Trust's plant and equipment is recorded at cost and is depreciated over its estimated useful life. The estimate useful lives of the Trust's plant and equipment range from 10 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 $514,000, or 7%, to $7,225,000 in 2003 compared to $7,739,000 in 2002. The decrease is primarily due to the Byron and San Joaquin projects operating on a shorter production schedule during the first half of 2003. As a result of high natural gas prices, the Byron and San Joaquin projects had elected to produce the minimum amount of contracted energy, thereby enabling the projects to sell their residual volume of natural gas under fixed priced purchase contracts at current market prices, resulting in slight profits and reduced wear and tear on the generation equipment. As a partial offset to the decrease previously discussed, revenues from the Trust's on-site cogeneration projects increased $158,000 due to the increase in natural gas prices.
Rental revenue from the Trust's mobile power modules decreased by $76,000 to $33,000 in 2003. The decrease in rental revenue is due the increase in competition and production of newer efficient models.
Gross profit, which represents total revenues reduced by cost of sales, increased by $740,000 to a profit of $259,000 in 2003 from a gross loss of $481,000 in 2002. The increase is a result of the lower fuel expenses due to the shorter production schedule in 2003, offset by the decrease in power generation revenues.
General and administrative expenses increased $4,000, or 2%, to $197,000 in 2003 from $193,000 in 2002.
In 2002, the Trust recovered $107,000 relating to PG&E revenues from prior years, which had been treated as uncollectible due to PG&E's filing for bankruptcy protection. In the current year the Trust incurred $38,000 of bad debt expense.
In 2003, the Trust recorded a write down to the Mobile Power Units of $143,000. In 2002, the Trust recorded a write down to its investments in power generation projects of $580,000. The projects comprising the write down are the Mobile Power Units, $461,000, Ridgewood AES, $67,000, and the On-site Cogeneration Projects, $52,000.
The management fee paid to the Managing Shareholder decreased by $34,000, or 9%, to $357,000 in 2003 from $391,000 reflecting the lower net assets of the Trust.
Loss from operations decreased $1,062,000, to $475,000 in 2003 from $1,537,000 in 2002, primarily due to the increase in gross profit and the decrease in write down in power generation projects in the current year.
Other income, net, increased by $1,917,000, to $2,098,000 in 2003 from $181,000 in 2002. The increase is comprised of $240,000 of proceeds received from the sale of the equipment of one of the idle cogeneration facilities, which had been written off in 2000. The Trust also recorded an unrealized gain of $1,254,000, in the current year,for the increase in the market price of natural gas. In addition, the Trust's equity income in the Providence Project increased $390,000 in 2003 compared to 2002. The increase in equity income from the Providence project can be attributed to the lower revenues recorded in 2002 as a result of the failure of one of the facility's engines. In addition, the project recorded the revenue of $772,000 for the transfer of renewable portfolio standard attributes in 2003 compared to zero in 2002.
The Trust's net income increased $2,979,000, from a loss of $1,356,000 in 2002 to income of $1,623,000 in 2003. The increase is primarily due to decrease in loss from operations in addition to the increase in equity income from the Providence project, the proceeds received from the sale of the equipment of one of the idle cogeneration facilities and the unrealized gain on gas purchase contracts.
The year ended December 31, 2002 compared to the year ended December 31, 2001.
Power generation revenue increased $1,761,000, or 29%, to $7,739,000 in 2002 compared to $5,978,000 in 2001. The increase is primarily due to the Byron and San Joaquin projects operating on their normal schedule in 2002 as compared to 2001 when the plants were idle from February to August due to PG&E's failure to pay the projects for power delivered since December 1, 2000. Rental revenue from the Trust's mobile power modules decreased by $295,000 or 73%, to $109,000 in 2002. The decrease in rental revenue is due to the higher rental volume experienced in 2001, as a result of the California energy crisis.
Gross profit, which represents total revenues reduced by cost of sales, decreased by $319,000 to a gross loss of $481,000 in 2002 from a gross loss of $162,000 in 2001. The increase in gross loss is primarily due to the San Joaquin and Byron projects experiencing greater repair and maintenance costs as well as a higher fuel costs as a result of the plants operating on their normal schedule, as compared to 2001 when the plants were mostly idle.
General and administrative expenses decreased $413,000, or 68%, to $193,000 in 2002 from $606,000 in 2001. The decrease primarily reflects the legal costs associated with the project's dispute with PG&E in 2001.
The $229,000 of bad debt expense in 2001 is associated with the sale of the San Joaquin and Byron project's PG&E receivables to AMROC. In 2002, the Trust recovered $107,000 relating to prior year PG&E revenues.
Write downs to the Trust's investments in power generation projects of $143,000 and $580,000 were recorded in 2003 and 2002, respectively. The write downs were comprised of Mobile Power Units $87,000 (2003) and $461,000 (2002), the On-Site Cogeneration Projects $56,000 (2003) and $52,000 (2002), and Ridgewood AES $67,000 (2002).
The management fee paid to the Managing Shareholder decreased by $101,000, or 21%, to $391,000 in 2002 from $493,000 reflecting the lower net assets of the Trust.
The loss from operations in 2002 remained comparable to 2001.
Other income, net, increased by $128,000, to $136,000 in 2002 from $8,000 in 2001. The increase is primarily due to costs incurred in issuing the "Notice of Solicitation of Consents" to investors in 2001. The Trust's equity income in the Providence Project increased slightly in 2002 compared to 2001 due to the decrease in interest expense as a result of the lower outstanding debt balance on the Providence Project.
