10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

x     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

o     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 For the transition period from ________ to _______

Commission file number:  0-23432

RIDGEWOOD ELECTRIC POWER TRUST III

(Exact Name of Registrant as Specified in Its Charter)

Delaware	22-3264565
(State or Other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification Number)

1314 King Street, Wilmington, DE 19801

(Address of Principal Executive Offices, including Zip Code)

(302) 888-7444

(Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Investor Shares of Beneficial Interest

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  o    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.      Yes o     No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o    No  x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  o  Accelerated filer o   Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.    Yes  o   No  x

There is no market for the Investor Shares. The number of Investor Shares outstanding at September 30, 2007 was 391.8444.

EXPLANATORY NOTE

This Annual Report on Form 10-K for the year ended December 31, 2005 (this “Form 10-K”) being filed by Ridgewood Electric Power Trust III (the “Trust”) contains complete audited financial statements of the Trust for the years ended December 31, 2005, 2004 and 2003 and interim financial information presented for each quarter during those periods. The financial information for the year ended December 31, 2003 and for the quarterly periods ended March 31, 2003, June 30, 2003, September 30, 2003, March 31, 2004, June 30, 2004 and September 30, 2004 is presented on a restated basis. This Form 10-K is being filed by the Trust in lieu of the Trust separately filing with the United States Securities and Exchange Commission (the “SEC”) (i) its delinquent Annual Reports on Form 10-K for the years ended December 31, 2005 and 2004,  and the Quarterly Reports on Form 10-Q for each of the quarterly periods during the year ended December 31, 2005, and (ii) restatements of its Annual Report on Form 10-K and Quarterly Reports on Form 10-Q filed with the SEC for periods commencing on or after January 1, 2003 (the foregoing quarterly and annual reports of the Trust herein collectively are referred to as the “Reports for the Historical Periods” and each such report is referred to herein as a “Report for a Historical Period”). This Form 10-K does not contain financial information, or discussion in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for periods ended prior to January 1, 2003.

This Form 10-K includes the financial and other disclosures required to be made by the Trust in each of the Reports for the Historical Periods. To the extent that a Report for a Historical Period was previously filed with the SEC, the information contained in this Form 10-K amends, restates and supersedes in its entirety the information contained in such report for periods commencing on or after January 1, 2003. Except as noted above, this Form 10-K also includes the financial and other information that would have otherwise been required to have been provided in the Trust’s delinquent Annual Reports on Form 10-K for the years ended December 31, 2004 and 2005 and quarterly reports on Form 10-Q for the periods ended March 31, 2005, June 30, 2005 and September 30, 2005, had such reports been filed with the SEC.

As previously disclosed in its Form 8-K filed October 11, 2007, (i) the consolidated financial statements of the Trust included in the Trust’s Quarterly Reports on Form 10-Q and the Trust’s Annual Report on Form 10-K for each of the periods beginning with the three-month period ended March 31, 2003 and continuing through the three and nine-month periods ended September 30, 2004 filed with the SEC (the “Previously Issued Financial Statements”) should no longer be relied upon and (ii) the Previously Issued Financial Statements should be restated to conform to generally accepted accounting principles (“GAAP”). The determination to restate these financial statements and selected financial data was made by the Trust and Ridgewood Renewable Power LLC, the Managing Shareholder of the Trust (the “Managing Shareholder”), as a result of the identification of accounting errors as more fully described in Note 2 to the Consolidated Financial Statements. The Trust has discussed these matters with its independent registered public accounting firm. As these errors were material to the Trust’s consolidated financial statements and selected financial information filed with the SEC, the Trust has concluded that it must restate the consolidated financial statements of such prior periods to correct misstatements therein.

FORM 10-K

TABLE OF CONTENTS

PART I
Item 1.	Business	1
Item 1A.	Risk Factors	6
Item 1B.	Unresolved Staff Comments	10
Item 2.	Properties	10
Item 3.	Legal Proceedings	10
Item 4.	Submission of Matters to a Vote of Security Holders	10
PART II
Item 5.	Market for Registrant’s Common Equity, Related Security Holder Matters and
	Issuer Purchases of Equity Securities	10
Item 6.	Selected Financial Data	10
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	22
Item 8.	Financial Statements and Supplementary Data	22
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	22
Item 9A.	Controls and Procedures	24
Item 9B.	Other Information; Unregistered Sales of Equity Securities and Use of Proceeds;
	Defaults Upon Senior Securities	25
PART III
Item 10.	Directors and Executive Officers of the Registrant	25
Item 11.	Executive Compensation	27
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Security Holder Matters	27
Item 13.	Certain Relationships and Related Transactions	27
Item 14.	Principal Accountant Fees and Services	28
PART IV
Item 15.	Exhibits and Financial Statement Schedules	29
SIGNATURES		31

Forward-Looking Statements

Certain statements discussed in Part I, Item 1. “Business”, Part I, Item 3. “Legal Proceedings”, Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.

These forward-looking statements generally relate to the Trust’s plans, objectives and expectations for future events and include statements about the Trust’s expectations, beliefs, plans, objectives, intentions, assumptions and other statements that are not historical facts.  These statements are based upon management’s opinions and estimates as of the date they are made.  Although management believes that the expectations reflected in these forward-looking statements are reasonable, such forward-looking statements are subject to known and unknown risks and uncertainties that may be beyond the Trust’s control, which could cause actual results, performance and achievements to differ materially from the results, performance and achievements projected, expected, expressed or implied by the forward-looking statements. Examples of events that could cause actual results to differ materially from historical results or those anticipated include changes in political and economic conditions, federal or state regulatory structures, government mandates, the ability of customers to pay for energy received, supplies and prices of fuels, operational status of generating plants, mechanical breakdowns, volatility in the price for electric energy, natural gas, or renewable energy.  Additional information concerning the factors that could cause actual results to differ materially from those in the forward-looking statements is contained in Part I, Item 1A. “Risk Factors” and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and elsewhere in this Annual report on Form 10-K.  The Trust undertakes no obligation to publicly revise any forward-looking statements or cautionary factors, except as required by law.

PART I

ITEM 1.  BUSINESS

Overview

The Trust is a Delaware trust formed on December 6, 1993 to primarily make investments in projects and businesses in the energy and infrastructure sectors. Ridgewood Renewable Power LLC (“RRP” or the “Managing Shareholder”), a New Jersey limited liability company, is the Managing Shareholder. As the Managing Shareholder, RRP has direct and exclusive control over the management and operations of the Trust.

The Trust has focused primarily on projects fueled by natural gas and renewable sources of fuel. These projects allow the Trust to develop secure long-term positions in attractive specialty markets for products and services provided by its projects and companies. As of December 31, 2005, the projects in which the Trust then had investments were located in the United States. As of that date, the Trust had investments in a landfill gas-fired electric generating project with total capacity of 13.8 megawatts (“MW”) and in electric cogeneration projects with total capacity of 14.2MW.

The Trust initiated its private placement offering in January 1994 selling whole and fractional investor shares of beneficial interests of $100,000 per share (“Investor Shares”). There is no public market for Investor Shares and one is not likely to develop. In addition, Investor Shares are subject to significant restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Trust’s Declaration of Trust (“Declaration of Trust”) and applicable federal and state securities laws. The offering was concluded in May 1995 and after payment of offering fees, commissions and investment fees, the Trust had $32.9 million available for investments and operating expenses. As of September 30, 2007, the Trust had 391.8444 Investor Shares outstanding, held by 841 shareholders.

Managing Shareholder

RRP, via a predecessor corporation, was founded in 1991 by Robert E. Swanson. As the Managing Shareholder, RRP has direct and exclusive control over the management of the Trust’s operations. With respect to project investment, RRP locates potential projects, conducts appropriate due diligence and negotiates and completes the transactions in which the investments are made by the Trust.

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In addition, RRP performs (or arranges for the performance of) the operation and maintenance of the projects owned by the Trust and the management and administrative services required for Trust operations. Among other services, RRP administers the accounts and handles relations with the shareholders, including tax and other financial information. RRP also provides the Trust with office space, equipment and facilities and other services necessary for its operation.

As compensation for its management services, the Managing Shareholder is entitled to (i) an annual management fee, payable monthly, equal to 2.5% of the prior year net asset value of the Trust and (ii) a 20% interest in the cash distributions made by the Trust in excess of certain threshold amounts expressed in terms of shareholder returns. The Managing Shareholder is also entitled to receive reimbursement from the Trust for operating expenses incurred by the Trust, or on behalf of the Trust and paid by RRP, as the Managing Shareholder. RRP has arranged for administrative functions required to be performed for the Trust to be performed by an affiliate, Ridgewood Power Management LLC (“RPM”), and at RPM’s costs, which costs are reimbursed to RPM by the Trust. RRP also serves as the managing shareholder (or managing member as appropriate) of a number of affiliated Trusts and investment vehicles similar to the Trust and, through RPM, provides services to those entities similar to those provided to the Trust.

Affiliates of RRP act on behalf of a number of investment vehicles in the oil and gas and venture capital sectors in a manner similar to that for which RRP serves on behalf of the Trust.

Business Strategy

The Trust’s primary investment objective is to generate cash flow for distribution to shareholders and capital appreciation from one or more of the acquisition, development, ownership and operation of interests in electricity generation and other infrastructure projects and companies. The Trust generally seeks to invest in projects and companies that provide products or services through a number of small facilities and that offer opportunities for expansion either through increasing production at existing sites or through the establishment of additional sites. These projects often involve development, construction and operating risk but, once established, may be able to effectively “lock-in” the customer (or customers) served by the project, which would prevent competitors from dislodging the Trust’s project. The Trust focuses on markets in which projects can be developed and built quickly and can be standardized as to their design, equipment and construction. By following this strategy, the Trust seeks to take advantage of attractive market opportunities while streamlining the development process and diversifying across a number of projects in order to contain the exposure of the Trust to the risks inherent in such projects. As of December 31, 2005, all of the Trust’s projects are managed by the Managing Shareholder and are either 100% owned by the Trust or owned through investment vehicles that the Trust co-owns with certain affiliated investment Trusts.

Projects and Properties

The following table is a summary of the Trust’s primary investment portfolio as of December 31, 2005 detailing the nature of the business and the portion of the investment owned by the Trust.

Company	Trust Interest	Leased/ Owned1	Purpose	Structure2
San Joaquin Project3	100%	Leased	Electricity generation	Steel building/ concrete slab
Byron Project3	100%	Leased	Electricity generation	Steel building/ concrete slab
Ridgewood Providence4	35.7%	Leased	Electricity generation	Steel building/ concrete slab

¹ Refers to the locations on which the Trust’s projects are located and not the projects themselves.

² Describes the type of structure in which the projects of the Trust are housed.

³ Located in Northern California.

⁴ Co-owned with Ridgewood Electric Power Trust IV (“Trust IV”). The facility is located in Rhode Island.

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San Joaquin Project and Byron Project

In January 1995, the Trust acquired 100% of the existing partnership interests of JRW Associates, L.P., which owned and operated an 8.5MW electric cogeneration facility located in Atwater, California (the “San Joaquin Project”). The aggregate purchase price was $4.9 million, including transaction costs.

In January 1995, the Trust caused the formation of Byron Power Partners, L.P. in which the Trust owns 100% of the partnership interests.  In January 1995, Byron Power Partners, L.P. acquired a 5.7MW electric cogeneration facility located in Byron, California (the “Byron Project”).  The aggregate purchase price was $2.5 million, including transaction costs.

The Byron Project and the San Joaquin Project (collectively the “Norcals”) are fueled by natural gas and sell their electric output to Pacific Gas & Electric Company (“PG&E”) under power contracts that expire in 2020. 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 expires in 2020. Thermal energy from the Byron Project is used to evaporate brine from oil and gas wells under a long-term contract that also expires in 2020.

The Norcal’s contract prices with PG&E 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 natural gas price index; referred to as the Short Run Avoided Cost Methodology ("SRAC").  Effective August 2001, however, the Norcals entered into amendments to its power contracts, which provided for, among other things, that the Norcals would receive a fixed energy payment (as well as the required capacity payment) for a term of five years, until August 2006.  Upon expiration of the amendment, through the remainder of the term of the contract, the SRAC formula contained in the original contract is to be used to determine the energy price paid by PG&E.

The Norcals entered into agreements with Coral Energy Services, Inc. (“Coral”), a subsidiary of Shell Oil, to procure its natural gas fuel at a fixed price through August 2006.  Coral and the Norcals also had master re-sale agreements, which also expired in August 2006.  Such agreement enabled the Norcals to not take delivery of, and to sell back to Coral, certain amounts of natural gas once predetermined prices have been established. During the contract, the Norcals re-sold gas back to Coral.

The plants are operated and maintained by RPM, on an at-cost basis.

Ridgewood Providence

Ridgewood Providence Power Partners, L.P. (“Ridgewood Providence”) was formed in February 1996 as a Delaware limited partnership and in April 1996, Ridgewood Providence purchased substantially all of the net assets of Northeastern Landfill Power Joint Venture for $20.4 million including the assumption of debt. The assets acquired included a 13.8MW electrical generating station and associated gas treatment system, located at the Central Landfill in Johnston, Rhode Island. Ridgewood Providence includes nine reciprocating engine/generator sets, which are fueled by methane gas produced by, and collected from, the landfill. The project has been operating on the site since 1990 and the net electricity generated is sold to New England Power Service Company (“NEP”) under a long-term electricity sales contract. The contract expires in 2020 but becomes a market-rate contract in 2010. The plant is operated and maintained by RPM, on an at-cost basis.

Ridgewood Providence occupies the site and uses the gas from the landfill under the terms of an agreement with the Rhode Island Resource Recovery Corporation (“RIRRC”), a Rhode Island state agency that owns and operates the landfill. Ridgewood Providence subleases a portion of its rights to the landfill gas to Central Gas Limited Partnership (“CGLP”). CGLP operates and maintains a portion of the landfill gas collection system and sells the collected gas to Ridgewood Providence. Ridgewood Providence pays a royalty to RIRRC that is based on its revenue and pays CGLP on a per kilowatt basis. The Ridgewood Providence project qualifies for renewable energy incentives in Massachusetts and Connecticut and a portion of the benefits of these incentives are eligible to be sold to a power marketer under an agreement that continues through 2009.

In December 2002, the Managing Shareholder of the Trust formed Ridgewood Rhode Island Generation LLC (“RRIG”), for the purpose of utilizing the supply of gas from the landfill that is in excess of the quantity that could be used by Ridgewood Providence. The project owned by RRIG reached full operation in October 2005 and has a capacity of 8.5MW. RRIG has rights to gas from the landfill for the purpose of operating the RRIG project. Other than the gas rights granted to RRIG, there is no commercial relationship between RRIG and Ridgewood Providence. The landfill generates significantly more gas than can be utilized by the combined projects of Ridgewood Providence and RRIG.

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On August 1, 2003, Ridgewood Providence entered into an Environmental Attribute Agreement with RIRRC and Ridgewood Gas Services, LLC (“RGS”), an affiliate of Ridgewood Providence that provides management services to RIRRC. Pursuant to the terms of the agreement, Ridgewood Providence is required to pay 15% net revenue royalty to RIRRC and RGS which is derived from the sale of Renewable Portfolio Standards Attributes (“RPS Attributes”) and is the only direct cost of the renewable attribute revenue. The term of the agreement coincides with the Central Landfill lease agreement, which expires in 2020 and provides for an extension of an additional ten years.

On January 17, 2003, Ridgewood Providence received a “Statement of Qualification” from the Massachusetts Division of Energy Resources (“DOER”) pursuant to the renewable portfolio standards adopted by Massachusetts. Since Ridgewood Providence has now 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.

During 2004, Ridgewood Providence became qualified to sell RPS Attributes in Connecticut under a similar RPS program, except that the Connecticut program does not have a “vintage” prohibition, which in Massachusetts disqualifies the amount of a facility’s generation of electric energy measured by its average output during the period 1995 through 1997. Thus, Ridgewood Providence can sell the 86,000 megawatt hours (“MWh”) that are ineligible under Massachusetts standards into the Connecticut market. During 2006, 2005 and 2004, Ridgewood Providence sold its “vintage” RPS Attributes pursuant to agreements with various power marketers.

Similar agreements have committed Ridgewood Providence to sell its 2007 “vintage” RPS Attributes to such designated parties at certain fixed quantities and prices. Pursuant to the terms of the agreement, Ridgewood Providence is only required to deliver the specified RPS Attributes it generates and is not obligated to produce, nor is it subject to penalty if it is unable to produce, contracted quantities.

Ridgewood Providence and the Trust, along with Trust IV and RRIG, are evaluating expanding the generation facilities at the site. If such expansion were to occur, the Trust may make an additional investment in Ridgewood Providence.

Other Investments

Mobile Power Units

In the third quarter of 1999, the Trust purchased, for $1.7 million, five mobile power generating units. Due to the increases in competition and production of newer more efficient generating models, the Trust experienced continued decreases in rental revenue. The Trust decided in 2003 to sell these units; one unit was sold in the fourth quarter of 2003 for proceeds of $171,000 and the remaining units were sold in the second quarter of 2004 for proceeds of $384,000.

On-site Cogeneration Projects

In 1995, the Trust purchased a portfolio of 35 projects from affiliates of Eastern Utilities Associates ("EUA"), which sell electricity and thermal energy to industrial and commercial customers, for an aggregate purchase price of $11.3 million. The Trust then invested an additional $1.4 million for capital improvements. The projects were located in California (18 sites), Connecticut (6 sites), Massachusetts (2 sites), New York (8 sites) and Rhode Island (1 site).  The projects used natural gas fired turbines or reciprocating engines to produce electrical energy and/or heat for industrial uses or air conditioning under a variety of individual customer circumstances. Their energy service agreements had terms expiring between September 1996 and 2011. The Trust shut down all but two of the projects beginning in 2001 through 2003. The remaining projects ceased operations in the fourth quarter of 2006.

In September 1997, the Trust formed a joint partnership, Ridgewood/AES Power Partners, L.P. with AES-NJ Cogen, Inc. (“AES-NJ”) to develop cogeneration projects. During 2003, The Trust sold its interest in the joint partnership for $100,000 cash, a $150,000 interest bearing promissory note ("promissory note"), and a $74,000 interest free note ("interest free note"). The promissory note bore interest at a rate of 10% per annum, and was fully paid monthly over a four year term. The interest free note was repaid over a six month term.

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In 2003, the Trust sold the assets of a project located in Fall River, Massachusetts (“Globe”) for $240,000.

Significant Customers and Supplier

During 2005, 2004 and 2003, the Trust’s largest customer, Pacific Gas and Electric Company, accounted for 82%, 87% and 75%, respectively of total revenues. During 2005, 2004 and 2003, the Trust purchased substantially all of its gas from one supplier, Coral.

Business Segments

Power generation is the only business segment within which the Trust manages and evaluates its operations.

Project Feedstock/Raw Materials

The investments of the Trust each convert a raw material into a finished product and the arrangements for obtaining these raw materials are a key element in the business of the Trust. The cogeneration facilities use natural gas as fuel. Unless contracted for otherwise, the price charged for the gas is based on current market conditions. The landfill facility consists of reciprocating engine generator sets that use methane-containing landfill gas as fuel. Gas is collected from the landfills as it is produced through natural anaerobic digestion of the waste. Ridgewood Providence does not own or operate the landfill but has arrangements with the site owner/operator, which gives the project certain rights, including the right to build the projects, occupy the compounds and use the gas from the landfill. The gas agreement is a long-term agreement running for the expected life of the project and includes provisions for royalty payments from the project to the landfill operator as compensation for the granting of these rights. Royalty payments are calculated as a percent of revenue. The investments of the Trust do not maintain material inventories of raw materials.

Competition

Power generated from the Norcal projects and Ridgewood Providence is sold pursuant to long-term contracts, and as a result, these facilities do not face competition in the sale of its finished product.

Government Incentives and Regulation

Ridgewood Providence qualifies for incentives because of its location and use of renewable fuel.

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 DOER.

In January 17, 2003, Ridgewood Providence received a “Statement of Qualification” from the DOER pursuant to the RPS adopted by Massachusetts. Since Ridgewood Providence has been qualified, it has sold 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 are not required to 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.