The Trust's net loss in 2002 decreased $126,000, or 9%, from $1,482,000 in 2001 to $1,356,000 in 2002. The decrease is primarily due to decrease in general and administrative expenses, offset by the write down of certain power generation investments.
Liquidity and Capital Resources
In 2003, the Trust's operating activities used $168,000 of cash compared to $18,000 in 2002.
Cash generated from investing activities in 2003 and 2002 was $1,022,000 and $10,000. The increase is reflective of the distributions received from the Providence Project in 2003 and proceeds of $266,000 from the sale of the Ridgewood AES Project and one of the mobile power units.
Cash used by financing activities of $1,187,000 in 2003 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 and liens and make guarantees.
In October 2003, the Trust issued through its bank two standby letters of credit, in the amounts of $504,000 and $792,000 to secure the gas purchases for the Byron and San Joaquin projects, respectively. The Trust used the 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 Providence Project has secured long-term debt, without recourse to the Trust, with scheduled principal payments as follows:
2004 $867,223
On February 13, 2004 the Providence Project made a payment of $813,257 to pay off its remaining debt. The final payment consisted of cash and the transfer of the balance in the Providence Projects' debt reserve fund at February 13, 2004.
The Byron and San Joaquin Projects have certain long-term obligations relating to their Power Contracts with PG&E and their Gas Agreements with Coral (See Note 6 of the Consolidated Financial Statements). The Providence Project has certain long-term obligations relating to its Power Contract with NEP, its property lease and its arrangements with its gas supplier. The On-site Cogeneration Projects also have certain long-term obligations with the companies owning the facilities where they are sited. None of these long-term obligations are 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 to 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 $ 46,000 Average interest rate 1.04%
Item 8.
Item 8. Financial Statements and Supplementary Data.
A. Index to Consolidated Financial Statements
Report of Independent Accountants Report of Independent Accountants Consolidated Balance Sheet at December 31, 2003 and 2002 Consolidated Statement of Operations for the three years ended December 31, 2003 Consolidated Statement of Changes in Shareholders' Equity for the three years ended December 31, 2003 Consolidated Statement of Cash Flows for the three years ended December 31, 2003 Notes to Consolidated Financial Statements to
Financial Statements for Ridgewood Providence Power Partners, L.P.
Ridgewood Electric Power Trust III
Consolidated Financial Statements
December 31, 2003, 2002 and 2001
Report of Independent Accountants
Managing Shareholder and Shareholders' Ridgewood Electric Power Trust III
We have audited the accompanying consolidated balance sheet of Ridgewood Electric Power Trust III 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 III 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 III:
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 III 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 III Consolidated Balance Sheets - --------------------------------------------------------------------------------
December 31, ------------------------------ 2003 2002 ------------ ------------ Assets: Cash and cash equivalents .................. $ 46,173 $ 379,894 Restricted cash ............................ -- 100,000 Trade receivables, net ..................... 456,666 554,722 Current portion of note receivable from sale of investment ................. 59,963 -- Assets held for sale ....................... 483,994 -- Current portion unrealized gain on gas purchase contract ................ 559,499 -- Due from affiliates ........................ 860,587 277,083 Other current assets ....................... 103,987 138,369 ------------ ------------ Total current assets ................ 2,570,869 1,450,068
Investment in Ridgewood Providence Power Partners, L.P. ......... 5,669,648 5,717,184
Plant and equipment ........................ 9,326,726 11,086,565 Accumulated depreciation ................... (4,310,375) (4,454,161) ------------ ------------ 5,016,351 6,632,404 ------------ ------------
Electric power sales contracts ............. 1,793,500 1,793,500 Accumulated amortization ................... (645,660) (573,920) ------------ ------------ 1,147,840 1,219,580 ------------ ------------
Note receivable from sale of investment, less current portion ....... 85,536 -- Unrealized gain on gas purchase contract, net of current portion ....... 695,106 -- Other assets ............................... 14,000 570,000 ------------ ------------ 794,642 570,000 ------------ ------------ Total assets ....................... $ 15,199,350 $ 15,589,236 ------------ ------------
Liabilities and Shareholders' Equity: Liabilities: Accounts payable and accrued expenses ...... $ 127,188 $ 691,714 Accrued fuel expense ....................... 200,247 299,627 Due to affiliates .......................... 163,350 324,617 ------------ ------------ Total current liabilities ......... 490,785 1,315,958
Commitments and contingencies .............. -- --
Shareholders' Equity: Shareholders' equity (391.8444 investor shares issued and outstanding) ....................... 14,892,513 14,461,579 Managing shareholder's accumulated deficit (1 management share issued and outstanding) ................. (183,948) (188,301) ------------ ------------ Total shareholders' equity ........ 14,708,565 14,273,278 ------------ ------------ Total liabilities and shareholders' equity ............ $ 15,199,350 $ 15,589,236 ------------ ------------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust III Consolidated Statements of Operations - ------------------------------------------------------------------------------- Year Ended December 31, ----------------------------------------- 2003 2002 2001 ----------- ----------- -----------
Power generation revenue ......... $ 7,224,948 $ 7,739,234 $ 5,978,365 Rental revenue ................... 33,048 109,360 404,702 ----------- ----------- ----------- Total revenue ................. 7,257,996 7,848,594 6,383,067
Cost of sales, including depreciation and amortization of $644,328, $712,386 and $710,204 in 2003, 2002 and 2001 ........... 6,999,253 8,329,348 6,545,145 ----------- ----------- ----------- Gross profit (loss) ............... 258,743 (480,754) (162,078) ----------- ----------- ----------- General and administrative expenses ...................... 196,627 192,936 605,967 Provision for bad debt (recoveries) expense .......... 37,595 (107,045) 229,443 Write down of investments in power generation projects ....................... 143,179 579,550 -- Management fee paid to managing shareholder ............ 356,742 390,743 492,430 ----------- ----------- ----------- Total other operating expenses .......... 734,143 1,056,184 1,327,840 ----------- ----------- ----------- Loss from operations .............. (475,400) (1,536,938) (1,489,918) ----------- ----------- ----------- Other income (expense): Interest income ................ 12,934 25,306 32,337 Interest expense ............... (10,835) (59,844) -- Unrealized gain on gas purchase contracts .................... 1,254,605 -- -- Equity income from Ridgewood Providence Power Partners, L.P. ........ 628,822 239,290 168,919 Other income .................. 240,000 -- -- Other expense ................. (27,427) (24,210) (193,825) ----------- ----------- ----------- Total other income (expense), net ............ 2,098,099 180,542 7,431 ----------- ----------- ----------- Net income (loss) ................. $ 1,622,699 $(1,356,396) $(1,482,487) ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust III Consolidated Statement 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 ..... $ 17,272,073 $ (159,912) $ 17,112,161
Net loss for the year ......... (1,467,662) (14,825) (1,482,487) ------------- ----------- ------------- Shareholders' equity (deficit), December 31, 2001 ... 15,804,411 (174,737) 15,629,674
Net loss for the year ......... (1,342,832) (13,564) (1,356,396) ------------- ----------- ------------- Shareholders' equity (deficit), December 31, 2002 ... 14,461,579 (188,301) 14,273,278
Cash distributions .... (1,175,538) (11,874) (1,187,412)
Net income for the year .......... 1,606,472 16,227 1,622,699 ------------- ----------- ------------- Shareholders' equity (deficit), December 31, 2003 ... $ 14,892,513 $ (183,948) $ 14,708,565 ------------- ----------- -------------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust III Consolidated Statements of Cash Flows - --------------------------------------------------------------------------------
Year Ended December 31, ----------------------------------------- 2003 2002 2001 ----------- ----------- ----------- Cash flows from operating activities: Net income (loss) .......... $ 1,622,699 $(1,356,396) $(1,482,487) ----------- ----------- ----------- Adjustments to reconcile net loss to net cash flows from operating activities: Depreciation and amortization ............ 644,328 712,386 710,204 Provision for doubtful accounts ......... 37,595 -- -- Writedown of investments in power generation projects 143,179 579,550 -- Equity in earnings from unconsolidated Ridgewood Providence Power Partners L.P. ..... (628,822) (239,290) (168,919) Unrealized gain on gas purchase contract.......... (1,254,605) -- -- Changes in assets and liabilities: Decrease (increase) restricted cash ........ 100,000 197,430 (297,430) Increase (decrease) in trade receivables ..... (13,933) 207,672 1,217,945 Decrease (increase) in other current assets . 34,382 (60,866) 121,897 Decrease (increase) in other assets ..... 556,000 (14,000) (556,000) (Decrease) increase in accounts payable and accrued expenses ............... (564,526) (213,812) 88,100 Decrease in accrued fuel expense ............ (99,380) (154,873) (305,092) Increase (decrease) in due to affiliates, net (744,771) 573,968 (550,342) (Decrease) increase in other liabilities ... -- (250,000) 250,000 ----------- ----------- ----------- Total adjustments ...... (1,790,553) 1,338,165 1,120,547 ----------- ----------- ----------- Net cash used in operating activities ... (167,854) (18,231) (361,940) ----------- ----------- ----------- Cash flows from investing activities: Cash distribution from Ridgewood Providence Power Partners L.P. ...... 676,357 -- 356,732 Proceeds from sale of investment, net ....... 266,292 -- -- Proceeds from note receivable ........ 78,895 -- -- Reimbursement (payment) of capital expenditures ... -- 10,453 (33,247) ----------- ----------- ----------- Net cash provided by investing activities 1,021,545 10,453 323,485 ----------- ----------- ----------- Cash flows from financing activities: Cash distributions to shareholders ......... (1,187,412) -- -- ----------- ----------- ----------- Net cash used in financing activities . (1,187,412) -- -- ----------- ----------- ----------- Net decrease in cash and cash equivalents ......... (333,721) (7,778) (38,455) Cash and cash equivalents, beginning of year ........... 379,894 387,672 426,127 ----------- ----------- ----------- Cash and cash equivalents, end of year ................. $ 46,173 $ 379,894 $ 387,672 ----------- ----------- -----------
See accompanying notes to the consolidated financial statements.
Ridgewood Electric Power Trust III Notes to Consolidated Financial Statements - --------------------------------------------------------------------------------
1. Organization and Purpose
Nature of Business Ridgewood Electric Power Trust III (the "Trust") was formed as a Delaware business trust on December 6, 1993. The managing shareholder of the Trust is Ridgewood Renewable Power LLC (formerly Ridgewood Power Corporation). The Trust began offering shares on January 3, 1994. The Trust commenced operations on April 16, 1994 and discontinued its offering of shares on May 31, 1995.
The Trust has been organized to invest in independent power generation facilities and in the development of these facilities. These independent power generation facilities include cogeneration facilities, which produce both electricity and thermal energy, and other power plants that use various fuel sources (except nuclear). The power plants sell electricity and, in some cases, thermal energy to utilities and industrial users under long-term contracts.