During 2004, Ridgewood Providence also became qualified to sell RPS Attributes in Connecticut under a similar RPS program, except that the Connecticut program does not have a “vintage” prohibition, which in Massachusetts disqualifies the amount of a facility’s generation of electric energy measured by its average output during the period 1995 through 1997. Thus, Ridgewood Providence can sell the 86,000 MWh that are ineligible under Massachusetts standards into the Connecticut market.

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Insurance

The Trust has in place, either directly or through investee companies, insurance typical for activities such as those conducted by the Trust. These policies include property and casualty, business interruption and workman’s compensation insurance, which the Trust believes to be appropriate. Certain of the insurance carried by the Trust are required by the lenders of certain investee companies.

Employees

The Trust does not have employees. The activities of the Trust are performed either by employees of the Managing Shareholder, its affiliates or those of the specific investments of the Trust.

Offices

The principal office of the Trust is located at 1314 King Street, Wilmington, Delaware, 19801 and its phone number is 302-888-7444. The Managing Shareholder maintains offices 947 Linwood Avenue, Ridgewood, New Jersey, 07450 and its phone number is 201-447-9000.

Available Information

The Trust’s shares are registered under Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The Trust must therefore comply with, among other things, the periodic reporting requirements of Section 13(a) of the Exchange Act. As a result, the Trust prepares and files annual reports with the SEC on Form 10-K, quarterly reports on Form 10-Q and, from time to time, current reports on Form 8-K. Moreover, the Managing Shareholder maintains a website at http://www.ridgewoodpower.com that contains important information about the Managing Shareholder, including biographies of key management personnel, as well as information about the investments made by the Trust and the other investment programs managed by the Managing Shareholder.

Where You Can Get More Information

The Trust files annual, quarterly and current reports and certain other information with the SEC. Persons may read and copy any documents the Trust files at the SEC’s public reference room at 100 F Street, NE, Washington D.C. 20549. You may obtain information on the operation at the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. A copy of any such filings will be provided free of charge to any shareholder upon written request to the Managing Shareholder at its business address - 947 Linwood Avenue, Ridgewood, New Jersey 07450, ATTN: General Counsel.

Reports to Shareholders

The Trust does not anticipate providing annual reports to shareholders but will make available upon request copies of the Trust’s periodic reports to the SEC on Form 10-K and on Form 10-Q.

ITEM 1A. RISK FACTORS

In addition to the other information set forth elsewhere in this report, you should carefully consider the following factors when evaluating the Trust:

RISKS INHERENT IN THE BUSINESSES OF THE TRUST

The Trust has material weaknesses in its disclosure controls and procedures.

Material weaknesses in disclosure controls and procedures have been identified by management of the Trust. These weaknesses primarily relate to the Trust’s inability to complete its reporting obligations on a timely basis as a result of deficient disclosure controls and procedures. See Item 9A. “Controls and Procedures” in this report. The inability of the Trust to timely report its results could impact the ability of an investor to adequately understand its investment, restrict the Trust’s ability to conduct its activities and subject the Trust to fines and penalties. Upon further review, the Trust may also determine that it has material weaknesses in its internal control over financial reporting.

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The Trust’s Ridgewood Providence business depends on the production of landfill methane from the landfill site on which it operates and access to that gas production.

The electricity production of the Ridgewood Providence project is typically limited by the available amount of landfill methane gas used as fuel by the project. A number of factors influence the amount of landfill methane gas produced by a landfill site including the quantity and makeup of the waste deposited into the site by the landfill operator, the manner and sequence of the waste deposition, the non-waste materials used to support the landfill structure and the amount of liquid in the landfill. A number of factors also influence the ability of the Trust’s personnel to gain access to gas that is being produced by a landfill including the land filling strategy and practices of the landfill site operator. To the extent that these factors limit the production of landfill methane gas or the ability of the project to collect and use that gas, Ridgewood Providence may not achieve profitable output levels.

The Trust’s Ridgewood Providence business is subject to interruption of its business operations. 

The electric generating plant owned by Ridgewood Providence is located on property owned by the landfill from which Ridgewood Providence derives the methane gas to power its plant. If the landfill expands in the direction of the electric generating plant it is possible that the site on which the electric generating plant is located may be included in such expansion. If such an expansion occurs, Ridgewood Providence might have to relocate or abandon the electricity generating plant.  Were this to occur, Ridgewood Providence could face a temporary or permanent loss of the revenues from this plant.

The operations of the Trust have limited capital, limited access to new capital and have obligations to third parties for borrowed money.

The Trust’s investments, but not the Trust itself, have in the past utilized debt financing. Debt financing could increase the variability of results and could increase the financial risk of the Trust. In such cases, the rights of the Trust to the cash flow of the projects would typically be subordinated to the obligations of the projects under the debt facilities, which could limit the Trust’s ability to receive cash distributions from its investments.

The projects of the Trust depend on the near-continuous operation of their equipment. Should the productivity of some or all of this equipment be compromised or should the equipment fail altogether, the Trust would be adversely affected. The Trust may also experience difficulty in hiring qualified operating personnel.

The primary equipment of the Trust is subject to mechanical failure that the Trust may not be able to predict and that can render specific projects inoperable for considerable periods of time. This risk also extends to failures of the electricity grid near the Trust’s projects that could prevent the affected project or projects from delivering its electricity. In addition, the Trust may experience price increases for, or difficulty in obtaining, spare parts for its projects and in identifying and hiring personnel qualified to operate, maintain and repair the specialized equipment that make up parts of its projects.

The projects of the Trust are subject to regulatory changes (including changes in environmental regulations) that could significantly reduce revenues or increase expenses of the Trust.

This area of risk is inherently difficult to predict but could include matters such as emission control changes. Such changes could increase costs at affected projects or prevent certain projects from operating.

Ridgewood Providence derives a significant portion of its income from renewable energy incentive programs sponsored by state governments. Should states reduce, eliminate or change the compliance requirements for these programs, such changes could have a materially adverse impact on the financial performance of the Trust’s investment in Ridgewood Providence.

The Trust may become involved in litigation.

The Trust faces an inherent business risk of exposure to various types of claims and lawsuits that may arise in the ordinary course of business. Although it is not possible to predict the timing, nature or outcome of such claims or lawsuits should they arise, we believe the chances that any claims or lawsuits arising and resulting, individually or in the aggregate, in a material impact on the Trust to be remote. However, the Trust could in the future incur judgments or enter into settlements of lawsuits and claims that could have a material adverse effect on the results of the Trust. In addition, while the Trust maintains insurance coverage with respect to certain claims, the Trust may not be able to obtain such insurance on acceptable terms in the future, if at all, and any such insurance may not provide adequate coverage against any such claims.

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RISKS RELATED TO THE NATURE OF THE TRUST’S SHARES

The Trust’s shares have severe restrictions on transferability and liquidity and shareholders are required to hold the shares indefinitely.

The Trust’s shares are illiquid investments. There is currently no market for these shares and one is not likely to develop. Because there may be only a limited number of persons who purchase shares and because there are significant restrictions on the transferability of such shares under the Trust’s Declaration of Trust and under applicable federal and state securities laws, it is expected that no public market will develop. Moreover, neither the Trust nor the Managing Shareholder will provide any market for the shares. Shareholders are generally prohibited from selling or transferring their shares except in the circumstances permitted under the Declaration of Trust and applicable law, and all such sales or transfers require the Trust’s consent, which it may withhold at its sole discretion. Accordingly, shareholders have no assurance that an investment can be transferred and must be prepared to bear the economic risk of the investment indefinitely.

Shareholders are not permitted to participate in the Trust’s management or operations and must rely exclusively on the Managing Shareholder.

Shareholders have no right, power or authority to participate in the Trust’s management or decision making or in the management of the Trust’s projects. The Managing Shareholder has the exclusive right to manage, control and operate the Trust’s affairs and business and to make all decisions relating to its operation.

The Trust’s assets are generally illiquid and any disposition of Trust assets is at the discretion of the Managing Shareholder.

The Trust’s interest in projects is illiquid. However, if the Trust were to attempt to sell any such interest, a successful sale would depend upon, among other things, the operating history and prospects for the project or interest being sold, the number of potential purchasers and the economics of any bids made by them. The Managing Shareholder has full discretion to determine whether any project, or any partial interest, should be sold and the terms and conditions under which such project would be sold. Consequently, shareholders will depend on the Managing Shareholder for the decision to sell all or a portion of an asset, or retain it, for the benefit of the shareholders and for negotiating and completing the sale transaction.

The Trust indemnifies its officers, as well as the Managing Shareholder and its employees, for certain actions taken on its behalf. Therefore, the Trust has limited recourse relative to these actions.

The Declaration of Trust provides that the Trust’s officers and agents, the Managing Shareholder, the affiliates of the Managing Shareholder and their respective directors, officers and agents when acting on behalf of the Managing Shareholder or its affiliates on the Trust’s behalf, will be indemnified and held harmless by the Trust from any and all claims rising out of the Trust’s management, except for claims arising out of bad faith, gross negligence or willful misconduct or a breach of the Declaration of Trust. Therefore, the Trust may have difficulty sustaining an action against the Managing Shareholder, or its affiliates and their officers based on breach of fiduciary responsibility or other obligations to the shareholders.

The Managing Shareholder is entitled to receive a management fee regardless of the Trust’s profitability and also receives cash distributions.

The Managing Shareholder is entitled to receive an annual management fee from the Trust regardless of whether the Trust is profitable in that year. The annual fee, payable monthly, is equal to 2.5% of the Trust's prior year net asset value. In addition to its annual management fee, the Managing Shareholder, as compensation for its management services, will receive 20% of the Trust’s cash distributions to shareholders upon the shareholders having received a certain minimum level of distributions as set out in the Declaration of Trust, even though the Managing Shareholder has not contributed any cash to the Trust. Accordingly, shareholders contribute all of the cash utilized for the Trust’s investments and activities. If the Trust’s projects are unsuccessful, the shareholders may lose 100% of their investment while the Managing Shareholder will not suffer any investment losses because it did not contribute any capital. None of the compensation to be received by the Managing Shareholder has been derived as a result of arm’s length negotiations.

Cash distributions are not guaranteed and may be less than anticipated or estimated.

Distributions depend primarily on available cash from project operations. At times, distributions have been delayed to repay the principal and interest on project or Trust borrowings, if any, or to the Trust’s other costs. The Trust’s taxable income will be taxable to the shareholders in the year earned, even if cash is not distributed.

8

Because the Managing Shareholder manages other electricity generation and infrastructure trusts, it may have conflicts of interest in its management of the Trust’s operations.

Shareholders will not be involved in the management of the Trust’s operations. Accordingly, they must rely on the Managing Shareholder’s judgment in such matters. Inherent with the exercise of its judgment, the Managing Shareholder will be faced with conflicts of interest. While neither the Trust nor the Managing Shareholder have specific procedures in place in the event of any such conflicting responsibilities, the Managing Shareholder recognizes that it has fiduciary duties to the Trust in connection with its position and responsibilities as Managing Shareholder and it intends to abide by such fiduciary responsibilities in performing its duties. Therefore, the Managing Shareholder and its affiliates will attempt, in good faith, to resolve all conflicts of interest in a fair and equitable manner with respect to all parties affected by any such conflicts of interest. However, the Managing Shareholder is not liable to the Trust for how conflicts of interest are resolved unless it has acted in bad faith, or engaged in gross negligence or willful misconduct.

TAX RISKS ASSOCIATED WITH AN INVESTMENT IN SHARES

The Trust is organized as a Delaware trust and the Managing Shareholder has qualified the Trust as a partnership for federal tax purposes. The principal tax risks to shareholders are that:

· The Trust may recognize income taxable to the shareholders but may not distribute enough cash to cover the income taxes owed by shareholders on the Trust’s taxable income.

· The allocation of Trust items of income, gain, loss, and deduction may not be recognized for federal income tax purposes.

· All or a portion of the Trust’s expenses could be considered either investment expenses (which would be deductible by a shareholder only to the extent the aggregate of such expenses exceeded 2% of such shareholder’s adjusted gross income) or as nondeductible items that must be capitalized.

· All or a substantial portion of the Trust’s income could be deemed to constitute unrelated business taxable income, such that tax-exempt shareholders could be subject to tax on their respective portions of such income.

· If any Trust income is deemed to be unrelated business taxable income, a shareholder that is a charitable remainder trust could have all of its income from any source deemed to be taxable.

· All or a portion of the losses, if any, allocated to the shareholders will be passive losses and thus deductible by the shareholder only to the extent of passive income.

· The shareholders could have capital losses in excess of the amount that is allowable as a deduction in a particular year.

Although the Trust has obtained an opinion of counsel regarding the matters described in the preceding paragraph, it will not obtain a ruling from the IRS as to any aspect of the Trust’s tax status. The tax consequences of investing in the Trust could be altered at any time by legislative, judicial, or administrative action.

If the IRS audits the Trust, it could require investors to amend or adjust their tax returns or result in an audit of their tax.

The IRS may audit the Trust’s tax returns. Any audit issues will be resolved at the Trust level by the Managing Shareholder. If adjustments are made by the IRS, corresponding adjustments will be required to be made to the federal income tax returns of the shareholders, which may require payment of additional taxes, interest, and penalties. An audit of the Trust’s tax return may result in the examination and audit of a shareholder’s return that otherwise might not have occurred, and such audit may result in adjustments to items in the shareholder’s return that are unrelated to the Trust’s operations. Each shareholder bears the expenses associated with an audit of that shareholder’s return.

In the event that an audit of the Trust by the IRS results in adjustments to the tax liability of a shareholder, such shareholder will be subject to interest on the underpayment and may be subject to substantial penalties.

The tax treatment of the Trust cannot be guaranteed for the life of the Trust. Changes in laws or regulations may adversely affect any such tax treatment.

Deductions, credits or other tax consequences may not be available to shareholders. Legislative or administrative changes or court decisions could be forthcoming which would significantly change the statements herein. In some instances, these changes could have substantial effect on the tax aspects of the Trust. Any future legislative changes may or may not be retroactive with respect to transactions prior to the effective date of such changes. Bills have been introduced in Congress in the past and may be introduced in the future which, if enacted, would adversely affect some of the tax consequences of the Trust.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.  PROPERTIES

Information regarding the Trust’s properties is contained in Item 1. “Business”, under the heading “Projects and Properties”.

ITEM 3.  LEGAL PROCEEDINGS

On August 16, 2006, the Trust and several affiliated entities, including the Managing Shareholder, filed a lawsuit against the former independent registered public accounting firm for the Trust and several affiliated entities, Perelson Weiner LLP (“Perelson Weiner”), in New Jersey Superior Court. The suit alleged professional malpractice and breach of contract in connection with audit and accounting services performed for the Trust and the other plaintiffs by Perelson Weiner. On October 20, 2006, Perelson Weiner filed a counterclaim against the Trust and the other plaintiffs, alleging breach of contract due to unpaid invoices in the total amount of approximately $1,188,000. Discovery is ongoing and no trial date has been set.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITY HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

There has never been an established public trading market for the Trust’s Investor Shares.

Holders

As of September 30, 2007 and December 31, 2005, 2004 and 2003, there were 841, 831, 831 and 832 holders of Investor Shares, respectively.

Dividends

Trust distributions for the three years ended December 31, 2005 were as follows (in thousands, except per share data):

	2005		2004		2003
Distributions to Investors	$	1,929	$	2,155	$	1,176
Distributions per Investor Share		4,900		5,500		3,000
Distributions to Managing Shareholder		20		22		12

ITEM 6.  SELECTED FINANCIAL DATA

The following selected consolidated financial data should be read in conjunction with the Trust’s consolidated financial statements and related notes and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K.

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The consolidated statement of operations data for the years ended December 31, 2005, 2004 and 2003 and the consolidated balance sheet data as of December 31, 2005, 2004 and 2003, are derived from audited financial statements included in this Form 10-K. The consolidated statement of operations data for the years ended December 31, 2002 and 2001 and the consolidated balance sheet data as of December 31, 2002 and 2001 are derived from audited consolidated financial statements that have not been restated, and as a result, may not be comparable to subsequent periods. For further discussion, see Note 2 to the Trust’s Consolidated Financial Statements included in this Form 10-K.

	December 31,
(in thousands, except per share data)	2005		2004		2003		2002			2001
					(Restated)
Consolidated Statement of Operations Data:
Revenues	$	4,205	$	5,594	$	5,909	$	7,849		$	6,383
Net income (loss)		1,353		1,817		2,259		(1,356	)		(1,482	)
Net income (loss) per Investor Share		3,418		4,592		5,707		(3,462	)		(3,783	)
Consolidated Balance Sheet Data:
Plant and equipment, net	$	3,594	$	4,585	$	5,016	$	6,632		$	7,863
Total assets		13,739		14,453		14,875		15,589			17,481
Total liabilities		107		304		372		1,316			1,851
Shareholders' equity		13,632		14,149		14,503		14,273			15,630

Quarterly financial information is derived from unaudited financial data, which, in the opinion of management, reflects all adjustments, which are necessary to present fairly the results for such interim periods. It is suggested that the quarterly financial data be read in conjunction with the financial statements and the notes thereto included in this Form 10-K.

	Nine Months Ended September 30,						Three Months Ended September 30,
(in thousands, except per share data)	2005		2004		2003		2005		2004		2003
			(Restated)		(Restated)				(Restated)		(Restated)
Consolidated Statement of Operations Data:
Revenues	$	4,068	$	4,269	$	4,843	$	1,750	$	1,791	$	2,137
Net income (loss)		2,817		2,314		2,238		2,349		1,073		(189	)
Net income (loss) per Investor Share		7,119		5,847		5,655		5,936		2,710		(476	)

 

(in thousands)	September 30,
	2005		2004		2003
Consolidated Balance Sheet Data:			(Restated)		(Restated)
Plant and equipment, net	$	4,268	$	4,699	$	5,188
Total assets		16,054		15,648		15,405
Total liabilities		572		315		530
Shareholders' equity		15,482		15,333		14,875

	Six Months Ended June 30,						Three Months Ended June 30,
(in thousands, except per share data)	2005		2004		2003		2005			2004		2003
			(Restated)		(Restated)					(Restated)		(Restated)
Consolidated Statement of Operations Data:
Revenues	$	2,318	$	2,478	$	2,706	$	1,354		$	1,380	$	1,742
Net income (loss)		468		1,241		2,427		(190	)		562		1,390
Net income (loss) per Investor Share		1,183		3,136		6,131		(479	)		1,422		3,547

 

(in thousands)	June 30,
	2005		2004		2003
Consolidated Balance Sheet Data:			(Restated)		(Restated)
Plant and equipment, net	$	4,373	$	4,807	$	6,098
Total assets		14,375		15,772		16,336
Total liabilities		846		818		877
Shareholders' equity		13,529		14,954		15,459

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	Three Months Ended March 31,
(in thousands, except per share data)	2005		2004		2003
			(Restated)		(Restated)
Consolidated Statement of Operations Data:
Revenues	$	964	$	1,097	$	964
Net income		658		679		1,037
Net income per Investor Share		1,662		1,712		2,621
(in thousands)	March 31,
	2005		2004		2003
Consolidated Balance Sheet Data:			(Restated)		(Restated)
Plant and equipment, net	$	4,479	$	4,910	$	6,243
Total assets		14,831		15,160		15,192
Total liabilities		717		374		728
Shareholders' equity		14,114		14,786		14,464

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the Trust’s Consolidated Financial Statements and Notes which appear elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements that involve risks, uncertainties and assumptions. The Trust’s actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors, including those set forth in Part I, Item 1A. “Risk Factors” and elsewhere in this Annual Report on Form 10-K.

Restatement of Financial Statements

As previously disclosed in its Form 8-K filed with the SEC on October 11, 2007, the consolidated financial statements of the Trust included in the Trust’s Quarterly Reports on Form 10-Q and the Trust’s Annual Report on Form 10-K for each of the periods beginning with the three-month period ended March 31, 2003 and continuing through the three and nine-month periods ended September 30, 2004 previously filed by the Trust with the SEC should no longer be relied upon and that those financial statements should be restated to conform to generally accepted accounting principles. The determination to restate these financial statements and selected financial data was made by the Trust and the Managing Shareholder of the Trust, as a result of the identification of accounting errors as more fully described in Note 2 to the Consolidated Financial Statements. Accordingly, this Annual Report on Form 10-K contains restated financial statements for the periods mentioned above.

Overview

The Trust is a Delaware trust formed on December 6, 1993 to primarily make investments in projects and businesses in the energy and infrastructure sectors. Ridgewood Renewable Power LLC (“RRP” or the “Managing Shareholder”), a New Jersey limited liability company, is the Managing Shareholder. As the Managing Shareholder, RRP has direct and exclusive control over the management and operations of the Trust.