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 16, 1994, the Trust elected to be treated as a "business development company" ("BDC") under the Investment Company Act of 1940 ("the 1940 Act") and registered its shares under the Securities Exchange Act of 1934.
In November 2001, through a proxy solicitation the Trust requested investor consent to end the BDC status. On December 18, 2001, the consents were tabulated and more than 50% of the investor shares consented to the elimination of the BDC status. Accordingly, the Trust is no longer an investment company under the 1940 Act.
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 $1,254,605 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.
Trade receivables Trade receivables are recorded at invoice price and do not bear interest. An allowance for bad debt expense of $37,595 and $0 in at December 31, 2003 and 2002, respectively, 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 10 to 20 years with a weighted average of 18 years at December 31, 2003 and 2002. During 2003, 2002 and 2001, the Trust recorded depreciation expense of $572,588, $640,646 and $638,464, respectively.
Electrical Power Sales Contracts A portion of the purchase price of the JRW Associates L.P. and Byron Power Partners, L.P. were assigned to electric power sales contracts and are being amortized over the lives of the contracts (25 years) on a straight-line basis. The electric power sales contracts are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. During 2003, 2002 and 2001, the Trust recorded amortization expense of $71,740 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 contracts. 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. Rental revenue and interest income are recorded when earned and dividend income is recorded when declared.
Significant Customers and Supplier During 2003, 2002 and 2001, the Trust's largest customer, Pacific Gas and Electric Company ("PG&E"), accounted for 72%, 75% and 53%, respectively of total revenues. During 2003, 2002 and 2001, the Trust's second largest customer accounted for 18%, 12% and 17%, respectively of total revenues. In early 2001, PG&E experienced severe financial difficulty, see Note 8 for additional discussion. During 2003, 2002 and 2001, the Trust purchased 100% of the San Joaquin and Byron 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 $20,170,582 and $21,374,328, respectively.
Supplemental cash flow information Total interest paid during the years ended December 31, 2003, 2002 and 2001 was $10,835, $59,844 and $0, respectively.
In conjunction with the sale of Ridgewood AES in March 2003, accounts receivable of $74,344 was converted to a note receivable. In the fourth quarter of 2003, the Trust recorded $483,994 in Assets held for sale. Accordingly, the Trust reduced Plant and equipment $483,994.
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
JRW Associates, L.P. (known as the San Joaquin Project) On January 17, 1995, the Trust acquired 100% of the existing partnership interests of JRW Associates, L.P., which owns and operates an 8.5 megawatt electric cogeneration facility, located in Atwater, California. The aggregate purchase price was $4,898,987 including transaction costs.
The acquisition of the San Joaquin Project was accounted for as a purchase and the results of operations of the San Joaquin 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, $1,374,000 was allocated to the Electric Power Sales Contract and is being amortized over the life of the contract (25 years). See Note 8 - Pacific Gas and Electric Company Financial Crisis, for developments affecting the Byron and San Joaquin Projects.
Byron Power Partners, L.P. (known as the Byron Project) In January 1995, the Trust caused the formation of Byron Power Partners, L.P. in which the Trust owns 100% of the partnership interests. On January 17, 1995, Byron Power Partners, L.P. acquired a 5.7 megawatt electric cogeneration facility, located in Byron, California. The aggregate purchase price was $2,508,847 including transaction costs.
The acquisition of the Byron Project was accounted for as a purchase and the results of operations of the Byron 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, $419,500 was allocated to the Electric Power Sales Contract and is being amortized over the life of the contract (25 years). See Note 8 - Pacific Gas and Electric Company Financial Crisis, for developments affecting the Byron and San Joaquin Projects.
Ridgewood Providence Power Partners, L.P. (known as the Providence Project) In 1996, Ridgewood Providence Power Partners, L.P. was formed as a Delaware limited partnership ("Providence Power") which acquired a 12.3 megawatt capacity electrical generating station, located at the Central Landfill in Johnston, Rhode Island (the "Providence Project"). In 1997, the capacity was increased to 13.8 megawatts. The Trust invested $7,132,860 in return for a 35.7% limited partnership interest in Providence Power and its general partner.
The Providence Project is fueled by methane gas produced and collected from the landfill. The electricity generated is sold to New England Power Corporation under a long-term contract. The remaining 64.3% of Ridgewood Power is owned by Ridgewood Electric Power Trust IV ("Trust IV"), whose managing partner is also Ridgewood Renewable Power LLC.
The Trust's investment in the Providence Project is accounted for under the equity method of accounting. The Trust's equity in the earnings of the Providence Project has been included in the consolidated financial statements since acquisition.
Summarized financial information for Ridgewood Providence Power Partners, L.P. is as follows:
Balance Sheet As of December 31, 2003 2002 ----------- -----------
Current assets ............. $ 2,683,947 $ 1,827,155 Other non-current assets ... 15,084,289 17,088,980 ----------- ----------- Total assets ............... $17,768,236 $18,916,135 ----------- -----------
Current liabilities ........ $ 1,886,867 $ 2,034,392 Long-term debt ............. -- 867,223 ----------- ----------- Total liabilities and equity $17,768,236 $18,916,135 ----------- ----------- Trust share ................ $ 5,669,648 $ 5,717,184 ----------- -----------
Ridgewood Electric Power Trust III Notes to Consolidated Financial Statements - --------------------------------------------------------------------------------
Statements of Operations
For the Year Ended December 31, ------------------------------------ 2003 2002 2001 ---------- ---------- ----------
Revenue .......... $8,552,957 $7,344,120 $7,472,308 ---------- ---------- ---------- Cost of sales .... 6,023,645 5,885,503 5,840,911 Other expenses, net .......... 767,905 788,338 1,221,061 ---------- ---------- ---------- Total expenses ... 6,791,550 6,673,841 7,061,972 ---------- ---------- ---------- Net income ....... $1,761,407 $ 670,279 $ 410,336 ---------- ---------- ----------
Trust share ...... $ 628,822 $ 239,290 $ 168,919 ---------- ---------- ----------
Ridgewood Mobile Power III, LLC (a wholly owned subsidiary) Effective August 1999, the Trust acquired five Caterpillar mobile power modules with a total capacity of 4.2 megawatts for $1,695,558. These modules are rented to domestic and international customers. As per an agreement with Hawthorne Power Systems ("Hawthorne"), the Trust pays Hawthorne, a California company that maintains a large fleet of similar rental modules, a fee of 20% of gross rental revenues to arrange and administer the rental of the units. The revenue from these modules is included as rental revenue and Hawthorne's fee is included in cost of sales in the Consolidated Statement of Operations.