The Trust has focused primarily on projects fueled by natural gas and renewable sources of fuel. These projects allow the Trust to develop secure long-term positions in attractive specialty markets for products and services provided by its projects and companies. As of December 31, 2005, the projects in which the Trust had investments were located in the United States. As of that date, the Trust had investments in a landfill gas-fired electric generating project with total capacity of 13.8MW and in electric cogeneration projects with total capacity of 14.2MW.

The Trust’s consolidated financial statements include the Trust’s 35.7% interest in Ridgewood Providence, which is accounted for under the equity method of accounting as the Trust has the ability to exercise significant influence but does not control the operating and financial policies of the investment. The remaining 64.3% of Ridgewood Providence is owned by Trust IV.

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Critical Accounting Policies and Estimates

The discussion and analysis of the Trust’s financial condition and results of operations are based upon the Trust’s consolidated financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing these financial statements, the Trust is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Trust’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of the Trust’s revenues and expenses during the periods presented. The Trust evaluates these estimates and assumptions on an ongoing basis. The Trust bases its estimates and assumptions on historical experience and on various other factors that the Trust believes to be reasonable at the time the estimates and assumptions are made. However, future events and their effects cannot be predicted with absolute certainty. Therefore, the determination of estimates requires the exercise of judgment. Actual results may differ from these estimates and assumptions under different circumstances or conditions, and such differences may be material to the financial statements. The Trust believes the following critical accounting policies affect the more significant estimates and judgments in the preparation of the Trust’s consolidated financial statements.

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 electric power sales contract. Adjustments are made to reflect actual volumes delivered when the actual volumetric information subsequently becomes available. Billings to customers for power generation generally occurs during the month following deliveries. Final billings do not vary significantly from estimates.

Accounts Receivable

Accounts receivable are recorded at invoice price in the period the related revenues are earned, and do not bear interest. No allowance for bad debt expense was provided based upon historical write-off experience, evaluation of customer credit condition and the general economic status of the customers.

Plant and Equipment

Plant and equipment, consisting principally of electrical generating equipment, is stated at cost less accumulated depreciation. Renewals and betterments that increase the useful lives of the assets are capitalized. Repair and maintenance expenditures are expensed as incurred. Upon retirement or disposal of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheets. The difference, if any, between the net asset value and any proceeds from such retirement or disposal is recorded as a gain or loss in the statement of operations.

Depreciation is recorded using the straight-line method over the useful lives of the assets, which ranges from 5 to 20 years.

Impairment of Intangibles and Long-Lived Assets

The Trust evaluates intangible assets and long-lived assets, such as plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is made by comparing the carrying value of an asset to the estimated undiscounted cash flows attributable to that asset. If impairment has occurred, the impairment loss recognized is the amount by which the carrying value exceeds the estimated fair value of the asset, which is based on the estimated future cash flows discounted at the estimated cost of capital. The analysis requires estimates of the amount and timing of projected cash flows and, where applicable, judgments associated with, among other factors, the appropriate discount rate. Such estimates are critical in determining whether any impairment charge should be recorded and the amount of such charge if an impairment loss is deemed to be necessary.

Gas Contracts

In August 2001, subsidiaries of the Trust entered into agreements to purchase natural gas, at fixed prices, over a five-year term in connection with entering into amendments fixing the sales price of electric power sales contracts for a similar term. These contracts were entered into in order to minimize the impact of fluctuating energy prices. The Trust has determined that these contracts are derivatives as defined under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. The Trust has designated these derivatives as non-hedge instruments. Accordingly, the value of the contracts based on the differences between contract prices and market value prices is recognized as an asset or a liability in the balance sheet. Changes in the carrying value of the contracts are reflected as a component of cost of revenues in the consolidated statements of operations.

13

Management Fee

The Trust is charged management fees from its Managing Shareholder. Unpaid management fees accrue interest at 10% per annum. The Managing Shareholder has periodically waived its right to receive a portion of the fees and related interest. Any waived management fees and interest are deemed capital contributions at the time of waiver.

Income Taxes

No provision is made for income taxes in the Trust’s consolidated financial statements as the income or losses of the Trust are passed through and included in the income tax returns of the individual shareholders of the Trust.

Results of Operations and Changes in Financial Condition

Year ended December 31, 2005 compared to the year ended December 31, 2004

Revenues decreased approximately $1.4 million, or 24.8%, from $5.6 million in 2004 to $4.2 million in 2005. This decrease was primarily due to a decrease in revenues of $1.2 million from the Norcal projects and $0.2 million from two cogeneration facilities which were shut down in 2005 due to the expiration of their contracts.

Cost of revenues decreased by $1.6 million, or 37%, from $4.3 million in 2004 to $2.7 million in 2005 primarily due to lower cost of revenues at the Norcals resulting from the derivative accounting for its gas contract as natural gas prices increased during the year, partially offset by higher maintenance expenses of $0.2 million and other related productions cost increases of $0.2 million.

Gross profit increased by $0.2 million, or 15.3%, from $1.3 million in 2004 to $1.5 million in 2005. This increase was primarily due to derivative accounting for its gas contracts as natural gas prices increased during the year.

General and administrative expenses increased by $85,000 from $0.2 million in 2004 to $0.3 million in 2005. The increase was primarily attributable to an increase of $0.1 million in accounting fees during 2005.

In 2005, the Trust recorded an impairment of $0.6 million related to its remaining co-generation projects purchased from EUA.  In 2004, the Trust recorded an impairment of $0.1 million related to its mobile power modules. The Trust records impairment of plant and equipment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

In 2005, the Trust recorded equity income of $1 million from its investment in Ridgewood Providence compared to $1.2 million in 2004. The decrease in equity income of approximately $0.2 million was primarily due to lower revenue at Ridgewood Providence from less production in 2005.

Total assets at December 31, 2005 decreased by $0.8 million, from $14.5 million at December 31, 2004 to $13.7 million at December 31, 2005, primarily due to decreases of $1 million in plant and equipment and $0.4 million in investments.  The decrease in plant and equipment was due to the impairment of the remaining EUA projects of $0.6 million and depreciation of $0.4 million.  The decrease in investments was due to distributions from investments of $1.5 million, which exceeded equity in income of investments by approximately $0.4 million.  Total liabilities decreased $0.2 million from $0.3 million at December 31, 2004 to $0.1 million at December 31, 2005, primarily due to decreases of $79,000 in due to affiliates and $0.1 million in accounts payable and accrued expenses.

Year ended December 31, 2004 compared to the year ended December 31, 2003

Revenues decreased $0.3 million, or 5.3%, to $5.6 million in 2004 compared to $5.9 million in 2003. This decrease was primarily due to a decrease of $0.6 million in cogeneration revenues as a result of shutting down various cogeneration facilities, as well as decreases of $0.1 million in San Joaquin Project revenues and $22,000 in Byron Project revenues.

Cost of revenues for 2004 was $4.3 million as compared to $3.7 million for 2003, an increase of $0.6 million, or 14.8%. The increase was primarily due to the change in natural gas prices partially offset by an increase in cogeneration production costs.

Gross profit decreased by $0.9 million to $1.3 million in 2004 as compared to $2.2 million in 2003. The decrease was due primarily to the decrease in revenue from 2003 to 2004.

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Other income for the year ended December 31, 2003 includes $0.2 million of proceeds from the sale of equipment from cogeneration projects that were previously written down to zero.

In 2004, the Trust recorded equity income of $1.2 million from its investment in Ridgewood Providence compared to $0.6 million in 2003. The increase was primarily due to higher renewable attribute revenues for 2004 as compared to 2003.

Total assets decreased approximately $0.4 million from $14.9 million at December 31, 2003 to $14.5 million at December 31, 2004. This decrease was primarily due to decreases of $0.5 million in assets held for sale related to the mobile power modules and $0.1 million in due from affiliates, partially offset by an increase of $1 million in gas forward contracts. Total liabilities decreased $68,000 from $0.4 million at December 31, 2003 to $0.3 million at December 31, 2004, primarily due to a decrease of $55,000 in accounts payable and accrued expenses.

Nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

Revenues decreased $0.2 million, or 4.7%, from $4.3 million for the nine months ended September 30, 2004 to $4.1 million for the same period in 2005. This decrease was primarily due to a decrease of $0.2 million in cogeneration revenues.

Cost of revenues for the nine months ended September 30, 2005 was $1.6 million as compared to $2.3 million for the same period in 2004, a decrease of $0.7 million, or 29.6%. This decrease was primarily due to a decrease of $0.3 million in cogeneration facilities expenses, $0.1 million reduction in maintenance expense and a decrease of $0.1 million in fuel expense at the San Joaquin facility for the first nine months of 2005.

Gross profit increased approximately $0.4 million to $2.4 million for the nine months ended September 30, 2005 as compared to $2 million for the same period in 2004.  This increase was due to decreased cogeneration facilities expenses, maintenance costs and fuel expenses.

Total assets at September 30, 2005 were $16.1 million, an increase of $1.6 million from the December 31, 2004 balance of $14.5 million. This increase was primarily due to the increase of $1.7 million in gas forward contracts arising from increased prices of natural gas, $0.4 million in investments, $0.3 million in accounts receivable, partially offset by a decrease of $0.3 million in plant and equipment due to annual depreciation of the assets. Total liabilities increased approximately $0.3 million from $0.3 million at December 31, 2004 to $0.6 million at September 30, 2005 primarily due to increases of $0.1 million in due to affiliates and $0.1 million in accounts payable and accrued expenses.

Nine months ended September 30, 2004 compared to the nine months ended September 30, 2003

Revenues decreased approximately $0.5 million, or 11.9%, from $4.8 million for the nine months ended September 30, 2003 as compared to $4.3 million for the nine months ended September 30, 2004. This decrease was primarily due to a decrease of $0.9 million in cogeneration facilities revenues in the first nine months of 2004.

Cost of revenues for the nine months ended September 30, 2004 was $2.3 million as compared to $2.8 million for the same period in 2003.  The decrease of $0.5 million was primarily due to a decrease in cost of revenues at the Byron facility of $0.3 million, increased natural gas prices, the impact of which reduced cost of revenues by $0.4 million, and a decrease in cogeneration facilities expense of $0.3 million in 2004.

Gross profit decreased by $0.1 million from $2.1 million for the nine months ended September 30, 2003 as compared to $2 million for the same period in 2004. This decrease was primarily due to reduced cogeneration revenues in the 2004 period as compared to the 2003 period.

For the nine months ended September 30, 2004, the Trust recorded equity income of $0.9 million from its investment in Ridgewood Providence as compared to $0.4 million in the 2003 period. The increase in equity income of $0.5 million was primarily due to higher renewable attribute revenues at Ridgewood Providence.

For the nine months ended September 30, 2003, the Trust recorded $0.2 million of other operating income resulting from the sale of cogeneration equipment that was previously written down to zero.

Total assets at September 30, 2004 were $15.6 million, an increase of approximately $0.7 million from the December 31, 2003 balance of $14.9 million. This increase was primarily due to increases of $1.7 million in gas forward contracts due to increased natural gas prices and $0.2 million in accounts receivable partially offset by decreases of $0.2 million in due from affiliates, $0.3 million in plant and equipment and $0.3 million in investments. Total liabilities decreased $57,000 from $0.4 million at December 31, 2003 to $0.3 million at September 30, 2004.

15

Three months ended September 30, 2005 compared to the three months ended September 30, 2004

Revenues decreased $41,000, or 2.3%, to $1.8 million in the third quarter of 2005 as compared to $1.8 million for the third quarter of 2004. This decrease was primarily due to a decrease of $66,000 in cogeneration facilities revenue.

Cost of revenues for the third quarter of 2005 was a credit of $0.5 million, a decrease of approximately $1.5 million as compared to $1 million in the third quarter of 2004. The decrease was primarily due to a greater increase in natural gas prices in the third quarter of 2005 compared to the increase in the third quarter of 2004.

Gross profit increased approximately $1.4 million to $2.2 million for the three months ended September 30, 2005 as compared to $.0.8 million for the same period in 2004.  This increase was due to increased natural gas prices in 2005.

General and administrative expenses increased $36,000 to $47,000 in the third quarter of 2005 as compared to $11,000 in the same period in 2004, primarily attributable to an increase in accounting fees.

For the three months ended September 30, 2005, the Trust recorded a decrease of $0.1 million in equity income from $0.3 million from its investment in Ridgewood Providence as compared to $0.4 million for the three months ended September 30, 2004. The decrease in the equity in income was primarily due to decreased revenues and increased general and administrative expenses in the 2005 period as compared to the 2004 period.

Three months ended September 30, 2004 compared to the three months ended September 30, 2003

Revenues decreased $0.3 million, or 16.2%, to $1.8 million in the third quarter of 2004 as compared to $2.1 million for the same quarter in 2003.  This decrease was primarily due to a decrease in cogeneration revenues.

Cost of revenues for the 2004 period was $1 million as compared to $2.3 million for the 2003 period, a decrease of $1.3 million, or 57.1%. The decrease was primarily due to increased natural gas prices in the third quarter of 2004.

Gross profit increased by $0.9 million from a loss of $0.1 million for the three months ended September 30, 2003 as compared to profit of $0.8 million for the same period in 2004. This increase was primarily due to increased natural gas prices in 2004.

During the third quarter of 2003, the Trust recorded $88,000 of impairment of equipment related to the mobile power modules.

For the three months ended September 30, 2004, the Trust recorded equity income of $0.4 million from its investment in Ridgewood Providence as compared to $0.1 million in the 2003 period. The increase in the equity income of $0.3 million was primarily due to the higher renewable attribute revenues at Ridgewood Providence.

Six months ended June 30, 2005 compared to the six months ended June 30, 2004

Revenues decreased $0.2 million, or 6.5%, from $2.5 million for the six months ended June 30, 2004 as compared to $2.3 million for the six months ended June 30, 2005. The decrease was primarily due to shutting down two cogeneration facilities as a result of the expiration of their sales contracts.

Cost of revenues increased approximately $0.8 million, or 54.8%, from $1.3 million for the six months ended June 30, 2004 as compared to $2.1 million for the six months ended June 30, 2005. The increase was primarily due to the rate of increase in natural gas prices slowing in 2005.

Gross profit decreased by $0.9 million from $1.1 million for the six months ended June 30, 2004 as compared to $0.2 million for the same period in 2005. This decrease was primarily due to increased cost of revenues arising from the rate of increase in natural gas prices slowing in 2005 compared to 2004.

Total assets at June 30, 2005 were $14.4 million, a decrease of $0.1 million from the December 31, 2004 balance of $14.5 million. Total liabilities increased $0.5 million from $0.3 million at December 31, 2004 to $0.8 million at June 30, 2005. This increase was primarily the result of increases of $0.5 million in due to affiliates and $68,000 in accounts payable and accrued expenses.

16

Six months ended June 30, 2004 compared to the six months ended June 30, 2003

Revenues decreased $0.2 million, or 8.4%, to $2.5 million for the six months ended June 30, 2004 compared to $2.7 million for the first six months of 2003. This decrease was primarily due to a decrease in cogeneration facilities revenues of $0.6 million in the first six months of 2004 as compared to the six months ended June 30, 2003.

Cost of revenues increased approximately $0.8 million to $1.3 million for the six months ended June 30, 2004 from $0.5 million for the same period in 2003. The increase was primarily due to higher natural gas prices.

Gross profit decreased by $1.1 million from $2.2 million for the six months ended June 30, 2003 as compared to $1.1 million for the same period in 2004. This decrease was primarily due to decreased cogeneration facilities revenues of $0.6 million in 2004 and higher natural gas prices in 2004.

In the first half of 2004, the Trust recorded equity income of $0.5 million from its investment in Ridgewood Providence as compared to $0.3 million in the 2003 period. The increase in equity income of $0.2 million was primarily due to the higher renewable attribute revenues at Ridgewood Providence in 2004 as compared to 2003.

Total assets at June 30, 2004 were $15.8 million, an increase of $0.9 million from the December 31, 2003 balance of $14.9 million. The increase was caused by increases in cash and cash equivalents of $0.4 million, $0.3 million in accounts receivable, $1.3 million increase in gas forward contracts due to increased natural gas prices and $0.5 million in investments, partially offset by decreases of $0.6 million in due from affiliates, $0.2 million in plant and equipment, and $0.5 million in assets held for sale. Total liabilities increased $0.4 million from $0.4 million at December 31, 2003 to $0.8 million at June 30, 2004, primarily due to an increase in due to affiliates of $0.5 million, partially offset by a decrease in accounts payable and accrued expenses of $14,000.

Three months ended June 30, 2005 compared to the three months ended June 30, 2004

Revenues remained flat at $1.4 million for both the 2005 and 2004 periods.

Cost of revenues for the quarter ended June 30, 2005 increased approximately $0.7 million to $1.6 million from $0.9 million in the 2004 period. The increase was primarily due to a temporary decline in natural gas prices during the 2005 quarter.

Gross profit decreased by $0.7 million from $0.5 million for the six months ended June 30, 2004 as compared to a loss of $0.2 million for the same period in 2005. This decrease was primarily due to increased cost of revenues arising from the rate of increase in natural gas prices slowing in 2005 as compared to 2004.

Three months ended June 30, 2004 compared to the three months ended June 30, 2003

Revenues decreased approximately $0.3 million, or 20.8%, to $1.4 million in the second quarter of 2004 as compared to $1.7 million in the second quarter of 2003. This decrease was primarily due to the decrease in cogeneration facilities revenues.

Cost of revenues for the three months ended June 30, 2004 was $0.9 million compared to $0.3 million for the same period in 2003.  The increase of $0.6 million was primarily due to the effect of the change in the market price of natural gas.

Gross profit decreased by $1.0 million from $1.4 million for the six months ended June 30, 2003 as compared to approximately $0.4 million for the same period in 2004. This decrease was primarily due to a decrease in revenue of $0.4 million and by the effect of change in the market price of natural gas.

Three months ended March 31, 2005 compared to the three months ended March 31, 2004

Revenues in the first quarter of 2005 of $1 million decreased by $0.1 million, or 12.1%, from revenues of $1.1 million in the first quarter of 2004.  This decrease was primarily due to a decrease in cogeneration facilities revenues.

Gross profit decreased by $0.2 million from $0.7 million for the three months ended March 31, 2004 as compared to $0.5 million for the same period in 2005. This decrease was primarily due to decreased cogeneration revenue and increased cost of revenues caused in turn by the rate of increase in natural gas prices slowing in 2005 as compared to 2004.

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For the first quarter of 2005, the Trust recorded equity income of $343,000 from its investment in Ridgewood Providence as compared to $281,000 for the same period in 2004, an increase of $62,000, primarily due to a decrease of cost of revenues for Ridgewood Providence.

Total assets at March 31, 2005 were $14.8 million, an increase of approximately $0.3 million from the December 31, 2004 balance of $14.5 million. Total liabilities increased $0.4 million from $0.3 million at December 31, 2004 to $0.7 million at March 31, 2005. This increase in total liabilities was primarily due to increases of $0.2 million in due to affiliates and $0.2 million in accounts payable and accrued expense.

Three months ended March 31, 2004 compared to the three months ended March 31, 2003

Revenues increased $0.1 million, or 13.9%, to $1.1 million in the first quarter of 2004 as compared to $1 million in the first quarter of 2003. The increase was primarily due to an increase of $0.3 million in Norcal revenue partially offset by a $0.2 million decrease in cogeneration facilities revenues.

Cost of revenues for the three months ended March 31, 2004 was $0.4 million as compared to $0.2 million for the same period in 2003. The increase of approximately $0.2 million was primarily due to the effect of the change in the market price of natural gas.

Gross profit decreased by $0.1 million from $0.8 million for the three months ended March 31, 2003 as compared to $0.7 million for the same period in 2004. This decrease was primarily due to the decreased cost of revenues partially offset by an increase in revenues.

Total assets at March 31, 2004 were $15.2 million, an increase of $0.3 million from the December 31, 2003 balance of $14.9 million. This increase was primarily due to increases of $0.8 million in gas forward contracts due to increases in the price of natural gas and $0.3 million in investments, partially offset by a decrease in due from affiliates of $0.6 million. Total liabilities remained flat at $0.4 million at March 31, 2004 and December 31, 2003.

Liquidity and Capital Resources

Year ended December 31, 2005 compared to the year ended December 31, 2004

At December 31, 2005, the Trust had cash and cash equivalents of $0.3 million, an increase of $0.2 million from December 31, 2004. The cash flows for 2005 consisted of $2.1 million provided by operating activities and $1.9 million used in financing activities.

In 2005, the Trust’s operating activities provided cash of $2.1 million as compared to $1.9 million in 2004, an increase of $0.2 million, primarily due to increased cash flows from ongoing operations.

In 2005, investing activities provided $31,000 from collection from a note receivable.  In 2004, cash provided by investing activities was $0.4 million, which is the net of proceeds of $0.4 million related to the sale of it mobile power modules, capital expenditures of $34,000 and collections from a note receivable of $45,000.

In 2005, the Trust used $1.9 million in financing activities as compared to $2.2 million in 2004, both of which were cash distributions to shareholders.

Year ended December 31, 2004 compared to the year ended December 31, 2003

At December 31, 2004, the Trust had cash and cash equivalents of $0.1 million, an increase of $74,000 from December 31, 2003. The cash flows for the year 2004 consisted of $1.9 million provided by operating activities, $0.4 million provided by investing activities and $2.2 million used in financing activities.

In 2004, the Trust’s operating activities provided cash of $1.9 million as compared to $0.5 million in 2003, an increase of approximately $1.4 million primarily due to a decrease in amounts used to pay down accounts payable of $0.6 million and due to affiliates of $0.9 million.

In 2004, investing activities provided cash of $0.4 million compared to $0.3 million in 2003, an increase of approximately $0.1 million. The increase in cash provided was primarily due to an increase in proceeds related to the sale of investments in 2004 as compared to 2003.

In 2004, the Trust used $2.2 million in financing activities as compared to $1.2 million in 2003, both of which were distributions to shareholders.

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Nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

At September 30, 2005, the Trust had cash and cash equivalents of $0.4 million, an increase of $0.3 million from December 31, 2004. The cash flows for the first nine months of 2005 were $1.8 million provided by operating activities and $1.5 million used in financing activities.

Cash provided by operating activities for the nine months ended September 30, 2005 was $1.8 million as compared to $1.3 million for the nine months ended September 30, 2004. The increase in cash flow from operating activities in the first nine months of 2005 as compared to the same period in 2004 was primarily due to an increase of $0.7 million in net due to from affiliates.

Cash used in financing activities was $1.5 million for both the 2005 and 2004 periods, which was comprised of cash distributions to shareholders.

Nine months ended September 30, 2004 compared to the nine months ended September 30, 2003

At September 30, 2004, the Trust had cash and cash equivalents of $0.3 million, an increase of $0.3 million from December 31, 2003. The cash flows for the first nine months of 2004 were $1.3 million provided by operating activities, $0.4 million used in investing activities and $1.5 million used in financing activities.

Cash provided by operating activities for the nine months ended September 30, 2004 was $1.3 million as compared to $0.5 million for the nine months ended September 30, 2003. The increase in cash flow was primarily due to a decrease in cash used to pay accounts payable of $0.6 million.

Cash provided by investing activities was $0.4 million during the first nine months of 2004 as compared to $0.2 million in the first nine months of 2003.  The increase of approximately $0.2 million is primarily due to increased proceeds from sale of equipment.

Cash used in financing activities for the first nine months of 2004 was $1.5 million compared to $0.8 million for the first nine months of 2003. The increase in cash used in financing activities was due to increased distributions to shareholders.

Six months ended June 30, 2005 compared to the six months ended June 30, 2004

At June 30, 2005, the Trust had cash and cash equivalents of $0.3 million, an increase of approximately $0.2 million from December 31, 2004. The increase was the result of $1.2 million provided by operating activities and $1.1 million used in financing activities.

Cash provided by operating activities for the six months ended June 30, 2005 was $1.2 million as compared to $0.8 million for the six months ended June 30, 2004. The increase in cash flow was primarily due to distributions from investments of $0.4 million in the six months ended June 30, 2005.

Cash used in financing activities for the first half of 2005 was $1.1 million as compared to $0.8 million for the first half of 2004, both of which were due to distributions to shareholders. 

Six months ended June 30, 2004 compared to the six months ended June 30, 2003

At June 30, 2004, the Trust had cash and cash equivalents of $0.4 million, an increase of $0.4 million from December 31, 2003. The increase was the result of $0.8 million provided by operating activities, $0.4 million provided by investing activities and $0.8 million used in financing activities.

Cash provided by operating activities for the six months ended June 30, 2004 was $0.8 million as compared to cash used of $0.5 million for the six months ended June 30, 2003. The increase in cash provided by operating activities was primarily due to an increase in due to from affiliates of $1 million and a decrease of $0.5 million in cash used to pay accounts payable.

Cash provided by investing activities was $0.4 million during the first six months of 2004 as compared to $0.1 million in the first six months of 2003. The increase in cash was primarily due to the disposal of the mobile power units in 2004.

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Cash used in financing activities for the first half of 2004 was $0.8 million as compared to $0.4 million in the first half of 2003, both of which were distributions to shareholders.

Three months ended March 31, 2005 compared to the three months ended March 31, 2004

At March 31, 2005, the Trust had cash and cash equivalents of $1,000, a decrease of $0.1 million from December 31, 2004. The decrease was primarily the result of $0.6 million provided by operating activities and $0.7 million used in financing activities.

Cash provided by operating activities for the three months ended March 31, 2005 was $0.6 million as compared to cash provided of $0.4 million for the three months ended March 31, 2004. The increase in cash flow in the 2005 period compared to 2004 period was primarily due to an increase in accounts payable.

Cash used in financing activities for the first quarter of 2005 was $0.7 million compared to $0.4 million in the first quarter of 2004. In the first quarter of each of 2005 and 2004, cash used in financing activities represents cash distributions to shareholders.

Three months ended March 31, 2004 compared to three months ended March 31, 2003

At March 31, 2004, the Trust had cash and cash equivalents of $63,000, an increase of $17,000 from December 31, 2003. The increase was the result of $0.4 million provided by operating activities, $15,000 provided by investing activities and $0.4 million used in financing activities.

Cash provided by operating activities for the three months ended March 31, 2004 was $0.4 million compared to cash used of $0.3 million for the three months ended March 31, 2003. The increase of $0.7 million in cash flows from operating activities was primarily the result of increases in due to affiliates and accounts payable.

Cash used in financing activities for the first quarter of 2004 was $0.4 million compared to none in the first quarter of 2003. In the first quarter of 2004, cash used in financing activities represents cash distributions to shareholders.

Off-Balance Sheet Arrangements

In connection with the gas supply contracts at the Norcals, the Trust has issued two standby letters of credit totaling $350,000 at December 31, 2005. These letters of credit expired in August 2006.

Contractual Obligations and Commitments

At December 31, 2005, the Trust’s contractual obligations are as follows:

	Payments due by period
Contractual obligations	Total		Less than 1 year		2 - 3 years		4 - 5 years		More than 5 years
Ground operating leases	$	2,655	$	173	$	346	$	346	$	1,790
Gas forward contracts, net		837		837		-		-		-
Total	$	3,492	$	1,010	$	346	$	346	$	1,790

The gas forward contracts require the Norcals to purchase minimum quantities of natural gas through August 2006. Amounts reflected above are net of agreements to resell the purchased gas back to the Norcals’ supplier.

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Recent Accounting Pronouncements

SFAS 143 and FIN 47

 In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations, on the accounting for obligations associated with the retirement of long-lived assets. SFAS No. 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 No. 143 is effective for fiscal years beginning after June 15, 2002. Furthermore, in March 2005, the FASB issued FASB Interpretation No. 47 (“FIN 47”), Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, which clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143. Specifically, FIN 47 provides that an asset retirement obligation is conditional when the timing and/or method of settling the obligation is conditioned on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. The Trust adopted SFAS No. 143 effective January 1, 2003, with no material impact on its 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 Corrections. 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. SFAS No. 145 is effective for interim periods beginning after May 15, 2002. The Trust adopted SFAS No. 145 effective January 1, 2003, with no material impact on its 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. SFAS No. 146 is effective for fiscal years ending after December 31, 2002. The Trust adopted SFAS No. 146 effective January 1, 2003, with no material impact on its 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, under certain circumstances 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 during the fourth quarter of 2002 with no material impact to the consolidated financial statements.

FIN 46R

In January 2003, the FASB issued FASB Interpretation No. 46, 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, 2003, with no material impact to the consolidated financial statements. In December 2003, the FASB issued a revision to FIN 46 (“FIN 46R”) to clarify some of the provisions and to exempt certain entities from its requirements. The Trust implemented the full provisions of FIN 46R effective January 1, 2004, with no material impact on its consolidated financial statements.

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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 No. 149 effective July 1, 2003, with no material impact on its consolidated financial statements.

SFAS 150

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for classifying and measuring certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for interim periods beginning after June 15, 2003. The Trust adopted SFAS No. 150 effective July 1, 2003, with no material impact on its consolidated financial statements.

SFAS 153

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29. The guidance in APB Opinion No. 29, Accounting for Nonmonetary Transactions (“Opinion 29”), is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in Opinion 29, however, included certain exceptions to that principle. This Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Trust adopted SFAS No. 153 effective June 15, 2005, with no material impact on its consolidated financial statements.

SFAS 154

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. This statement changes the requirements for the accounting for, and reporting of, a change in accounting principle and applies to all voluntary changes in accounting principle, as well as changes pursuant to accounting pronouncements that do not include transition rules. Under SFAS No. 154, changes in accounting principle must be applied retrospectively to prior periods’ financial statements, or the earliest practicable date, as the required method for reporting a change in accounting principle. The Trust adopted SFAS No. 154 effective December 15, 2005, and accordingly restated the consolidated financial statements, as described in Note 2 to the consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The disclosure required by this Item is omitted pursuant to Item 305(e) of Regulation S-K.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The consolidated financial statements of the Trust, including the notes thereto and the report thereon, are presented beginning at page F-1 of this Form 10-K.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

As reported on a Form 8-K filed with the SEC on June 14, 2006, the Managing Shareholder of the Trust dismissed Perelson Weiner as the Trust’s independent registered public accountants effective June 8, 2006. Perelson Weiner was engaged as the independent accountants of the Trust as of January 14, 2004 after the Trust dismissed PricewaterhouseCoopers LLP (“PWC”) as its independent accountants, as reported on a Form 8-K filed by the Trust with the SEC on January 20, 2004. 

For the period January 14, 2004 through June 8, 2006, there were no (1) disagreements with Perelson Weiner on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements if not resolved to their satisfaction would have caused them to make reference to the subject matter of the disagreements in their report on the Trust’s financial statements, or (2) “reportable events,” as defined in Item 304(a)(1)(v) of Regulation S-K, other than as follows:

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A. Disagreements

1.   The Trust did not record the fair value of the thermal energy provided to a landlord pursuant to contractual arrangements. Perelson Weiner identified adjustments that would result in the Trust recording thermal sales for the thermal energy provided to the landlord for the year ended December 31, 2004, which Perelson Weiner estimated to have a market value of $546,642 for such year, and recording a corresponding rent expense increase of the same amount. This change would have no impact on the net income of the Trust for the year ended December 31, 2004.

2.   The Trust recorded power generation revenue and fuel expense for certain pass-through arrangements between two subsidiaries of the Trust and the steam costs of two projects. Perelson Weiner identified adjustments which would eliminate the power generation revenue and fuel expense which the Trust recognized for these projects of $976,823 for the year ended December 31, 2004. This change would have no impact on the net income of the Trust for the year ended December 31, 2004.

3.       Perelson Weiner has identified an inconsistency relating to the Trust’s allocation in the consolidated financial statements of net income (loss) between the Managing Shareholder and other shareholders of the Trust and the terms of the Amended Declaration of Trust. This change would have no impact on the amount or location of cash distributions of the Trust to its shareholders.

B. Reportable Events

Perelson Weiner identified the following material deficiencies in disclosure controls and procedures, which are reportable events: (i) a lack of automation and integration in the Trust’s accounting and financial reporting software, which caused the Trust to be unable to timely comply with its financial reporting responsibilities, (ii) a lack of sufficient personnel with relevant experience to maintain and operate the Trust’s accounting and financial reporting software and to develop and administer additional disclosure controls and procedures to enable the Trust to comply on a timely basis with its financial reporting obligations, and (iii) disclosure controls and procedures that were insufficient to enable the Trust to meet its financial reporting and disclosure obligations in an accurate and timely manner.

See Note 2 to the Trust’s consolidated financial statements appearing elsewhere in this Form 10-K for a discussion of restatements to its previously issued financial statements.

For the year ended December 31, 2002 and for the period through January 14, 2004, there were no (1) disagreements with PWC on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements if not resolved to their satisfaction would have caused them to make reference to the subject matter of the disagreements in their report on the Trust’s financial statements, or (2) “reportable events,” as defined in Item 304(a)(1)(v) of Regulation S-K.

As reported on a Form 8-K filed on July 13, 2006, the Managing Shareholder of the Trust appointed Grant Thornton LLP as the Trust’s independent registered public accounting firm effective July 12, 2006.

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ITEM 9A.  CONTROLS AND PROCEDURES

In accordance with Rule 13a-15(b) under the Exchange Act, the Trust’s Chief Executive Officer and Chief Financial Officer evaluates the effectiveness of the Trust’s disclosure controls and procedures. A system of disclosure controls and procedures is designed to ensure that information required to be disclosed by a registrant in reports filed with the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms. This includes disclosure controls and procedures designed to ensure that information required to be disclosed by a registrant is accumulated and communicated to senior management so as to allow timely decisions regarding required disclosure. A review of these controls and procedures was done by the Trust as of December 31, 2003 and for each quarter through September 30, 2004 and such reviews revealed no material weaknesses in the Trust’s disclosure controls and procedures. Additional reviews were conducted as of the end of each of the periods ended December 31, 2004, March 31, 2005, June 30, 2005, September 30, 2005 and December 31, 2005. These additional reviews indicated material weaknesses, of which the following continue to exist as material weaknesses:

(i) a lack of sufficient personnel with relevant experience to develop, administer and monitor disclosure controls and procedures to enable the Trust to comply efficiently, or on a timely basis, with its financial reporting obligations,

(ii) inadequate disclosure controls and procedures, including inadequate record retention and review policies, over both foreign and US operations, that would enable the Trust to meet its financial reporting and disclosure obligations in an efficient and timely manner.

As a result of these weaknesses, the Trust has not timely met its reporting obligations under the Exchange Act. Additionally, upon further examination of the Trust’s previously issued financial statements, various accounting errors were identified. As reported under Item 4.02 of the Form 8-K filed by the Trust on October 11, 2007, management of the Trust concluded that the Trust’s previously issued financial statements for the periods ended March 31, 2003 and thereafter should no longer be relied upon and should be restated to correct for identified errors detected by management.

The primary cause of the above weaknesses was a lack of sufficiently qualified personnel. The Trust has implemented the following to address the above weaknesses:

· Increased the number of degreed accountants. Additional staff expansion is underway.

· Engaged a national accounting firm to evaluate procedures and controls over financial reporting. The firm made a report to the Managing Shareholder in May 2006, which has implemented some of the firm’s recommendations, and is in the process of evaluating the remaining recommendations.

· In August 2006, engaged a national accounting firm to supply accounting personnel to assist while personnel hiring is underway. The work performed by the firm is under the direct supervision of the Trust’s Chief Financial Officer and Controller.

· In May 2007, the Trust appointed a new Chief Financial Officer who is a Certified Public Accountant with approximately 29 years of professional accounting experience, including prior experiences as a financial officer of publicly traded companies.

The Trust believes that the completion of the expansion of the accounting and financial reporting staff and implementation of recommended procedures will mitigate the above weaknesses. However, due to the Trust’s delinquencies in meeting its filing deadlines under the Exchange Act, the Trust expects these deficiencies to continue to be material weaknesses at least until such time as the Trust is no longer delinquent in its Exchange Act filings.

The Trust also concluded as part of the reviews subsequent to September 30, 2004, that it had material weaknesses regarding system automation and identification of material transactions. The Trust also believes that as of December 31, 2005, it has implemented changes in internal control to address those weaknesses. As a result of the implemented controls, the Trust no longer considers those items to be material weaknesses.

The Trust’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Trust’s disclosure controls and procedures as of the end of each of the periods covered by this report pursuant to Rule 13a-15(b) under the Exchange Act and concluded that, as of the end of each of the periods covered by this report, because of the material weaknesses noted above, the Trust’s disclosure controls and procedures were not effective.

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ITEM 9B.  OTHER INFORMATION; UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS; DEFAULTS UPON SENIOR SECURITIES

None.

PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Trust’s Managing Shareholder, Ridgewood Renewable Power, LLC, was originally founded in 1991. The Managing Shareholder has very broad authority, including the authority to elect executive officers of the Trust.

Each of the executive officers of the Trust also serves as an executive officer of the Managing Shareholder. The executive officers of the Trust are as follows:

Name, Age and Position with Registrant	Officer Since
Randall D. Holmes, 60
President and Chief Executive Officer	2004
Robert E. Swanson, 60
Chairman	1997
Jeffrey H. Strasberg, 50
Executive Vice President and Chief Financial Officer (1)	2007
Daniel V. Gulino, 47
Senior Vice President, General Counsel and Secretary	2000
Douglas R. Wilson, 48
Executive Vice President and Chief Financial Officer (1)	2005

(1) Mr. Strasberg replaced Mr. Wilson as Executive Vice President and Chief Financial Officer on May 2, 2007.

Set forth below is the name of and certain biographical information regarding the executive officers of the Trust:

Randall D. Holmes has served as President and Chief Executive Officer of the Trust since January 2006 and served as Chief Operating Officer of the Trust from January 2004 until January 2006. Mr. Holmes has also served as the President and Chief Operating Officer of the Managing Shareholder, and affiliated Power Trusts and LLCs since January 2004. Prior to such time, Mr. Holmes served as the primary outside counsel to and has represented the Managing Shareholder and its affiliates since 1991. Immediately prior to being appointed Chief Operating Officer, Mr. Holmes was counsel to Downs Rachlin Martin PLLC (“DRM”). DRM is one of the primary outside counsel to the Trust, the Managing Shareholder and its affiliates. 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 Executive Officer. Mr. Holmes is a graduate of Texas Tech University and the University of Michigan Law School. He is a member of the New York State bar.

Robert E. Swanson has served as Chairman of the Trust, the Managing Shareholder and affiliated Power Trusts and LLCs since their inception. From their inception until January 2006, Mr. Swanson also served as their Chief Executive Officer. Mr. Swanson is the controlling member of the Managing Shareholder, as well as Ridgewood Energy and Ridgewood Capital, affiliates of the Trust. Mr. Swanson has been President and registered principal of Ridgewood Securities since its formation in 1982, has served as the Chairman of the Board of Ridgewood Capital since its organization in 1998 and has served as President and Chief Executive Officer of Ridgewood Energy since its inception in 1982. Mr. Swanson is a member of the New York State and New Jersey State 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.

Jeffrey H. Strasberg has served as Executive Vice President of the Trust, the Managing Shareholder, and affiliated Power Trusts and LLCs since May 2007. Mr. Strasberg also serves as Senior Vice President and Chief Financial Officer of Ridgewood Capital and affiliated LLCs and Ridgewood Securities and has done so since April 2005. Mr. Strasberg joined Ridgewood Capital in 1998 where his initial responsibilities were to serve as interim Chief Financial Officer of various portfolio companies in which Ridgewood Capital Trusts had interests. Mr. Strasberg is a Certified Public Accountant and a graduate of the University of Florida.

25

Daniel V. Gulino has served as Senior Vice President and General Counsel of the Trust, the Managing Shareholder and affiliated Power Trusts and LLCs since 2000 and was appointed Secretary in February 2007. Mr. Gulino also serves as Senior Vice President and General Counsel of Ridgewood Energy, Ridgewood Capital, Ridgewood Securities and affiliated Trusts and LLCs and has done so since 2000. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. He is a graduate of Fairleigh Dickinson University and Rutgers University School of Law.