Due to the increase in competition and production of newer efficient models, the Trust experienced a decrease in rental revenue for the second consecutive year. As a result of the change in these market conditions, the forecasted revenues for the mobile power modules are not expected to be enough to recover the units' book value. In 2003 and 2002, the Trust recorded writedowns of $87,465 and $460,697, respectively, to reflect the units fair market value. The writedowns have been presented as a separate line item under other operating expenses in the Consolidated Statements of Operations.
In the third quarter of 2003, the Trust decided to make its mobile power modules available for sale. Shortly after making the mobile power modules available for sale, the Trust sold one module for $171,000. The remaining net book value of $483,994, as of December 31, 2003, is reflected as Assets held for sale on the accompanying Consolidated Balance Sheet.
Ridgewood AES Power Partners, LLC (known as Ridgewood AES) In 1997, the Trust formed Ridgewood AES Power Partners, LLC and entered into an agreement with AES-NJ Cogen, Inc. (AES-NJ) to invest in five co-generation facilities operated by AES-NJ. The facilities are all located in New York.
In March 2003, the Trust, sold 100% of its ownership interest in Ridgewood AES to AES-NJ. The acquisition agreement provides for the sale of 100% of the Trust's ownership in Ridgewood AES in return for $100,000 cash, a $150,000 interest bearing promissory note ("promissory note") and a $74,394 interest free note ("interest free note"). The promissory note bears interest at a rate of 10% per annum, and will be repaid monthly over a four year term. The interest free note will be repaid over a six month term. Both notes are guaranteed by AES-NJ.
In 2002, the Trust recorded a writedown of $66,783 to reflect the projects fair market value as determined by the terms of the sale agreement. The writedown has been presented as a separate line item under other operating expenses in the Consolidated Statements of Operations. The sale of Ridgewood AES has not been disclosed as a discontinued operation due to the immateriality of the project's operating results.
Ridgewood El Segundo, LLC (known as the El Segundo Project) In April 1998, the Trust purchased an on-site cogeneration facility located near one of its existing on-site cogeneration facilities in Los Angeles, California. The total purchase price was approximately $590,733, including the payment of liabilities that encumbered the project. During 2000, the Trust analyzed the carrying value of the El Segundo Project assets using an estimated undiscounted cash flow analysis. Using this analysis, an impairment loss was recorded during 2000 in the amount of $524,054, bringing the book value of the project to zero. In the third quarter of 2003, the project's power generation agreement with its host expired.
On-site Cogeneration Projects In 1995, the Trust acquired a portfolio of 35 projects from affiliates of Eastern Utilities Associates ("EUA"), which sell electricity and thermal energy to industrial and commercial customers. The projects were held in eight limited partnerships of which the Trust is the sole limited partner and is the sole owner of each of the general partners. In the aggregate, the projects had 13.7 megawatts of base load and 5.7 megawatts of backup and standby capacity. The Trust paid a total of $11,300,000 for the projects and invested additional amounts for capital repairs and improvements and for working capital. All the projects were gas-fired cogeneration projects, located in California, Connecticut, Massachusetts, Rhode Island or New York. Their energy service agreements had terms expiring between September 1996 and 2011. The acquisition of the projects was accounted for as a purchase and the results of operations of the projects have been included in the Trust's consolidated financial statements since the acquisition date.
The Trust has shut down the majority of the projects and as a result recorded writedowns of $52,070 in 2002, and $10,764,642 in the years prior to 2001. During 2003, the Trust recorded an additional writedown of $55,714 to adjust the carrying value of the projects to reflect their current fair market value. The writedown has been presented as a separate line item under other operating expenses in the Consolidated Statements of Operations. Two of the projects are still operated by the Trust with a total base load of 2 megawatts.
4. Transactions With Managing Shareholder And Affiliates
The Trust entered into a management agreement with the managing shareholder, under which the managing shareholder renders certain management, administrative and advisory services and provides office space and other facilities to the Trust. As compensation to the managing shareholder, the Trust pays the managing shareholder an annual management fee equal to 2.5% 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 $356,742, $390,743 and $492,430, 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 14% 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 paid through December 31, 2003.
The managing shareholder owns one investor share of the Trust with a cost of $84,000. The Trust granted the managing shareholder a single Management Share representing the managing shareholder's management rights and rights to distributions of cash flow.