Douglas R. Wilson served as Executive Vice President and Chief Financial Officer of the Trust, the Managing Shareholder and affiliated Power Trusts and LLCs from April 2005 until May 2007. Mr. Wilson continues to serve the Managing Shareholder as Executive Vice President and Chief Development Officer. Mr. Wilson has been associated with the Ridgewood group of companies as a consultant and advisor since 1996 performing investment evaluation, structuring and execution services for the trusts and entities managed by Ridgewood Capital LLC. From May of 2002, until its sale in 2007, Mr. Wilson has served as a Director, CEO and Finance Director for CLPE Holdings. Mr. Wilson is a graduate of the University of Texas at Arlington and has an MBA from the Wharton School at the University of Pennsylvania.

Board of Directors and Board Committees

The Trust does not have its own board of directors or any board committees. The Trust relies upon the Managing Shareholder to perform the function that a board of directors or its committees would otherwise perform. Officers of the Trust are not directly compensated by the Trust, and all compensation matters are addressed by the Managing Shareholder, as described in Item 11. “Executive Compensation”. Because the Trust does not maintain a board of directors and because officers of the Trust are compensated by the Managing Shareholder, the Managing Shareholder believes that it is appropriate for the Trust to not have a nominating or compensation committee.

Managing Shareholder

The Trust’s management agreement with the Managing Shareholder details how the Managing Shareholder is to render management, administrative and investment advisory services to the Trust (the “Management Agreement”). Specifically, the Managing Shareholder performs (or may arrange for the performance of) the management and administrative services required for the operation of the Trust. Among other services, the Managing Shareholder administers the accounts and handles relations with shareholders, provides the Trust with office space, equipment and facilities and other services necessary for its operation, and conducts the Trust’s relations with custodians, depositories, accountants, attorneys, brokers and dealers, corporate fiduciaries, insurers, banks and others, as required.

The Managing Shareholder is also responsible for making investment and divestment decisions, subject to the provisions of the Declaration of Trust. The Managing Shareholder is obligated to pay the compensation of the personnel and administrative and service expenses necessary to perform the foregoing obligations. The Trust pays all other expenses of the Trust, including transaction expenses, valuation costs, expenses of preparing and printing periodic reports for shareholders and the SEC, postage for Trust mailings, SEC fees, interest, taxes, legal, accounting and consulting fees, litigation expenses and other expenses properly payable by the Trust. The Trust reimburses the Managing Shareholder for all such Trust expenses paid by the Managing Shareholder.

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 in Item 13. “Certain Relationships and Related Transactions”.

Each investor in the Trust consented to the terms and conditions of the 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 shareholders or the Managing Shareholder. The Management Agreement is subject to amendment by the parties upon the approval of a majority in interest of the investors.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Trust’s executive officers and directors, and persons who own more than 10% of a registered class of the Trust’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Trust, the Trust believes that the filing requirements were not met by Randall D. Holmes, Robert E. Swanson, Douglas R. Wilson, Daniel V. Gulino and Robert L. Gold during the years ended December 31, 2005, 2004 and 2003 as they each failed to timely file Form 3. All such required reports have since been filed with the SEC.

26

Code of Ethics

In March 2004, the Managing Shareholder, for itself and for the Trust and its affiliates adopted a Code of Ethics applicable to the principal executive officer, principal financial officer, principal accounting officer or controller (or any persons performing similar functions), of each such entity. A copy of the Code of Ethics is filed as Exhibit 14 to this Annual Report on Form 10-K.

ITEM 11.  EXECUTIVE COMPENSATION

The executive officers of the Trust do not receive compensation directly from the Trust or any of its subsidiaries. They provide managerial services to the Trust. The Managing Shareholder, or affiliated management companies, determines and pays the compensation of these officers. Each of the executive officers of the Trust also serves as an executive officer of the Managing Shareholder and other trusts managed by the Managing Shareholder and its affiliates.

The Managing Shareholder is entitled to receive management fees from the Trust and may determine to use a portion of the proceeds from the management fee to pay compensation to executive officers of the Trust. See Item 13. “Certain Relationships and Related Transactions” for more information regarding Managing Shareholder compensation and payments to affiliated entities.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS

The following table sets forth information with respect to the beneficial ownership of the Trust’s Investor Shares as of December 31, 2005 (no person owns more than 5%) by:

· each executive officer (there are no directors) of the Trust; and

· all of the executive officers of the Trust as a group.

Beneficial ownership is determined in accordance with SEC rules and includes voting or investment power with respect to the securities. Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all Investor Shares shown as beneficially owned by them. Percentage of beneficial ownership is based on 391.8444 Investor Shares outstanding at December 31, 2005. Other than as set forth below, no officer of the Trust owns any shares of the Trust.

Name of beneficial owner	Number of shares (1)	Percent
Ridgewood Renewable Power LLC (Managing Shareholder)        Robert E. Swanson,  controlling member	1	*
Executive officers as a group	1	*

*           Represents less than one percent.

(1) Does not include a Management Share in the Trust representing the beneficial interests and management rights of the Managing Shareholder in its capacity as the Managing Shareholder. The management share owned by the Managing Shareholder is the only issued and outstanding management share of the Trust. The management rights of the Managing Shareholder are described in further detail in Item 1. “Business”. 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. “Certain Relationships and Related Transactions”.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Under the terms of the Trust’s Management Agreement, the Managing Shareholder provides certain management, administrative and advisory services, and office space to the Trust. In return, the Trust is obligated to pay the Managing Shareholder an annual management fee equal to 2.5% of the Trusts’ prior year net asset value which equaled $354,000 $363,000 and $336,000 for the years ended December 31, 2005, 2004 and 2003, respectively, as compensation for such services. The management fee is to be paid in monthly installments and, to the extent that the Trust does not pay the management fee on a timely basis, the Trust accrues interest at an annual rate of 10% on the unpaid balance.

27

For the years ended December 31, 2005, 2004 and 2003, the Trust accrued interest expense of $7,000, $6,000 and $5,000, respectively, on accrued but unpaid management fees. The interest accrued was waived by the Managing Shareholder and recorded as capital contribution in the period waived.  Additionally, the Managing Shareholder waived $72,000 of the 2005 management fee, which was also recorded as contributed capital.

Under the Management Agreement with the Managing Shareholder, Ridgewood Power Management (“RPM”), an entity related to the Managing Shareholder through common ownership, provides management, purchasing, engineering, planning and administrative services to the projects operated by the Fund. RPM charges the projects at its cost for these services and for the allocable amount of certain overhead items. Allocations of costs are on the basis of identifiable direct costs or in proportion to amounts invested in projects managed by RPM. During the years ended December 31, 2005, 2004 and  2003, RPM charged the projects approximately $250,000, $248,000 and $270,000, respectively, for overhead items allocated in proportion to the amount invested in projects managed. In addition, RPM charged the Trust projects approximately $3,669,000, $4,690,000 and $5,430,000, respectively, for all of the direct operating and non-operating expenses incurred during such periods.

The shareholders of the Trust other than the Managing Shareholder were allocated 99% of each contribution and the Managing Shareholder was allocated 1% so that the amount of the contribution allocated offset the amount of the expense initially accrued.

Under the Declaration of Trust, the Managing Shareholder is entitled to receive, concurrently with the shareholders of the Trust other than the Managing Shareholder, 1% of all distributions from operations made by the Trust in a year until the shareholders have received distributions in that year equal to 14% of their equity contribution. Thereafter, the Managing Shareholder is entitled to receive 20% of the distributions for the remainder of the year. The Managing Shareholder is entitled to receive 1% of the proceeds from dispositions of Trust property until the shareholders other than the Managing Shareholder, 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. Distributions to the Managing Shareholder were $20,000, $22,000 and $12,000 for each of the three years ended December 31, 2005, 2004 and 2003, respectively. The Trust has not yet reached Payout.

Income is allocated to the Managing Shareholder until the profits so allocated equal distributions to the Managing Shareholder. Thereafter, income is allocated among the shareholders other than the Managing Shareholder in proportion to their ownership of Investor Shares. If the Trust has net losses for a fiscal period, the losses are allocated 99% to the shareholders other than the Managing Shareholder and 1% to the Managing Shareholder, subject to certain limitations as set forth in the Declaration of Trust. Amounts allocated to shareholders other than the Managing Shareholder are apportioned among them in proportion to their capital contributions.

Under the terms of the Declaration of Trust, if the Adjusted Capital Account (as defined in the Declaration of Trust) of a shareholder other than the Managing Shareholder would become negative using General Allocations (as defined in the Declaration of Trust), losses and expenses will be allocated to the Managing Shareholder. Should the Managing Shareholder’s Adjusted Capital Account become negative and items of income or gain occur, then such items of income or gain will be allocated entirely to the Managing Shareholder until such time as the Managing Shareholder’s Adjusted Capital Account becomes positive. This mechanism does not change the allocation of cash, as discussed above.

On June 26, 2003, the Managing Shareholder entered into a Revolving Credit and Security Agreement with Wachovia Bank, National Association. The agreement, as amended, allows the Managing Shareholder to obtain loans and letters of credit of up to $6,000,000 for the benefit of the Trust and trusts that it manages. As part of the agreement, the Trust agreed to limitations on its ability to incur indebtedness, liens and to provide guarantees.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees and services rendered by Grant Thornton LLP, the Trust’s principal accountant, for the years ended December 31, 2005, 2004 and 2003 (in thousands).

	2005		2004		2003
Audit Fees*	$	167	$	133	$	133
Audit-Related Fees		-		-		-
Tax Fees		-		-		-
All Other Fees		-		-		-
Total	$	167	$	133	$	133
* These fees are being borne by the Managing Shareholder.

The above table excludes fees for services rendered by Perelson Weiner LLP, the Trust’s original principal accountant for the Trust’s 2003 audit. Total fees for services rendered by Perelson Weiner LLP for the Trust’s original 2003 audit and for 2003 tax services total $35,000 and $38,000, respectively.

28

Audit Committee Pre-Approval Policy

The Managing Shareholder pre-approves on an annual basis all audit and permitted non-audit services that may be performed by the Trust’s independent registered public accounting firm, including the audit engagement terms and fees, and also pre-approves any detailed types of audit-related and permitted tax services to be performed during the year. The Managing Shareholder pre-approves permitted non-audit services on an engagement-by-engagement basis.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)           Financial Statements

See the Index to Financial Statements on page F-1 of this report.

(b)           Exhibits

Exhibits required by Section 601 of Regulation S-K:

Exhibit No.			Description
3	(i)(A)		Certificate of Trust of the Registrant (incorporated by reference to the Registrant’s Registration Statement filed with the SEC on February 15, 1994).
3	(i)(B)	*	Certificate of Amendment to the Certificate of Trust of the Registrant filed with Delaware Secretary of State on December 18, 2003.
3	(ii)(A)		Declaration of Trust of the Registrant (incorporated by reference to the Registrant’s Registration Statement filed with the SEC on February 15, 1994).
3	(ii)(B)	*	Declaration of Trust of the Registrant (as amended and restated).
3	(ii)(C)		Amendment No. 1 to Declaration of Trust of the Registrant (incorporated by reference to Exhibit A of the Registrant’s Proxy Statement filed with the SEC on November 5, 2001, SEC File No. 814-00134)
3	(ii)(D)	*	Amendment to the Amended Declaration of Trust of the Registrant effective January 1, 2005.
10.1		#	Management Agreement between the Trust and Managing Shareholder, dated January 3, 1994 (incorporated by reference to the Registrant’s Registration Statement filed with the SEC on February 15, 1994).
10.2		*	Long-Term Energy and Capacity Power Purchase Agreement between Byron Power Partners and Pacific Gas and Electric Company dated April 1985 (as amended).
10.3		*	Long-Term Energy and Capacity Power Purchase Agreement between JRW Associates L.P., as successor in interest, and Pacific Gas and Electric Company dated December 1985 (as amended).
10.4		*	Power Purchase Agreement between New England Power Company and Ridgewood Providence Power Partners, as successor in interest, dated November 1987 (as amended).

29

Exhibit No.		Description
14		Code of Ethics, adopted on March 1, 2004 (incorporated by reference to the Annual Report on Form 10-K filed by The Ridgewood Power Growth Fund with the SEC on March 1, 2006).
21	*	Subsidiaries of the Registrant.
31.1	*	Certification of Randall D. Holmes, Chief Executive Officer of the Registrant, pursuant to Securities Exchange Act Rule 13a-14(a).
31.2	*	Certification of Jeffrey H. Strasberg, Chief Financial Officer of the Registrant, pursuant to Securities Exchange Act Rule 13a-14(a).
32	*	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, signed by Randall D. Holmes, Chief Executive Officer of the Registrant, and Jeffrey H. Strasberg, Chief Financial Officer of the Registrant.
99.1	*	Financial statements of Ridgewood Providence Power Partners, L.P.

_____________________

* Filed herewith.

# A management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 15(a)(3) of Form 10-K.

(c)           Financial Statement Schedules

See Financial Statements and accompanying notes included in this report.

30

SIGNATURES

Pursuant to the requirements 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
Date: December 13, 2007	By:	/s/ Randall D. Holmes
		Randall D. Holmes
		Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/s/ Randall D. Holmes	Chief Executive Officer	December 13, 2007
Randall D. Holmes	(Principal Executive Officer)
/s/ Jeffrey H. Strasberg	Executive Vice President and Chief Financial Officer	December 13, 2007
Jeffrey H. Strasberg	(Principal Financial and Accounting Officer)
RIDGEWOOD RENEWABLE POWER LLC (Managing Shareholder) By: /s/ Randall D. Holmes	Chief Executive Officer of Managing Shareholder	December 13, 2007
Randall D. Holmes

31

RIDGEWOOD ELECTRIC POWER TRUST III

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets at December 31, 2005, 2004 and 2003	F-3
Consolidated Statements of Operations for the three years ended December 31, 2005	F-4
Consolidated Statements of Changes in Shareholders’ Equity (Deficit)
for the three years ended December 31, 2005	F-5
Consolidated Statements of Cash Flows for the three years ended December 31, 2005	F-6
Consolidated Balance Sheets (unaudited) at September 30, 2005, June 30, 2005,
March 31, 2005	F-7
Consolidated Balance Sheets (unaudited) at September 30, 2004, June 30, 2004, March 31, 2004	F-8
Consolidated Balance Sheets (unaudited) at September 30, 2003, June 30, 2003, March 31, 2003	F-9
Consolidated Statements of Operations (unaudited) for the nine and three months ended
September 30, 2005, 2004 and 2003	F-10
Consolidated Statements of Operations (unaudited) for the six and three months ended
June 30, 2005, 2004 and 2003	F-11
Consolidated Statements of Operations (unaudited) for the three months ended
March 31, 2005, 2004 and 2003	F-12
Consolidated Statements of Changes in Shareholders’ Equity (Deficit) (unaudited) for the three months,
six months and nine months ended March 31, June 30, September 30, for 2003, 2004 and 2005	F-13
Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2005,
2004 and 2003	F-14
Consolidated Statements of Cash Flows (unaudited) for the six months ended June 30, 2005,
2004 and 2003	F-15
Consolidated Statements of Cash Flows (unaudited) for the three months ended March 31, 2005,
2004 and 2003	F-16
Notes to Consolidated Financial Statements	F-17

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Managing Shareholder and Shareholders

        Ridgewood Electric Power Trust III

We have audited the accompanying consolidated balance sheets of Ridgewood Electric Power Trust III (a Delaware trust) and subsidiaries as of December 31, 2005, 2004 and 2003, and the related consolidated statements of operations, changes in shareholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2005. 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 audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement.  The Trust is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide 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 as of December 31, 2005, 2004, and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements as of and for the year ended December 31, 2003 have been restated as discussed in Note 2 to the consolidated financial statements.

/s/ GRANT THORNTON LLP

Edison, New Jersey

December 13, 2007

F-2

Ridgewood Electric Power Trust III

Consolidated Balance Sheets

(in thousands, except share data)

	December 31,
	2005			2004			2003
							(Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	303		$	120		$	46
Accounts receivable		894			504			457
Notes receivable - current portion		70			54			60
Due from affiliates		670			745			860
Assets held for sale		-			-			484
Gas forward contract - current portion		2,482			1,269			575
Other current assets		89			115			104
Total current assets		4,508			2,807			2,586
Investment		4,633			5,070			5,489
Plant and equipment, net		3,594			4,585			5,016
Intangibles, net		1,004			1,076			1,148
Notes receivable - noncurrent portion		-			47			86
Gas forward contract - noncurrent portion		-			854			536
Other assets		-			14			14
Total assets	$	13,739		$	14,453		$	14,875
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	103		$	221		$	276
Due to affiliates		4			83			96
Total current liabilities		107			304			372
Commitments and contingencies
Shareholders’ equity (deficit):
Shareholders’ equity (391.8444 Investor Shares issued and
outstanding)		13,827			14,339			14,689
Managing shareholder’s accumulated deficit
(1 management share issued and outstanding)		(195	)		(190	)		(186	)
Total shareholders’ equity		13,632			14,149			14,503
Total liabilities and shareholders’ equity	$	13,739		$	14,453		$	14,875

The accompanying notes are an integral part of these financial statements.

F-3

Ridgewood Electric Power Trust III

Consolidated Statement of Operations

(in thousands, except per share data)

	Years Ended December 31,
	2005			2004			2003
							(Restated)
Revenues	$	4,205		$	5,594		$	5,909
Cost of revenues		2,705			4,293			3,740
Gross profit		1,500			1,301			2,169
Operating expenses:
General and administrative expenses		251			166			246
Impairment of plant and equipment		550			100			143
Management fee to the Managing Shareholder		354			363			336
Total operating expenses		1,155			629			725
Income from operations		345			672			1,444
Other income (expense):
Interest income		7			7			13
Interest expense		(15	)		(6	)		(16	)
Equity in income from investment		1,021			1,150			574
Other (expense) income, net		(5	)		(6	)		244
Total other income, net		1,008			1,145			815
Net income	$	1,353		$	1,817		$	2,259
Managing Shareholder - Net income	$	14		$	18		$	23
Shareholders - Net income		1,339			1,799			2,236
Net income per Investor Share		3,418			4,592			5,707

The accompanying notes are an integral part of these financial statements.

F-4

Ridgewood Electric Power Trust III

Consolidated Statements of Changes in Shareholders' Equity (Deficit)

Years Ended December 31, 2005, 2004 and 2003

(in thousands)

				Managing			Total Shareholders'
	Shareholders			Shareholder			Equity
Shareholders' balance January 1, 2003,  restated	$	13,624		$	(197	)	$	13,427
Net income, restated		2,236			23			2,259
Distributions		(1,176	)		(12	)		(1,188	)
Capital contributions		5			-			5
Shareholders' balance December 31, 2003, restated		14,689			(186	)		14,503
Net income		1,799			18			1,817
Distributions		(2,155	)		(22	)		(2,177	)
Capital contributions		6			-			6
Shareholders' balance December 31, 2004		14,339			(190	)		14,149
Net income		1,339			14			1,353
Distributions		(1,929	)		(20	)		(1,949	)
Capital contributions		78			1			79
Shareholders' balance December 31, 2005	$	13,827		$	(195	)	$	13,632

The accompanying notes are an integral part of these financial statements.

F-5

Ridgewood Electric Power Trust III

Consolidated Statements of Cash Flows

(in thousands)

	Years Ended December 31,
	2005			2004			2003
							(Restated)
Cash flows from operating activities:
Net income	$	1,353		$	1,817		$	2,259
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		512			532			644
Impairment of plant and equipment		550			100			143
Equity in income from investment		(1,021	)		(1,150	)		(574	)
Distributions from investment		1,458			1,569			676
Gas forward contract		(359	)		(1,011	)		(1,924	)
Waiver of management fees and related interest		79			6			5
Loss on disposal of equipment		-			4			-
Change in operating assets and liabilities:
Restricted cash		-			-			100
Accounts receivable		(390	)		(47	)		24
Due to/from affiliates, net		(4	)		101			(766	)
Other current assets		28			(11	)		34
Other assets		14			-			556
Accounts payable and accrued expenses		(119	)		(54	)		(668	)
Total adjustments		748			39			(1,750	)
Net cash provided by operating activities		2,101			1,856			509
Cash flows from investing activities:
Proceeds from the sale of equipment		-			384			266
Proceeds from notes receivable		31			45			79
Capital expenditures		-			(34	)		-
Net cash provided by investing activities		31			395			345
Cash flows from financing activities:
Cash distributions to shareholders		(1,949	)		(2,177	)		(1,188	)
Net increase (decrease) in cash and cash equivalents		183			74			(334	)
Cash and cash equivalents, beginning of year		120			46			380
Cash and cash equivalents, end of year	$	303		$	120		$	46
Supplemental disclosure of cash flow information:
Interest paid	$	15		$	6		$	16

The accompanying notes are an integral part of these financial statements.

F-6

Ridgewood Electric Power Trust III

Consolidated Balance Sheets (unaudited)

(in thousands, except share data)

	2005
	September			June 30			March 31
ASSETS
Current assets:
Cash and cash equivalents	$	424		$	280		$	1
Accounts receivable		796			710			472
Notes receivable - current portion		76			57			52
Due from affiliates		-			282			307
Gas forward contract - current portion		3,857			1,659			1,897
Other current assets		114			23			94
Total current assets		5,267			3,011			2,823
Investment		5,483			5,203			5,413
Plant and equipment, net		4,268			4,373			4,479
Intangibles, net		1,022			1,040			1,058
Notes receivable - noncurrent portion		-			26			36
Gas forward contract - noncurrent portion		-			708			1,008
Other assets		14			14			14
Total assets	$	16,054		$	14,375		$	14,831
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	344		$	289		$	399
Due to affiliates		228			557			318
Total current liabilities		572			846			717
Commitments and contingencies
Shareholders’ equity (deficit):
Shareholders’ equity (391.8444 Investor Shares issued and
outstanding)		15,658			13,725			14,304
Managing shareholder’s accumulated deficit
(1 management share issued and outstanding)		(176	)		(196	)		(190	)
Total shareholders’ equity		15,482			13,529			14,114
Total liabilities and shareholders’ equity	$	16,054		$	14,375		$	14,831

The accompanying notes are an integral part of these financial statements.

F-7

Ridgewood Electric Power Trust III

Consolidated Balance Sheets (unaudited)

(in thousands, except share data)

	2004
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	301		$	429		$	63
Accounts receivable		698			716			449
Notes receivable - current portion		38			43			47
Due from affiliates		639			121			266
Assets held for sale		-			-			384
Gas forward contract - current portion		1,509			802			857
Other current assets		145			84			99
Total current assets		3,330			2,195			2,165
Investment		5,199			6,013			5,770
Plant and equipment, net		4,699			4,807			4,910
Intangibles, net		1,094			1,112			1,130
Notes receivable - noncurrent portion		65			70			83
Gas forward contract - noncurrent portion		1,247			1,561			1,088
Other assets		14			14			14
Total assets	$	15,648		$	15,772		$	15,160
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	228		$	262		$	247
Due to affiliates		87			556			127
Total current liabilities		315			818			374
Commitments and contingencies
Shareholders’ equity (deficit):
Shareholders’ equity (391.8444 Investor Shares issued and
outstanding)		15,511			15,135			14,969
Managing shareholder’s accumulated deficit
(1 management share issued and outstanding)		(178	)		(181	)		(183	)
Total shareholders’ equity		15,333			14,954			14,786
Total liabilities and shareholders’ equity	$	15,648		$	15,772		$	15,160

The accompanying notes are an integral part of these financial statements.

F-8

Ridgewood Electric Power Trust III

Consolidated Balance Sheets (unaudited)

(in thousands, except share data)

	2003
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	280		$	54		$	111
Restricted cash		16			16			16
Accounts receivable		866			830			245
Notes receivable - current portion		59			71			82
Due from affiliates		311			272			359
Assets held for sale		678			-			-
Gas forward contract - current portion		266			529			311
Other current assets		155			36			140
Total current assets		2,631			1,808			1,264
Investment		5,473			5,873			5,801
Plant and equipment, net		5,188			6,098			6,243
Intangibles, net		1,166			1,184			1,202
Notes receivable - noncurrent portion		97			104			112
Gas forward contract - noncurrent portion		280			699			-
Other assets		570			570			570
Total assets	$	15,405		$	16,336		$	15,192
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	243		$	427		$	176
Due to affiliates		287			450			420
Total current liabilities		530			877			596
Gas forward contract		-			-			132
Total liabilities		530			877			728
Commitments and contingencies
Shareholders’ equity (deficit):
Shareholders’ equity (391.8444 Investor Shares issued and
outstanding)		15,057			15,635			14,651
Managing shareholder’s accumulated deficit
(1 management share issued and outstanding)		(182	)		(176	)		(187	)
Total shareholders’ equity		14,875			15,459			14,464
Total liabilities and shareholders’ equity	$	15,405		$	16,336		$	15,192

The accompanying notes are an integral part of these financial statements.

F-9

Ridgewood Electric Power Trust III
Consolidated Statements of Operations (unaudited)
(in thousands, except per share data)

	Nine Months Ended September 30,								Three Months Ended September 30,
	2005		2004			2003			2005			2004			2003
			(Restated)			(Restated)						(Restated)			(Restated)
Revenues	$	4,068	$	4,269		$	4,843		$	1,750		$	1,791		$	2,137
Cost of revenues		1,630		2,314			2,754			(451	)		970			2,259
Gross profit (loss)		2,438		1,955			2,089			2,201			821			(122	)
Operating expenses:
General and administrative expenses		205		154			178			47			11			44
Impairment of plant and equipment		-		100			88			-			-			88
Management fee to the Managing Shareholder		265		276			252			88			92			84
Total operating expenses		470		530			518			135			103			216
Income (loss) from operations		1,968		1,425			1,571			2,066			718			(338	)
Other income (expense):
Interest income		6		9			9			1			2			2
Interest expense		-		-			(11	)		-			-			(1	)
Equity in income from investment		839		929			430			280			405			148
Other income (expense), net		4		(49	)		239			2			(52	)		-
Total other income, net		849		889			667			283			355			149
Net income (loss)	$	2,817	$	2,314		$	2,238		$	2,349		$	1,073		$	(189	)
Managing Shareholder - Net income (loss)	$	28	$	23		$	22		$	23		$	11		$	(2	)
Shareholders - Net income (loss)		2,789		2,291			2,216			2,326			1,062			(187	)
Net income (loss) per Investor Share		7,119		5,847			5,655			5,936			2,710			(476	)

The accompanying notes are an integral part of these financial statements.

F-10

Ridgewood Electric Power Trust III

Consolidated Statements of Operations (unaudited)

(in thousands, except per share data)

	Six Months Ended June 30,								Three Months Ended June 30,
	2005			2004		2003			2005			2004		2003
				(Restated)		(Restated)						(Restated)		(Restated)
Revenues	$	2,318		$	2,478	$	2,706		$	1,354		$	1,380	$	1,742
Cost of revenues		2,081			1,344		496			1,585			927		315
Gross profit (loss)		237			1,134		2,210			(231	)		453		1,427
Operating expenses:
General and administrative expenses		158			144		133			88			47		23
Impairment of plant and equipment		-			100		-			-			-		-
Management fee to the Managing Shareholder		177			184		168			88			92		84
Total operating expenses		335			428		301			176			139		107
(Loss) income from operations		(98	)		706		1,909			(407	)		314		1,320
Other income (expense):
Interest income		5			7		6			1			2		2
Interest expense		-			-		(10	)		-			-		(5	)
Equity in income from investment		559			524		282			216			243		73
Other income, net		2			4		240			-			3		-
Total other income, net		566			535		518			217			248		70
Net income (loss)	$	468		$	1,241	$	2,427		$	(190	)	$	562	$	1,390
Managing Shareholder - Net income (loss)	$	5		$	12	$	24		$	(2	)	$	6	$	14
Shareholders - Net income (loss)		463			1,229		2,403			(188	)		556		1,376
Net income (loss) per Investor Share		1,183			3,136		6,131			(479	)		1,422		3,547

The accompanying notes are an integral part of these financial statements.

F-11

Ridgewood Electric Power Trust III

Consolidated Statements of Operations (unaudited)

(in thousands, except per share data)

	Three Months Ended March 31,
	2005		2004		2003
			(Restated)		(Restated)
Revenues	$	964	$	1,097	$	964
Cost of revenues		496		417		181
Gross profit		468		680		783
Operating expenses:
General and administrative expenses		71		97		110
Impairment of plant and equipment		-		100		-
Management fee to the Managing Shareholder		88		92		84
Total operating expenses		159		289		194
Income from operations		309		391		589
Other income (expense):
Interest income		3		5		4
Interest expense		-		-		(5	)
Equity in income from investment		343		281		209
Other income, net		3		2		240
Total other income, net		349		288		448
Net income	$	658	$	679	$	1,037
Managing Shareholder - Net income	$	7	$	7	$	10
Shareholders - Net income		651		672		1,027
Net income per Investor Share		1,662		1,712		2,621

The accompanying notes are an integral part of these financial statements.

F-12

Ridgewood Electric Power Trust III

Consolidated Statement of Changes in Shareholders' Equity (Deficit)

Three Months, Six Months and Nine Months Ended March, June and September for 2003, 2004 and 2005 (unaudited)

(in thousands)

				Managing			Total Shareholders'
	Shareholders			Shareholder			Equity
Three months ended 03/31/03:
Shareholders' balance January 1, 2003,  restated	$	13,624		$	(197	)	$	13,427
Net income, restated		1,027			10			1,037
Shareholders' balance March 31, 2003, restated	$	14,651		$	(187	)	$	14,464
Six months ended 06/30/03:
Shareholders' balance January 1, 2003,  restated	$	13,624		$	(197	)	$	13,427
Net income, restated		2,403			24			2,427
Distributions		(392	)		(3	)		(395	)
Shareholders' balance June 30, 2003, restated	$	15,635		$	(176	)	$	15,459
Nine months ended 09/30/03:
Shareholders' balance January 1, 2003,  restated	$	13,624		$	(197	)	$	13,427
Net income, restated		2,216			22			2,238
Distributions		(783	)		(7	)		(790	)
Shareholders' balance September 30, 2003, restated	$	15,057		$	(182	)	$	14,875
Three months ended 03/31/04:
Shareholders' balance January 1, 2004,  restated	$	14,689		$	(186	)	$	14,503
Net income, restated		672			7			679
Distributions		(392	)		(4	)		(396	)
Shareholders' balance March 31, 2004, restated	$	14,969		$	(183	)	$	14,786
Six months ended 06/30/04:
Shareholders' balance January 1, 2004,  restated	$	14,689		$	(186	)	$	14,503
Net income, restated		1,229			12			1,241
Distributions		(783	)		(7	)		(790	)
Shareholders' balance June 30, 2004, restated	$	15,135		$	(181	)	$	14,954
Nine months ended 09/30/04:
Shareholders' balance January 1, 2004,  restated	$	14,689		$	(186	)	$	14,503
Net income, restated		2,291			23			2,314
Distributions		(1,469	)		(15	)		(1,484	)
Shareholders' balance September 30, 2004, restated	$	15,511		$	(178	)	$	15,333
Three months ended 03/31/05:
Shareholders' balance January 1, 2005	$	14,339		$	(190	)	$	14,149
Net income		651			7			658
Distributions		(686	)		(7	)		(693	)
Shareholders' balance March 31, 2005	$	14,304		$	(190	)	$	14,114
Six months ended 06/30/05:
Shareholders' balance January 1, 2005	$	14,339		$	(190	)	$	14,149
Net income		463			5			468
Distributions		(1,077	)		(11	)		(1,088	)
Shareholders' balance June 30, 2005	$	13,725		$	(196	)	$	13,529
Nine months ended 09/30/05:
Shareholders' balance January 1, 2005	$	14,339		$	(190	)	$	14,149
Net income		2,789			28			2,817
Distributions		(1,470	)		(14	)		(1,484	)
Shareholders' balance September 30, 2005	$	15,658		$	(176	)	$	15,482

The accompanying notes are an integral part of these financial statements.

F-13

Ridgewood Electric Power Trust III

Consolidated Statements of Cash Flows (unaudited)

(in thousands)

	Nine Months Ended September 30,
	2005			2004			2003
				(Restated)			(Restated)
Cash flows from operating activities:
Net income	$	2,817		$	2,314		$	2,238
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		371			374			486
Impairment of plant and equipment		-			100			88
Equity in income from investment		(839	)		(929	)		(430	)
Distributions from investment		426			1,219			549
Gas forward contract		(1,734	)		(1,645	)		(1,359	)
Change in operating assets and liabilities:
Restricted cash		-			-			84
Accounts receivable		(292	)		(241	)		(385	)
Due to/from affiliates, net		890			212			(26	)
Other current assets		1			(41	)		-
Other assets		-			-			(17	)
Accounts payable and accrued expenses		123			(60	)		(701	)
Total adjustments		(1,054	)		(1,011	)		(1,711	)
Net cash provided by operating activities		1,763			1,303			527
Cash flows from investing activities:
Proceeds from the sale of equipment		-			398			95
Proceeds from notes receivable		25			43			68
Capital expenditures		-			(5	)		-
Net cash provided by investing activities		25			436			163
Cash flows from financing activities:
Cash distributions to shareholders		(1,484	)		(1,484	)		(790	)
Net increase (decrease) in cash and cash equivalents		304			255			(100	)
Cash and cash equivalents, beginning of period		120			46			380
Cash and cash equivalents, end of period	$	424		$	301		$	280
Supplemental disclosure of cash flow information:
Interest paid	$	-		$	-		$	11

The accompanying notes are an integral part of these financial statements.

F-14

Ridgewood Electric Power Trust III

Consolidated Statements of Cash Flows (unaudited)

(in thousands)

	Six Months Ended June 30,
	2005			2004			2003
				(Restated)			(Restated)
Cash flows from operating activities:
Net income	$	468		$	1,241		$	2,427
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization		248			249			313
Impairment of plant and equipment		-			100			-
Equity in income from investment		(559	)		(524	)		(282	)
Distributions from investment		426			-			-
Gas forward contract		(244	)		(1,253	)		(2,041	)
Change in operating assets and liabilities:
Restricted cash		-			-			84
Accounts receivable		(206	)		(259	)		(337	)
Due to/from affiliates, net		937			1,199			175
Other current assets		92			20			102
Accounts payable and accrued expenses		68			(14	)		(517	)
Total adjustments		762			(482	)		(2,503	)
Net cash provided by (used in) operating activities		1,230			759			(76	)
Cash flows from investing activities:
Proceeds from the sale of equipment		-			384			95
Proceeds from notes receivable		18			33			50
Capital expenditures		-			(3	)		-
Net cash provided by investing activities		18			414			145
Cash flows from financing activities:
Cash distributions to shareholders		(1,088	)		(790	)		(395	)
Net increase (decrease) in cash and cash equivalents		160			383			(326	)
Cash and cash equivalents, beginning of period		120			46			380
Cash and cash equivalents, end of period	$	280		$	429		$	54
Supplemental disclosure of cash flow information:
Interest paid	$	-		$	-		$	10

The accompanying notes are an integral part of these financial statements.

F-15

Ridgewood Electric Power Trust III

Consolidated Statements of Cash Flows (unaudited)

(in thousands)

	Three Months Ended March 31,
	2005			2004			2003
				(Restated)			(Restated)
Cash flows from operating activities:
Net income	$	658		$	679		$	1,037
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization		124			125			162
Impairment of plant and equipment		-			100			-
Equity in income from investment		(343	)		(281	)		(209	)
Gas forward contract		(782	)		(833	)		(992	)
Change in operating assets and liabilities:
Restricted cash		-			-			84
Accounts receivable		32			8			236
Due to/from affiliates, net		673			624			58
Other current assets		21			5			49
Accounts payable and accrued expenses		179			(29	)		(769	)
Total adjustments		(96	)		(281	)		(1,381	)
Net cash provided by (used in) operating activities		562			398			(344	)
Cash flows from investing activities:
Proceeds from the sale of equipment		-			-			45
Proceeds from notes receivable		12			15			30
Net cash provided by investing activities		12			15			75
Cash flows from financing activities:
Cash distributions to shareholders		(693	)		(396	)		-
Net (decrease) increase in cash and cash equivalents		(119	)		17			(269	)
Cash and cash equivalents, beginning of period		120			46			380
Cash and cash equivalents, end of period	$	1		$	63		$	111
Supplemental disclosure of cash flow information:
Interest paid	$	-		$	-		$	5

The accompanying notes are an integral part of these financial statements.

F-16

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

1.    DESCRIPTION OF BUSINESS

Ridgewood Electric Power Trust III (the “Trust”) was formed as a Delaware trust on December 6, 1993. The Trust began offering shares in January 1994 and concluded its offering in May 1995. The objective of the Trust is to provide benefits to its shareholders through a combination of distributions of operating cash flow and capital appreciation. The Managing Shareholder of the Trust is Ridgewood Renewable Power LLC (“RRP” or the “Managing Shareholder”). The Trust has been organized to invest primarily in power generation facilities located in the US. The projects of the Trusts have characteristics that qualify the projects for government incentives.

The Trust’s accompanying consolidated financial statements include the financial statements of its wholly-owned subsidiaries. The Trust’s consolidated financial statements also include the Trust’s 35.7% limited partnership interest in Ridgewood Providence Power Partners, L.P. (“Ridgewood Providence”) which is accounted for under the equity method of accounting as the Trust has the ability to exercise significant influence but does not control the investment’s operating and financial policies.

The Managing Shareholder performs (or arranges for the performance of) the operation and maintenance of the projects invested in by the Trust and the management and administrative services required for Trust operations. Among other services, the Managing Shareholder administers the accounts and handles relations with the shareholders, including tax and other financial information. The Managing Shareholder also provides the Trust with office space, equipment and facilities and other services necessary for its operation.

2.    RESTATEMENT OF FINANCIAL STATEMENTS

The Trust has identified a series of adjustments, including adjustments related to amortization of power purchase agreements, accrual of royalties, adjustments related to investments, accounting for professional services, accounting for gain on gas purchase contracts, overaccrual of revenues and cost of revenues, accounting for management fees and accounting for the waiver of related interest, which have resulted in the restatement of the previously issued financial statements for the quarters ended March 31, June 30, and September 30, 2003 and 2004, and for the year ended December 31, 2003.

The tables below present the changes in financial statement line items between the Trust’s previously reported and restated balance sheets and statements of operations.  These restatements did not have a significant impact on the Trust’s statements of cash flows. Explanatory comments follow the tables.

Balance Sheet
	December 31,
ASSETS	2003
Investment	$	(181	)	(A)
Gas forward contract - current portion		16		(C)
Gas forward contract - noncurrent portion		(159	)	(C)
Total assets	$	(324	)
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable and accrued expenses	$	(51	)	(B)
Due to affiliates		(67	)	(E)(F)
Shareholders’ equity		(206	)	(F)
Total liabilities and shareholders' equity	$	(324	)

F-17

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Statement of Operations
	December 31,
	2003
Revenues, decrease	$	1,349		(D)(F)
Cost of revenues, decrease		(3,259	)	(C)(D)(F)
General and administrative expenses, increase		12		(B)
Management fee to the Managing Shareholder, decrease		(21	)	(E)
Loss from operations, increase		(1,919	)
Interest expense, increase		6		(E)
Equity in income from investment, decrease		55		(A)
Other income (expense), net, increase		1,223		(F)
Net income, decrease	$	(635	)
Managing Shareholder - Net income, decrease	$	(6	)
Shareholders - Net income, decrease		(629	)
Net income per Investor Share, decrease		(1,605	)

(A) Originally, Ridgewood Providence did not properly account for amortization of a power purchase agreement as the Trust failed to properly accrue royalty expenses. The Trust recorded an adjustment to decrease its investment in Ridgewood Providence and shareholders’ equity by $126 at the beginning of 2003. In addition, the Trust recorded an adjustment to decrease its investment in Ridgewood Providence and equity income by $55 for the year ended December 31, 2003.

(B)  In the previously issued financial statements, the Trust incorrectly accrued professional service fees in the period to be audited or reviewed rather than during the period in which the services were performed. As a result, the Trust overaccrued $52 of professional fees for the year ended December 31, 2003. The 2003 overaccrual was adjusted by recording a decrease to accrued expenses of $51 and an increase to general and administrative expenses and beginning shareholders’ equity of $13 and $65, respectively.

(C) Originally, the Trust did not properly recognize the market value related to its gas forward contracts. As a result, the Trust recorded a liability value of $813 at the beginning of 2003 with a corresponding decrease to beginning shareholders’ equity. Additionally, the Trust did not properly record changes in the value of the contracts that occurred during 2003, and as a result the Trust recorded a gain of $672 as a component of cost of revenues.