Effective from January 1, 1996, 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 projects at its cost for these services and for the allocable amount of certain overhead items. Allocations of costs are on the basis of identifiable direct costs, time records or in proportion to amounts invested in projects managed by Ridgewood Management. During the year ended December 31, 2003, 2002 and 2001, Ridgewood Management charged the following to the projects based on proportionate amounts invested:
For the Year Ended December 31, ------------------------------- 2003 2002 2001 --------- --------- --------- JRW Associates, L.P. ............ $120,180 $132,732 $152,098 Byron Power Partners, L.P. ...... 71,174 78,510 89,966 Ridgewood Providence Power Partners, L.P. ..... 451,626 570,159 538,262 Ridgewood El Segundo LLC ........ 14,015 15,029 17,223 On-site Cogeneration Projects: Ridgewood/Mass PPLP ........... 3,609 4,367 6,658 Ridgewood/Elmsford PPLP ....... 32,215 35,579 40,771 Other On-site Cogeneration Project Partnerships ...... 28,241 33,693 55,354
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 with the other affiliates do not bear interest. At December 31, 2003 and 2002, the Trust had outstanding payables and receivables, with the following affiliates:
As of December 31, Due To Due From ----------------------------------------- 2003 2002 2003 2002 ------------------- ------------------- Ridgewood Management ....... $ -- $ -- $290,184 $226,753 Ridgewood Providence Power Partners, L.P. ..... -- 266,285 570,073 -- Ridgewood Renewable Power .. 107,680 -- -- 50,000 Other affiliates ........... 55,670 58,332 330 330 -------- -------- -------- -------- Total ...................... $163,350 $324,620 $860,587 $277,083 ======== ======== ======== ========
5. 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 October 2003, the Trust issued through its bank two standby letters of credit, in the amounts of $504,000 and $792,000 to secure the gas purchases for the Byron and San Joaquin projects, respectively. The Trust used Ridgewood Renewable Power's credit facility to collateralize the letters of credit.
6. Commitments and Contingencies
The Trust, through certain of its subsidiaries, has two long-term operating ground leases.
Future minimum lease payments as of December 31, 2003 are as follows:
Year Ended December 31, Repayment ------------ --------- 2004 $173,256 2005 173,256 2006 173,256 2007 173,256 2008 173,256 Thereafter 2,136,962 --------- Total $3,003,242 ----------
Rent expense for the years ended December 31, 2003, 2002 and 2001 was $173,256, $172,932 and $172,332, respectively.
The San Joaquin and Byron projects have 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 $2,296,766 2005 3,512,322 2006 2,341,548 --------- Total $8,150,636 ----------
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 San Joaquin and Byron projects. 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 $1,254,605 in accordance with SFAS 149 utilizing re-sale prices committed for and fair value prices for re-sale prices uncommitted for.
7. Fair Value of Financial Instruments
At December 31, 2003 and 2002, the carrying value of the Trust's cash and cash equivalents, trade receivables, accounts payable and accrued expenses approximates their fair value. The fair value of the letters of credit does not differ materially from its carrying value.
8. 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 San Joaquin and Byron Projects in December 2000 and January 2001. Accordingly, the San Joaquin and Byron Projects were unable to pay their 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 crisis and its inability to pay, the San Joaquin and Byron Projects were unable on their 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 San Joaquin and Byron Projects. Many qualified facilities under contract with PG&E suffered the same fate and were 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 San Joaquin and Byron Projects entered into an agreement with a financial institution whereby they sold, irrevocably and without recourse, their undivided interest in all eligible trade accounts receivables for December 2000 and January 2001. Costs associated with the sale of receivables of $229,443 for 2001, primarily related to the discount and loss on sale, is included in provision for bad debt expense in the Consolidated Statements of Operations.
In August 2001, PG&E and the San Joaquin and Byron Projects entered into amendments to the electric power sales contracts 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 San Joaquin and Byron Projects entered into five year fixed price natural gas supply agreements with Coral Energy Services, Inc. ("Coral"), a subsidiary of Shell Oil. In addition to the letters of credit discussed in Note 5 above, the gas supply agreements required the San Joaquin and Byron Projects to maintain a deposit of $556,000 with Coral which is reflected as other assets in the December 31, 2002 Consolidated Balance Sheet. In the fourth quarter of 2003, upon the amending and extension of the letters of credit, Coral returned the Trust's deposit.
In the second half of 2001, the previous natural gas supplier made demands for payment of the arrears owed by the San Joaquin and Byron Projects. In December 2001, the San Joaquin and Byron Projects and the natural gas supplier executed a settlement agreement. Pursuant to the settlement agreement, the Byron and San Joaquin Projects were required to pay the natural gas supplier an upfront payment against the arrearage and the remainder to be paid over the next two years at 8% interest rate per annum. The entire balance was required to be discharged no later than the end of July 2003. The Trust has reflected the $250,000 due in 2003 as a current liability in the December 31, 2002 Consolidated Balance Sheet. In 2003, in accordance with the settlement agreement, the Trust made the final scheduled payment.