(D) The Trust incorrectly accounted for electricity generated for two of its customers in its previously issued financial statements. The Trust was provided materials by these customers to produce electricity, which when produced, was sold to these same customers. In its previously issued financial statements, the Trust recorded the provided materials as a cost of revenues with a corresponding increase to revenues. While not affecting net operating results, the Trust has determined that this accounting was not proper and that revenues and cost of revenues were overstated by the value of the supplied materials.  The Trust adjusted the overstatement by reducing revenues and cost of revenues by $877 for the year ended December 31, 2003.

(E)  Originally, the Trust did not properly record the accrual of management fees (including the associated interest thereon) due by the Trust to the Managing Shareholder. The Trust made adjustments by recording an accrual of the management fee expense in the period to which the accrual applied and any waiver or forgiveness of interest on unpaid management fees was treated as a capital contribution to the Trust by the Managing Shareholder. The contribution of the Managing Shareholder was also reallocated to the shareholders of the Trust in such a way as to keep the capital accounts of the shareholders in the Trust in the same relationship to each other as they had been prior to the contribution of the management fee by the Managing Shareholder. In 2003, the Trust recorded this adjustment by increasing interest expense and shareholders’ equity by $6 and decreasing due to affiliates and management fee by $21.  

(F) Certain items in the previously issued financial statements for the years ended December 31, 2003 have been reclassified to conform to the current year presentation. These reclassifications had no effect on net income.

F-18

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

The Trust restated 2002 amounts by decreasing the Trust’s beginning shareholders’ equity as of January 1, 2003 by $798. The adjustments recorded that were made to the Trust’s equity as of January 1, 2003 consisted of an understatement of accumulated amortization of electric power sales contract of $126 and valuation of gas forward contracts of $672.

Quarterly Balance Sheets (unaudited)	2004
	September 30			June 30			March 31
ASSETS
Cash and cash equivalents	$	-		$	9		$	-		(F)
Investment		(151	)		(141	)		(169	)	(A)
Gas forward contract - current portion		(439	)		254			356		(C)
Gas forward contract - noncurrent portion		(197	)		(499	)		(264	)	(C)
Total assets	$	(787	)	$	(377	)	$	(77	)
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable and accrued expenses	$	(23	)	$	4		$	2		(B)
Due to affiliates		(63	)		(55	)		(63	)	(D)(E)(F)
Shareholders’ equity		(701	)		(326	)		(16	)	(F)
Total liabilities and shareholders’ equity	$	(787	)	$	(377	)	$	(77	)

	2003
	September 30			June 30			March 31
ASSETS
Due from affiliates	$	-		$	9		$	5		(E)(F)
Investment		(138	)		(139	)		(128	)	(A)
Gas forward contract - current portion		(130	)		529			311		(C)
Gas forward contract - noncurrent portion		24			699			-		(C)
Total assets	$	(244	)	$	1,098		$	188
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable and accrued expenses	$	(26	)	$	(13	)	$	1		(B)
Due to affiliates		(57	)		(43	)		(42	)	(D)(E)(F)
Loss on gas purchase contract - noncurrent portion		-			-			132		(C)
Shareholders’ equity		(161	)		1,154			97		(F)
Total liabilities and shareholders’ equity	$	(244	)	$	1,098		$	188

F-19

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Quarterly Statements of Operations (unaudited)	Nine Months Ended September 30,						Three Months Ended September 30,
	2004			2003			2004			2003
Revenues, decrease	$	(729	)	$	(1,100	)	$	(226	)	$	(229	)	(D)(F)
Cost of revenues, decrease (increase)		2,367			2,455			617			(451	)	(C)(D)(F)
General and administrative expenses, (increase) decrease		(47	)		(31	)		17			8		(B)(F)
Management fee to the Managing Shareholder, increase		-			16			-			5		(E)
Income (loss) from operations, (decrease) increase		1,591			1,340			408			(667	)
Gain on gas purchase contract, decrease		(2,137	)		(653	)		(783	)		(653	)	(C)(F)
Equity in income from investment, increase (decrease)		30			(12	)		(10	)		1		(A)
Other income (expense), net, decrease		21			8			11			3		(F)
Net (loss) income, (decrease) increase	$	(495	)	$	683		$	(374	)	$	(1,316	)
Managing Shareholder - Net (loss) income, (decrease) increase	$	(5	)	$	6		$	(4	)	$	(13	)
Shareholders - Net (loss) income, (decrease) increase		(490	)		677			(370	)		(1,303	)
Net (loss) income per Investor Share, (decrease) increase		(1,250	)		1,727			(943	)		(3,326	)

	Six Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Revenues, decrease	$	(503	)	$	(870	)	$	(235	)	$	(187	)	(D)(F)
Cost of revenues, decrease (increase)		1,749			2,905			655			1,233		(C)(D)(F)
General and administrative expenses, (increase) decrease		(65	)		(38	)		(7	)		12		(B)(F)
Management fee to the Managing Shareholder, decrease		-			10			-			5		(E)
Income from operations, increase		1,181			2,007			413			1,063
Gain on gas purchase contract, decrease		(1,354	)		-			(755	)		-		(C)(F)
Equity in income from investment, increase (decrease)		40			(13	)		28			(11	)	(A)
Other income (expense), net, increase		11			6			5			2		(F)
Net (loss) income, (decrease) increase	$	(122	)	$	2,000		$	(309	)	$	1,054
Managing Shareholder - Net (loss) income, (decrease) increase	$	(1	)	$	20		$	(3	)	$	11
Shareholders - Net (loss) income, (decrease) increase		(121	)		1,980			(306	)		1,043
Net (loss) income per Investor Share, (decrease) increase		(310	)		5,053			(782	)		2,662

F-20

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

	Three Months Ended March 31,
	2004			2003
Revenues, decrease	$	(268	)	$	(684	)	(D)(F)
Cost of revenues, decrease		1,095			1,672		(C)(D)(F)
General and administrative expenses, increase		(57	)		(51	)	(B)(F)
Management fee to the Managing Shareholder, decrease		-			5		(E)
Income (loss) from operations, increase (decrease)		770			942
Gain on gas purchase contract, decrease		(598	)		-		(C)(F)
Equity in income from investment, increase (decrease)		12			(2	)	(A)
Other income (expense), net, increase		7			4		(F)
Net income, increase	$	191		$	944
Managing Shareholder - Net income, increase	$	2		$	9
Shareholders - Net income, increase		189			935
Net income per Investor Share, increase		482			2,386

(A) The Trust did not properly account for amortization of a power purchase agreement and failed to properly accrue royalty expenses for Ridgewood Providence. As a result, the Trust recorded the following adjustments (unaudited):

	2004									2003
		9/30			6/30			3/31			9/30			6/30			3/31
Equity in income from investments - increase (decrease)	$	30		$	40		$	12		$	(12	)	$	(13	)	$	(2	)
Beginning Shareholders' equity, decrease		(181	)		(181	)		(181	)		(126	)		(126	)		(126	)
Investments, decrease		(151	)		(141	)		(169	)		(138	)		(139	)		(128	)

 (B) The Trust corrected the method of recording professional service fees to record the fees in the periods during which the services were performed. As a result, the Trust recorded the following adjustments (unaudited):

	2004							2003
		9/30			6/30		3/31		9/30			6/30			3/31
Accounts payable and accrued expenses, (decrease) increase	$	(23	)	$	4	$	2	$	(26	)	$	(13	)	$	-
Beginning Shareholders' equity, increase		52			52		52		48			48			48
General and administrative expenses, increase		29			56		54		22			35			48

(C) The Trust did not properly account for the changes in the value of gas forward contracts. As a result, the Trust recorded the following adjustments (unaudited):

	2004									2003
		9/30			6/30			3/31			9/30			6/30			3/31
Gas forward contract - current portion	$	(876	)	$	255		$	356		$	(130	)	$	529		$	311
Gas forward contract - noncurrent portion, increase (decrease)		240			(499	)		(264	)		(23	)		699			(132	)
Beginning Shareholders' equity - (decrease) increase		(143	)		(143	)		(143	)		(813	)		(813	)		(813	)
Revenues, decrease		(729	)		(503	)		(268	)		(628	)		(399	)		(212	)
Cost of goods sold - (decrease) increase		(2,373	)		(1,756	)		(1,101	)		(1,941	)		(2,440	)		(1,204	)
Gas forward contract, decrease		(2,137	)		(1,354	)		(598	)		(653	)		-			-

F-21

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

(D) The Trust incorrectly accounted for capital contributions and related expenses. As a result, the Trust recorded the following adjustments (unaudited):

	2004									2003
		9/30			6/30			3/31			9/30			6/30			3/31
Due to affiliates, decrease	$	(41	)	$	(41	)	$	(41	)	$	(41	)	$	(41	)	$	(41	)
Beginning Shareholders' equity, decrease		45			45			45			45			45			45
Cost of revenues, increase		4			4			4			4			4			4

(E) Originally, the Trust did not properly record management fees and interest accrued on unpaid management fees to the Managing Shareholder. As a result, the Trust recorded the following adjustments (unaudited):

	2004									2003
		9/30			6/30			3/31			9/30			6/30			3/31
Due from  affiliates, decrease	$	(21	)	$	(21	)	$	(21	)	$	(16	)	$	(10	)	$	(5	)
Beginning Shareholders' equity, decrease		21			21			21			-			-			-
Management fee to the Managing Shareholders, decrease		-			-			-			(16	)		(10	)		(5	)

(F) Certain items in the previously issued financial statements for quarters ended September 30, June 30 and March 31, 2004 and 2003 have been reclassified to conform to the current quarters’ presentation. These reclassifications had no effect on net loss.

	2004						2003
		9/30		6/30		3/31		9/30		6/30		3/31
Due from affiliates - (decrease) increase	$	5	$	-	$	-	$	-	$	-	$	-
Due to affiliates (decrease) increase		5		9		-		-		-		(2	)
Cash and cash equivalents, (decrease) increase		-		9		-		-		-		-
Accounts payable and accrued expenses - (decrease)		-		-		-		-		-		2
Cost of goods sold - (decrease) increase		2		2		2		-		2		1
General and administrative expenses - increase (decrease)		18		9		4		9		3		3
Other income (expense) - increase (decrease)		20		11		6		9		5		4

3.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

a) Principles of Consolidation

The consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries.  All material intercompany transactions have been eliminated in consolidation.

The Trust uses the equity method of accounting for its investment in Ridgewood Providence since it is less than 50% owned and the Trust has the ability to exercise significant influence over its operating and financial policies. The Trust’s share of the operating results of Ridgewood Providence is included in the consolidated statements of operations.

b) 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, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, the Trust evaluates its estimates, including accounts receivable, investments, recoverable value of plant and equipment, intangibles 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 under different assumptions or conditions.

F-22

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

c) Revenue Recognition

Power generation revenue is recorded in the month of delivery, based on the estimated volumes sold to customers at rates stipulated in the power sales contract. Adjustments are made to reflect actual volumes delivered when the actual information subsequently becomes available. Billings to customers for power generation generally occurs during the month following delivery. Final billings do not vary significantly from estimates.

d) Cash and Cash Equivalents

The Trust considers all highly liquid investments with maturities, when purchased, of three months or less as cash and cash equivalents.  Cash and cash equivalents at December 31, 2005 consist of funds deposited in bank accounts. Cash balances with banks as of December 31, 2005, 2004 and 2003 exceed insured limits by approximately $203, $20 and $0, respectively.

e) Accounts Receivable

Accounts receivable are recorded at invoice price in the period the related revenues are earned, and do not bear interest. No allowance for bad debt expense was provided based upon historical write-off experience, evaluation of customer credit condition and the general economic status of the customer.

f) Plant and Equipment

Plant and equipment, consisting principally of electrical generating machinery and power generation facilities, are stated at cost less accumulated depreciation. Renewals and betterments that increase the useful lives of the assets are capitalized.  Repair and maintenance expenditures are expensed as incurred.  Upon retirement or disposal of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheets.  The difference, if any, between the net asset value and any proceeds from such retirement or disposal is recorded as a gain or loss in the statement of operations.

Depreciation is recorded using the straight-line method over the estimated useful lives of the assets.

Building	20 years
Machinery and equipment	5 to 7 years

g) Impairment of Long-Lived Assets and Intangibles

The Trust evaluates intangible assets and long-lived assets, such as plant and equipment, 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 estimated fair value of the asset, which is based on the estimated future cash flows discounted at the estimated cost of capital.  The analysis requires estimates of the amount and timing of projected cash flows and, where applicable, judgments associated with, among other factors, the appropriate discount rate.  Such estimates are critical in determining whether any impairment charge should be recorded and the amount of such charge if an impairment loss is deemed to be necessary.

h) 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 income tax returns of the individual shareholders of the Trust.

i) Comprehensive Income (Loss)

The Trust's comprehensive income (loss) consists only of net income (loss).

F-23

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

j) Significant Customer and Supplier

During 2005, 2004 and 2003, the Trust's largest customer accounted for 82%, 87% and 75% respectively, of total revenues. During 2005, 2004 and 2003, the Trust purchased substantially all of its gas supply from one supplier.

k) Fair Value of Financial Instruments

For the years ended December 31, 2005, 2004 and 2003, the carrying values of the Trust’s cash and cash equivalents, accounts and notes receivable, and accounts payable and accrued expenses approximate their fair values.

l) Gas Contracts

In August 2001, subsidiaries of the Trust entered into agreements to purchase natural gas, at fixed prices, over a five-year term in connection with entering into amendments fixing the sales price of electric power sales contracts for a similar term. These contracts were entered into in order to minimize the impact of fluctuating energy prices. The Trust has determined that these contracts are derivatives as defined under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. The Trust has designated these derivatives as non-hedge instruments. Accordingly, the value of the contracts based on the differences between contract prices and market value prices is recognized as an asset or a liability in the balance sheet. Changes in the carrying value of the contracts are reflected as a component of cost of revenues in the consolidated statements of operations.

m) Unaudited Interim Results

The unaudited interim consolidated financial statements included herein have been prepared on the same basis as the annual consolidated statements and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to present fairly the Trust’s financial position and its results of operations and cash flows for each of the interim periods presented. The financial data and other information disclosed in these notes to the consolidated financial statements related to such interim periods are also unaudited.

n) Recent Accounting Pronouncements

 SFAS 143 and FIN 47

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations, on the accounting for obligations associated with the retirement of long-lived assets. SFAS No. 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 No. 143 is effective for fiscal years beginning after June 15, 2002. Furthermore, in March 2005, the FASB issued FASB Interpretation No. 47 (“FIN 47”), Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, which clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143. Specifically, FIN 47 provides that an asset retirement obligation is conditional when the timing and/or method of settling the obligation is conditioned on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. This interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005.  The Trust adopted SFAS No. 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 Corrections. 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. SFAS No. 145 is effective for interim periods beginning after May 15, 2002.  The Trust adopted SFAS No. 145 effective January 1, 2003, with no material impact on the consolidated financial statements.

F-24

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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.  SFAS No. 146 is effective for fiscal years ending after December 31, 2002.  The Trust adopted SFAS No. 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, under certain circumstances, 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 during the fourth quarter of 2002 with no material impact to the consolidated financial statements.

FIN 46R

In January 2003, the FASB issued FASB Interpretation No. 46, 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, 2003, with no material impact to the consolidated financial statements.  In December 2003, the FASB issued a revision to FIN 46 (“FIN 46R”) to clarify some of the provisions and to exempt certain entities from its requirements.  The Trust implemented the full provisions of FIN 46R effective January 1, 2004, with no material impact on 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 No. 149 effective July 1, 2003, with no material impact on the consolidated financial statements.

SFAS 150

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for classifying and measuring certain financial instruments with characteristics of both liabilities and equity.  SFAS No. 150 is effective for interim periods beginning after June 15, 2003.  The Trust adopted SFAS No. 150 effective July 1, 2003, with no material impact on the consolidated financial statements.

SFAS 153

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29. The guidance in APB Opinion No. 29, Accounting for Nonmonetary Transactions (“Opinion 29”),is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in Opinion 29, however, included certain exceptions to that principle. This Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Trust adopted SFAS No. 153 effective June 15, 2005, with no material impact on the consolidated financial statements.

F-25

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

SFAS 154

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections.  SFAS No. 154 replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. This statement changes the requirements for the accounting for, and reporting of, a change in accounting principle and applies to all voluntary changes in accounting principle, as well as changes pursuant to accounting pronouncements that do not include transition rules.   Under SFAS No. 154, changes in accounting principle must be applied retrospectively to prior periods’ financial statements, or the earliest practicable date, as the required method for reporting a change in accounting principle.  The Trust adopted SFAS No. 154 effective December 15, 2005, and accordingly restated the consolidated financial statements, as described in Note 2.

4.    PROJECTS AND IMPAIRMENT OF LONG-LIVED ASSETS

JRW Associates, L.P.

In January 17, 1995, the Trust acquired 100% of the existing partnership interests of JRW Associates, L.P. (“San Joaquin”) which owns and operates an 8.5 megawatt (“MW”) electric cogeneration facility, located in Atwater, California.  The aggregate purchase price was $4,900, including transaction costs.

The acquisition of San Joaquin was accounted for as a purchase and the results of operations of San Joaquin 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, $1,400, was allocated to the Electric Power Sales Contract and is being amortized over the life of the contract (25 years).

Byron Power Partners, L.P.

In January 1995, the Trust caused the formation of Byron Power Partners, L.P. (“Byron”) in which the Trust owns 100% of the partnership interests.  On January 17, 1995, Byron acquired a 5.7MW electric cogeneration facility, located in Byron, California. The aggregate purchase price was $2,509, including transaction costs. The purchase price was allocated to the net assets acquired, based on their respective fair values.  Of the purchase price, $420 was allocated to the Electric Power Sales Contract and is being amortized over the life of the contract (25 years).

Ridgewood Mobile Power III, LLC

In the third quarter of 1999, the Trust purchased for $1,700, five mobile electric power generating units. During the third quarter of 2003, the Trust classified the mobile electric power generating units as held for sale and recorded $88 of impairment of equipment. The Trust sold one unit in the fourth quarter of 2003 for proceeds of $171. In 2004, the Trust recorded an impairment of $100 related to its electric power generating units. The remaining units were sold for proceeds of $384. The impairments were recorded to adjust the carrying value of the mobile electric power generating units to reflect their current estimated fair value.

Ridgewood AES Power Partners, LLC

In September 1997, the Trust formed a joint partnership, Ridgewood/AES Power Partners, L.P. with AES-NJ Cogen, Inc. (“AES-NJ”) to develop cogeneration projects. During 2003, The Trust sold its interest in the joint partnership for $100,000 cash, a $150,000 interest bearing promissory note ("promissory note"), and a $74,000 interest free note ("interest free note"). The promissory note bore interest at a rate of 10% per annum, and was fully paid monthly over a four year term. The interest free note was repaid over a six month term.

F-26

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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 13.7MW of base load and 5.7MW of backup and standby capacity.  The Trust paid a total of $11,300 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 shut down all but two of the projects from 2001 through 2003. The Trust performed an impairment assessment in 2003 using a discounted cash flow valuation methodology, and noted the carrying value of the projects exceeded their estimated fair value. As a result, the Trust recorded an impairment charge of $56. During the fourth quarter of 2005, based on a subsequent assessment, the Trust recorded an additional impairment charge of $550 to adjust for the carrying value of the projects to reflect their current estimated fair value. The remaining projects ceased operations in the fourth quarter of 2006.

In 2003, the Trust sold the assets of the Globe cogeneration project located in Fall River, Massachusetts for $240. The Trust had no basis in the project in 2003, as a result this amount was recognized as a gain.

5.    INVESTMENT

Ridgewood Providence Power Partners, L.P.

In 1996, Ridgewood Providence was formed as a Delaware limited partnership which acquired a 12.3MW electrical generating station, located at the Central Landfill in Johnston, Rhode Island.  In 1997, the capacity was increased to 13.8MW. The Trust invested $7,100, in return for a 35.7% limited partnership interest in Ridgewood Providence and its general partner.

The project is fueled by methane gas produced and collected from the landfill. The electricity generated is sold pursuant to a long-term contract. The remaining 64.3% of Ridgewood Providence is owned by Ridgewood Electric Power Trust IV ("Trust IV"), whose managing partner is also Ridgewood Renewable Power LLC.

The Trust's accounts for its investment in Ridgewood Providence under the equity method of accounting.