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 ............... $ 5,245,931 $ 5,917,877 $ 3,363,789 Depreciation and amortization ........ 426,269 428,036 426,954 Operating income (loss) 246,685 (470,425) (1,283,347) Total assets .......... 7,096,367 6,812,337 7,387,797 Capital expenditures .. -- (10,453) 33,247
Retail ----------------------------------------- 2003 2002 2001 ----------- ------------ ----------- Revenue ............... $ 2,012,065 $ 1,930,720 $ 3,019,278 Depreciation and amortization ........ 218,059 284,350 283,250 Operating income (loss) (10,597) (168,694) 512,084 Total assets .......... 1,522,975 2,291,340 3,200,827 Capital expenditures .. -- -- --
Corporate ----------------------------------------- 2003 2002 2001 ----------- ------------ ----------- Revenue ............... $ -- $ -- $ -- Depreciation and amortization ........ -- -- -- Operating loss ........ (711,488) (897,819) (718,655) Total assets .......... 6,483,254 6,485,559 6,892,171 Capital expenditures .. -- -- --
Total ----------------------------------------- 2003 2002 2001 ----------- ------------ ----------- Revenue ............... $ 7,257,996 $ 7,848,597 $ 6,383,067 Depreciation and amortization ........ 644,328 712,386 710,204 Operating loss ........ (475,400) (1,536,938) (1,489,918) Total assets .......... 15,102,596 15,589,236 17,480,795 Capital expenditures .. -- (10,453) 33,247
10. Renewable Attribute Revenue
In 1997, Massachusetts enacted the Electric Restructuring Act of 1997 (the "Restructuring Act"). Among other things, the Restructuring Act requires that all retail electricity suppliers in Massachusetts (i.e. those entities supplying electric energy to retail end-use customers in Massachusetts) purchase a minimum percentage of their electricity supplies from qualified new renewable generation units powered by one of several renewable fuels, such as solar, biomass or landfill. Beginning in 2003, each such retail supplier must obtain at least one (1%) percent of its supply from qualified new renewable generation units. Each year thereafter, the requirement increases one-half of one percentage point until 2009, when the requirement equals four (4%) percent of each retail supplier's sales in that year. Subsequent to 2009, the increase in the percentage requirement will be determined and set by the DOER.
On January 17, 2003, the Providence Project received a "Statement of Qualification" from the Massachusetts Division of Energy Resources ("DOER") pursuant to the renewable portfolio standards ("RPS") adopted by Massachusetts. Since the Providence Project has become qualified, it is able to sell to retail electric suppliers the RPS Attributes associated with its electrical energy. Retail electric suppliers need to purchase RPS Attributes associated with renewable energy and not necessarily the energy itself. Thus, electrical energy and RPS Attributes are separable products and need not be sold or purchased as a bundled product. Retail electric suppliers in Massachusetts will then use the purchase of such RPS Attributes to demonstrate compliance with the Restructuring Act and RPS Regulations.
For the year ended December 31, 2003, the Providence Project recorded Renewable attribute revenue totaling $772,370.
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 .............. $ 1,647,000 $ 1,930,000 $ 2,366,000 $ 1,315,000 Income (loss) from operations .......... (354,000) 256,000 329,000 (706,000) Net income (loss) .... 93,000 334,000 1,127,000 69,000
-------------------------------------------------------- First Second Third Fourth Quarte Quarter Quarter Quarter ----------- ----------- ----------- ------------ Revenue ............. $ 1,659,000 $ 2,199,000 $ 2,390,000 $ 1,601,000 Income (loss) from operations ......... (470,000) (315,000) 265,000 (1,017,000) Net income (loss) ... (495,000) (301,000) 286,000 (846,000)
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 Ridgewood Power. 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. For convenience, the remainder of this Memorandum will discuss each limited liability company and its corporate predecessor as a single entity.
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 18 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 LLC ("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 four privately offered venture capital funds (the Ridgewood Capital Venture Partners and Ridgewood Capital Venture Partners II 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, with primary responsibility for marketing and acquisitions. 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, has been Senior Vice President and General Counsel of the Managing Shareholder, RPM, 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, and PPL Resources, Inc., where he specialized in non-utility generation projects, independent power and power marketing transactions. Mr. Gulino also has experience with the electric and natural gas purchasing of industrial organizations, having worked as in-house counsel for Alumax, Inc. (now part of Alcoa) where he was responsible for, among other things, Alumax's electric and natural gas purchasing program. Mr. Gulino is a member of the New Jersey State Bar and Pennsylvania State Bar. He is a graduate of Fairleigh Dickinson University and Rutgers University School of Law - Newark.
Christopher I. Naunton, 39, has been the Vice President and Chief Financial Officer of the Managing Shareholder, RPM, the Trust, the 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 termination at any time on 60 days' prior notice by a majority in interest of the Investors or the Managing Shareholder. The Management Agreement is subject to amendment by the parties with the approval of a majority in interest of the Investors.
(d) Executive Officers of the Trust.
Pursuant to the Declaration, the Managing Shareholder has appointed officers of the Trust to act on behalf of the Trust and sign documents on behalf of the Trust as authorized by the Managing Shareholder. Mr. Swanson has been named the President of the Trust and the other 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.
The Corporate Trustee of the Trust is Christiana Bank & Trust Company ("Christiana"). Legal title to Trust Property is now and in the future will be in the name of the Trust. Christiana 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 assumed day-to-day management responsibility for the San Joaquin, Byron, On- site Cogeneration and Providence Projects in 1996. 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.
Initially, the Managing Shareholder does not anticipate charging RPM for the full amount of rent, utility supplies and office expenses allocable to RPM. As a result, both initially and on an ongoing basis the Managing Shareholder believes that 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 will be made either on the basis of identifiable direct costs, time records or in proportion to each program's investments in Projects managed by RPM; and allocations will be 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 will not have the power to act in the Trust's name or to bind the Trust, which will be exercised by the Managing Shareholder or the Trust's officers, although it may be authorized to act on behalf of the subsidiaries that own Projects.
The Operation Agreement does not have a fixed term and is terminable by 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 for the Managing Shareholder as set forth above.
(h). Code of Ethics.
The Managing Shareholder has adopted a Code of Ethics in March 2004 for itself, the Trust, Other Power Trusts, Ridgewood LLCs and affiliates. The Code of Ethics is attached hereto as Exhibit 10F.
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 391.8444 Investor Shares (approximately $39.2 million of gross proceeds) of beneficial interest in the Trust pursuant to a private placement offering under Rule 506 of Regulation D under the Securities Act. The offering closed on May 31, 1995. Further details concerning the offering are set forth above at Item 1 -- Business.
The Managing Shareholder purchased for cash of $84,000 in the offering one full Investor Share. By virtue of its purchase of an Investor Share, the Managing Shareholder is entitled to the same ratable interest in the Trust as all other purchasers of Investor Shares. No other executive officers of the Trust acquired Investor Shares in the Trust's offering.
The Managing Shareholder was issued one Management Share in the Trust representing the beneficial interests and management rights of the Managing Shareholder in its capacity as the Managing Shareholder (excluding its interest in the Trust attributable to Investor Shares it acquired in the offering). The management rights of the Managing Shareholder are described in further detail above at Item 1 -- Business and in Item 10 Directors and Executive Officers of the Registrant. Its beneficial interest in cash distributions of the Trust and its allocable share of the Trust's net profits and net losses and other items attributable to the Management Share are described in further detail below at Item 13
Item 13 -- Certain Relationships and Related Transactions.
Item 13. Certain Relationships and Related Transactions.
The Declaration provides that cash flow of the Trust, less reasonable reserves which the Trust deems necessary to cover anticipated Trust expenses, is to be distributed to the Investors and the Managing Shareholder (collectively, the "Shareholders"), from time to time as the Trust deems appropriate. Prior to Payout (the point at which Investors have received cumulative distributions equal to the amount of their capital contributions), 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 a cumulative amount equal to 14% per year of their total capital contributions (a "14% Priority Distribution"), and thereafter all remaining distributions from the Trust during the year, other than distributions of the revenues from dispositions of Trust Property, are to be allocated 80% to Investors and 20% to the Managing Shareholder. Revenues from dispositions of Trust Property are to be distributed 99% to Investors and 1% to the Managing Shareholder until Payout. In all cases, after Payout, Investors are to be allocated 80% of all distributions and the Managing Shareholder 20%.
For any fiscal period, the Trust's net profits, if any, other than those derived from dispositions of Trust Property, are allocated 99% to the Investors and 1% to the Managing Shareholder until the profits so allocated offset (1) the aggregate 14% Priority Distribution to all Investors and (2) any net losses from prior periods that had been allocated to the Shareholders. Any remaining net profits, other than those derived from dispositions of Trust Property, are allocated 80% to the Investors and 20% to the Managing Shareholder. If the Trust realizes net losses for the period, the losses are allocated 80% to the Investors and 20% to the Managing Shareholder until the losses so allocated offset any net profits from prior periods allocated to the Shareholders. Any remaining net losses are allocated 99% to the Investors and 1% to the Managing Shareholder. Revenues from dispositions of Trust Property are allocated in the same manner as distributions from such dispositions. Amounts allocated to the Investors are apportioned among them in proportion to their capital contributions.
On liquidation of the Trust, the remaining assets of the Trust after discharge of its obligations, including any loans owed by the Trust to the Shareholders, will be distributed, first, 99% to the Investors and the remaining 1% to the Managing Shareholder, until Payout, and any remainder will be distributed to the Shareholders in proportion to their capital accounts.
The Trust made distributions in 2003 as stated at Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters. The Trust and its subsidiaries paid fees or reimbursements to the Managing Shareholder and its affiliates as follows:
2003 2002 2001 2000 1999 Managing $356,742 $390,743 $492,430 $592,664 $594,576 Shareholder Cost Reimburse- $6,589,814 $7,893,953 $6,634,733 $7,440,297 $8,920,930 ments RPM
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. 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, 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 $35,000. 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 $16,000 and $41,000, 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 $38,000. 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 of Registrant's Registration Statement filed with the Commission on February 15, 1994.
3B. Declaration of Trust of the Registrant is incorporated by reference to Exhibit 3B of Registrant's Registration Statement filed with the Commission on February 19, 1994.
10A. Management Agreement dated as of January 3, 1994 between the Registrant and Ridgewood Power Corporation is incorporated by reference to Exhibit 10A of Registrant's Registration Statement filed with the Commission on February 15, 1994.
10B. Acquisition Agreement dated as of January 9, 1995 among JRW Cogen, Inc., and NorCal Cogen, Inc., as Sellers, and RW Central Valley, Inc., and Ridgewood Electric Power Trust III, as Purchasers, is incorporated by reference to Exhibit 2(i) to Registrant's Form 8K filed with the Commission on February 16, 1995.
10C. Agreement of Merger dated as of January 9, 1995 among Altamont Cogeneration Corporation, NorCal Altamont, Inc., and Byron Power Partners, L.P. is incorporated by reference to Exhibit 2(ii) to Registrant's Form 8K filed with the Commission on February 16, 1995.
10.D Asset Acquisition Agreement by and among Northeast Landfill Power Joint Venture, Northeast Landfill Power Company, Johnson Natural Power Corporation and Ridgewood Providence Power Partners, L.P. , is incorporated by reference to Exhibit 2 of the Registrant's Current Report on Form 8-K filed with the Commission on May 2, 1996.
10.E Operation Agreement, dated as of April 16, 1996, among Ridgewood/Providence Corporation, Ridgewood/Providence Power Partners, L.P. and Ridgewood Power Management Corporation. Incorporated by reference to Exhibit 10E to Registrant's Annual Report on Form 10-K for the year ended December 31, 1996.
10.F. 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 III (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 III ("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 III ("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