Summarized balance sheet data for Ridgewood Providence at December 31, 2005, 2004 and 2003 is as follows:

	2005		2004		2003
					(Restated)
Current assets	$	2,675	$	2,151	$	2,672
Non-current assets		12,214		13,596		14,694
Total assets	$	14,889	$	15,747	$	17,366
Current liabilities	$	1,912	$	1,546	$	1,991
Equity		12,977		14,201		15,375
Total liabilities and equity	$	14,889	$	15,747	$	17,366
Trust share of equity	$	4,633	$	5,070	$	5,489

F-27

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Summarized statements of operations data for Ridgewood Providence for the years ended December 31, 2005, 2004 and 2003 is as follows:

	2005		2004		2003
					(Restated)
Revenues	$	11,916	$	12,205	$	8,585
Cost of revenues		9,050		8,972		6,856
Other expenses		5		13		121
Total expenses		9,055		8,985		6,977
Net income	$	2,861	$	3,220	$	1,608
Trust share of net income	$	1,021	$	1,150	$	574

Quarterly summarized statements of operations data for Ridgewood Providence is as follows (unaudited):

	Nine Months Ended September 30,							Three Months Ended September 30,
	2005		2004		2003			2005		2004		2003
			(Restated)		(Restated)					(Restated)		(Restated)
Revenues	$	8,825	$	9,105	$	6,153		$	2,860	$	2,954	$	1,960
Cost of revenues		6,396		6,467		4,991			2,032		1,819		1,678
Other expenses (income)		80		35		(42	)		45		-		(133	)
Total expenses		6,476		6,502		4,949			2,077		1,819		1,545
Net income	$	2,349	$	2,603	$	1,204		$	783	$	1,135	$	415
Trust share of net income	$	839	$	929	$	430		$	280	$	405	$	148

	Six Months Ended June 30,						Three Months Ended June 30,
	2005		2004		2003		2005		2004		2003
			(Restated)		(Restated)				(Restated)		(Restated)
Revenues	$	5,965	$	6,151	$	4,193	$	2,875	$	3,013	$	1,905
Cost of revenues		4,364		4,648		3,313		2,249		2,328		1,655
Other expenses		35		35		91		21		8		43
Total expenses		4,399		4,683		3,404		2,270		2,336		1,698
Net income	$	1,566	$	1,468	$	789	$	605	$	677	$	207
Trust share of net income	$	559	$	524	$	282	$	216	$	243	$	73

F-28

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

	Three Months Ended March 31,
	2005		2004		2003
			(Restated)		(Restated)
Revenues	$	3,090	$	3,138	$	2,288
Cost of revenues		2,115		2,320		1,658
Other expenses		14		27		48
Total expenses		2,129		2,347		1,706
Net income	$	961	$	791	$	582
Trust share of net income	$	343	$	281	$	209

6.  PLANT AND EQUIPMENT

At December 31, 2005, 2004 and 2003, plant and equipment at cost and accumulated depreciation were:

	2005			2004			2003
							(Restated)
Building	$	319		$	319		$	166
Machinery and equipment		8,478			9,029			9,517
		8,797			9,348			9,683
Less: accumulated depreciation		(5,203	)		(4,763	)		(4,667	)
	$	3,594		$	4,585		$	5,016

For the years ended December 31, 2005, 2004 and 2003, depreciation expense was $440, $460 and $572, respectively, which is included in cost of revenues.

Quarterly plant and equipment and related depreciation expense were as follows (unaudited):

	2005
	September 30			June 30			March 31
Building	$	319		$	319		$	319
Machinery and equipment		9,031			9,030			9,029
		9,350			9,349			9,348
Less: accumulated depreciation		(5,082	)		(4,976	)		(4,869	)
	$	4,268		$	4,373		$	4,479

Depreciation expense for the 2005 year-to-date periods ended September 30, June 30, and March 31, was $319, $2,131 and $106, respectively.

	2004
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Building	$	319		$	319		$	319
Machinery and equipment		9,027			9,010			9,010
		9,346			9,329			9,329
Less: accumulated depreciation		(4,647	)		(4,522	)		(4,419	)
	$	4,699		$	4,807		$	4,910

Restated depreciation expense for the 2004 year-to-date periods ended September 30, June 30, and March 31, was $312, $213 and $106, respectively.

F-29

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

	2003
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Building	$	319		$	319		$	319
Machinery and equipment		9,531			10,298			10,298
		9,850			10,617			10,617
Less: accumulated depreciation		(4,662	)		(4,519	)		(4,374	)
	$	5,188		$	6,098		$	6,243

Restated depreciation expense for the 2003 year-to-date periods ended September 30, June 30, and March 31, was $432, $277 and $144, respectively.

7.    INTANGIBLE ASSETS

A portion of the purchase price of the San Joaquin and Byron were assigned to electric power sales contracts and are being amortized over the lives of the contracts 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.

Gross and net amounts of intangible assets and related amortization expense at December 31, 2005, 2004 and 2003 were as follows:

	2005			2004			2003
							(Restated)
Electricity sales contract - gross	$	1,794		$	1,794		$	1,794
Less: accumulated amortization		(790	)		(718	)		(646	)
Intangibles, net	$	1,004		$	1,076		$	1,148

During 2005, 2004 and 2003, the Trust recorded amortization expense of $72 per year.

Future amortization expenses as of December 31, 2005 are as follows:

Years ended December 31,	Amortization
2006	$	72
2007		72
2008		72
2009		72
2010		72
Thereafter		644

Quarterly gross and net amounts of intangible assets and related amortization expense were asfollows (unaudited):

	2005
	September 30			June 30			March 31
Electricity sales contract - gross	$	1,794		$	1,794		$	1,794
Less: accumulated amortization		(772	)		(754	)		(736	)
Intangibles, net	$	1,022		$	1,040		$	1,058

Amortization expense for the 2005 year-to-date periods ended September 30, June 30 and March 31, was $54, $36 and $18, respectively.

 

F-30

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

	2004
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Electricity sales contract - gross	$	1,794		$	1,794		$	1,794
Less: accumulated amortization		(700	)		(682	)		(664	)
Intangibles, net	$	1,094		$	1,112		$	1,130

Restated amortization expense for the 2004 year-to-date periods ended September 30, June 30 and March 31, was $54, $36 and $18, respectively.

	2003
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Electricity sales contract - gross	$	1,794		$	1,794		$	1,794
Less: accumulated amortization		(628	)		(610	)		(592	)
Intangibles, net	$	1,166		$	1,184		$	1,202

Restated amortization expense for the 2003 year-to-date periods ended September 30, June 30 and March 31, was $54, $36 and $18, respectively.

8.  TRANSACTIONS WITH MANAGING SHAREHOLDER AND AFFILIATES

The Trust operates pursuant to the terms of 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. The Trust pays the Managing Shareholder an annual management fee, which is payable in equal monthly installments, equal to 2.5% of the Trust’s shareholders’ equity as of the beginning of the year.  During 2005, 2004 and 2003, the Trust paid management fees to the Managing Shareholder of $282, $363, and $336, respectively. The management fee is to be paid in monthly installments and, to the extent that this includes the amount waived, the Trust does not pay the management fee on a timely basis, the Trust accrues interest at an annual rate of 10% on the unpaid balance.

For the years ended December 31, 2005, 2004 and 2003, the Trust accrued interest expense of $7, $6 and $5 respectively, on accrued but unpaid management fees. The interest accrued was waived by the Managing Shareholder in the fourth quarter of 2005 and recorded as capital contribution in the period waived. Additionally, the Managing Shareholder waived $72 of the 2005 management fee, which was also recorded as contributed capital.

Under the Management Agreement with the Managing Shareholder, Ridgewood Power Management ("RPM"), an entity related to the Managing Shareholder through common ownership, provides management, purchasing, engineering, planning and administrative services to the projects operated by the Fund. RPM charges the projects at its cost for these services and for the allocable amount of certain overhead items. Allocations of costs are on the basis of identifiable direct costs or in proportion to amounts invested in projects managed by RPM. During the years ended December 31, 2005, 2004 and 2003, RPM charged the Trust projects $250, $248 and $270, respectively, for overhead items allocated in proportion to the amount invested in projects managed. In addition, RPM charged the Trust projects $3,669, $4,690 and $5,430, respectively, for all of the direct operating and non-operating expenses incurred during such periods.

Under the Declaration of Trust, the Managing Shareholder receives 100% of current year operating profits until cumulative profits equal cumulative losses allocated to the Managing Shareholder.  The Managing Shareholder then receives 1% of operating profits until the shareholders have received 14% per annum of their equity contribution (“Payout”).  After Payout, the Managing Shareholder is entitled to receive 20% of the distributions for the remainder of the year.  Losses incurred in any given year are allocated 1% to the Managing Shareholder, provided the allocation of losses to the shareholders shall be limited to prevent the shareholder from having a negative capital account. These allocations do not affect the allocation of cash distributions discussed below.

The Managing Shareholder is also entitled to receive 1% of all annual distributions made by the Trust (other than those derived from the disposition of Trust property) until Payout.  Once Payout is reached, the Managing Shareholder is entitled to receive 20% of all future distributions. During 2005, 2004, and 2003, distributions to the Managing Shareholder were $20, $22, and $12, respectively. The Trust has not yet reached Payout.

F-31

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

The Managing Shareholder owns one investor share. The Trust granted the Managing Shareholder a single Management Share representing the Managing Shareholder's management rights and rights to distributions of cash flow.

In June 26, 2003, the Managing Shareholder entered into a Revolving Credit and Security Agreement with Wachovia Bank, National Association.  The agreement, as amended, allows the Managing Shareholder to obtain loans and letters of credit of up to $6,000 for the benefit of the trusts and funds that it manages.  As part of the agreement, the Trust agreed to limitations on its ability to incur indebtedness, and liens and to provide guarantees. The Managing Shareholder and Wachovia Bank agreed to extend the Managing Shareholder’s line of credit, through May 31, 2008. In October 2003, the Trust obtained from its bank, two standby letters of credit, to secure the gas purchases for the Byron and San Joaquin projects. The Trust used its credit facility to collateralize the letters of credit. These two standby letters of credit expired in August 2006 and at December 31, 2005 were a combined total of $350.

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, 2005, 2004 and 2003 the Trust had outstanding payables and receivables as follows:

	December 31,						December 31,
	2005		2004		2003		2005		2004		2003
	Due from						Due to
					(Restated)						(Restated)
RPM	$	311	$	284	$	290	$	-	$	-	$	-
RRP		-		-		-		4		81		87
Trust II		-		-		-		-		-		9
Providence		354		461		570		-		1		-
Other affiliates		5		-		-		-		1		-
Total	$	670	$	745	$	860	$	4	$	83	$	96

The Trust had the following quarterly outstanding payables and receivables with the following affiliates (unaudited):

	2005
	September 30		June 30		March 31		September 30		June 30		March 31
	Due from						Due to
RPM	$	369	$	278	$	303	$	-	$	-	$	-
RRP		-		-		-		224		436		82
Providence		-		-		-		377		121		236
Other affiliates		4		4		4		-		-		-
Total	$	373	$	282	$	307	$	601	$	557	$	318

F-32

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

	2004
	September 30		June 30		March 31		September 30		June 30		March 31
	Due from						Due to
	(Restated)		(Restated)		(Restated)		(Restated)		(Restated)		(Restated)
RPM	$	300	$	121	$	266	$	-	$	-	$	-
RRP		-		-		-		87		116		116
Trust II		-		-		-		-		10		10
Providence		339		-		-		-		430		1
Total	$	639	$	121	$	266	$	87	$	556	$	127

	2003
	September 30		June 30		March 31		September 30		June 30		March 31
	Due from						Due to
	(Restated)		(Restated)		(Restated)		(Restated)		(Restated)		(Restated)
RPM	$	311	$	263	$	336	$	-	$	-	$	-
RRP		-		9		23		32		-		-
Trust II		-		-		-		10		10		10
Providence		-		-		-		243		436		407
Other affiliates		-		-		-		2		4		3
Total	$	311	$	272	$	359	$	287	$	450	$	420

9.  COMMITMENTS AND CONTINGENCIES

The Trust, through certain of its subsidiaries, has two long-term operating ground leases with future minimum lease payments as of December 31, 2005 as follows:

Years Ended December 31,
2006	$	173
2007		173
2008		173
2009		173
2010		173
Thereafter		2,627
Total	$	3,492

Rent expense for the years ended December 31, 2005, 2004 and 2003 was $185, $186 and $220, respectively.

The San Joaquin and Byron projects have long-term agreements to purchase natural gas from their supplier at a fixed price throughout the term, which expired in August 2006.  At December 31, 2005, future minimum purchases under the agreements, net of resale agreements, totaled $837, all of which occurred in 2006.

During the years ended December 31, 2005, 2004 and 2003, the Trust recorded, as a component of cost of revenues, gains from changes in its gas supply contracts of $359, $1,011 and $1,924 , respectively.

The Trust is subject to legal proceedings involving ordinary and routine claims related to its business. The ultimate legal and financial liability with respect to such matters cannot be estimated with certainty and requires the use of estimates in recording liabilities for potential litigation settlements. Estimates for losses from litigation are disclosed if considered reasonably possible and accrued if considered probable after consultation with outside counsel. If estimates of potential losses increase or the related facts and circumstances change in the future, the Trust may be required to record additional litigation expense.

F-33

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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 gas. 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 Massachusetts Division of Energy Resources (“DOER”).

On January 17, 2003, Ridgewood Providence received a “Statement of Qualification” from the DOER pursuant to the renewable portfolio standards (“RPS”) adopted by Massachusetts. Since Ridgewood Providence has now 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.

During 2004, Ridgewood Providence became qualified to sell RPS Attributes in Connecticut under a similar RPS program, except that the Connecticut program does not have a “vintage” prohibition, which in Massachusetts disqualifies the amount of a facility’s generation measured by its average output during the period 1995 through 1997. Thus, Ridgewood Providence can sell the 86,000 megawatt hours (“MWhs”) that are ineligible under Massachusetts standards into the Connecticut market. During 2004, Ridgewood Providence sold its “vintage” RPS Attributes pursuant to agreements with various power marketers.

Similar agreements have committed Ridgewood Providence to sell its 2005 and 2006 “vintage” RPS Attributes to such designated parties at certain fixed quantities and prices. Pursuant to the terms of the agreement, Ridgewood Providence is only required to deliver the specified RPS Attributes it generates and is not obligated to produce, nor is it subject to penalty if it is unable to produce, contracted quantities.

11.    SELECTED UNAUDITED QUARTERLY FINANCIAL DATA

	2005 Quarters
	1st		2nd			3rd		4th
Revenues	$	964	$	1,354		$	1,750	$	137
Gross profit (loss)		468		(231	)		2,201		(938	)
Income (loss) from operations		309		(407	)		2,066		(1,623	)
Net income (loss)		658		(190	)		2,349		(1,464	)
Net income (loss) per Investor Share		1,662		(479	)		5,936		(3,701	)

	2004 Quarters
	1st		2nd		3rd		4th
	(Restated)		(Restated)		(Restated)
Revenues	$	1,097	$	1,380	$	1,791	$	1,326
Gross profit (loss)		680		453		821		(653	)
Income (loss) from operations		391		314		718		(751	)
Net income (loss)		679		562		1,073		(497	)
Net income (loss) per Investor Share		1,712		1,422		2,710		(1,252	)

F-34

Ridgewood Electric Power Trust III

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

	2003 Quarters
	1st		2nd		3rd			4th
	(Restated)		(Restated)		(Restated)			(Restated)
Revenues	$	964	$	1,742	$	2,137		$	1,066
Gross profit (loss)		783		1,427		122			(163	)
Income (loss) from operations		589		1,320		(338	)		(127	)
Net income (loss)		1,037		1,390		(189	)		21
Net income (loss) per Investor Share		2,621		3,547		(476	)		15

12.   SUBSEQUENT EVENTS

On August 16, 2006, the Managing Shareholder of the Trust and affiliates of the Trust, filed lawsuits against the former independent registered public accounting firm for the Trust, Perelson Weiner, LLP (“Perelson Weiner”), in New Jersey Superior Court.  The suits alleged professional malpractice and breach of contract in connection with audit and accounting services performed by Perelson Weiner. On October 26, 2006, Perelson Weiner filed a counterclaim against the Trust, and its affiliates alleging breach of contract due to unpaid invoices. Discovery is ongoing and no trial date has been set. The costs and expenses of the litigation are being paid for by the Managing Shareholder and affiliated management companies and not the underlying investment funds, including the Trust.

F-35

EX-3.IB

                                                                 Exhibit 3(i)(B)
                            CERTIFICATE OF AMENDMENT
                                     TO THE
                              CERTIFICATE OF TRUST
                                       OF
                       RIDGEWOOD ELECTRIC POWER TRUST II


The undersigned certifies that:

1.      The name of the statutory trust is Ridgewood Electric Power Trust III
(the "Statutory Trust").

2.      The amendment to the Certificate of Trust of the Statutory Trust set
forth below (the "Amendment") has been duly authorized by the Managing
Shareholder of the Statutory Trust.

          The second paragraph of the Certificate of Trust is hereby amended to
read as follows:

          "2. The name and business address of the Corporate Trustee of the
Trust in the State of Delaware is Christiana Bank & Trust Company, 1314 King
Street, P.O. Box 957, Wilmington, DE 19899-0957, Attention: Corporate Trust
Administration."

3.      Pursuant to Title 12, 3801 et. at., the Delaware Statutory Trust Act,
(the "Act"), this Certificate of Amendment to the Certificate of Trust of the
Statutory Trust shall become effective immediately upon fling with the Office of
the Secretary of State of the State of Delaware.

4.      The Amendment is made pursuant to the authority granted by the Statutory
Trust under Section 3810(b) of the Act and pursuant to the authority set forth
in the governing instrument of the Statutory Trust.


          IN WITNESS WHEREOF, the undersigned, being the Corporate Trustee of
the Statutory Trust, has duly executed this Certificate of Amendment this 18th
day of December, 2003.

                                              Christiana Bank & Trust Company,
                                              Corporate Trustee


                                              By: /s/ Toni L. Lindsay
                                              -------------------------
                                              Name:  Toni L. Lindsay
                                              Title: Vice President




       State of Delaware
      Secretary of State
   Division of Corporations
Delivered 02:18 PM 12/18/2003
  FILED 02:28 PM 12/18/2003
 SRV 030817295 - 2362359 FILE

EX-3.IIB

                                                                Exhibit 3(ii)(B)
                              DECLARATION OF TRUST

                                       FOR

                       RIDGEWOOD ELECTRIC POWER TRUST III

     This DECLARATION OF TRUST (the "Declaration") is made as of January 3,
1994, by Ridgewood Energy Holding Corporation, a Delaware corporation
("Ridgewood Holding"), who, with its successors as trustees under this
Declaration, is referred to as the "Corporate Trustee," for the benefit of those
persons who are accepted as holders of shares of beneficial interest under this
Declaration.

     WHEREAS, the Corporate Trustee wishes to organize the RIDGEWOOD ELECTRIC
POWER TRUST III (the "Trust") as a business trust under the Delaware Business
Trust Act, to provide for the management of the Trust by Ridgewood Power
Corporation, a Delaware corporation ("Ridgewood Power," or "Managing
Shareholder' when acting hereunder in such capacity), and to provide for the
sale of beneficial interests in the Trust, the operation of the Trust and the
rights of the Corporate Trustee, other persons acting as trustees (together with
the Corporate Trustee, the "Trustees") and owners of beneficial interests; and

     WHEREAS, a Certificate of Trust (the "Certificate") was filed by the
Corporate Trustee on December 6, 1993 with the Secretary of State of Delaware to
evidence the existence of the Trust;

     NOW, THEREFORE, the Corporate Trustee declares that it constitutes and
appoints itself trustee of the sum of $10.00 owned by it, together with all
other property that it acquires under this Declaration as trustee, together with
the proceeds thereof, to hold, IN TRUST, to manage and dispose of for the
benefit of the holders, from time to time, of beneficial interests in the Trust,
subject to the provisions of this Declaration as follows:

                                    ARTICLE 1

                             ORGANIZATION AND POWERS

     1.1 Trust Estate; Name. The Trust, comprised of the trust estate created
under this Declaration and the business conducted hereunder, shall be designated
as "Ridgewood Electric Power Trust III," which name shall refer to the trust
estate and to the Corporate Trustee in its capacity as trustee of the trust
estate but not in any other capacity and which shall not refer to the officers,
agents, other trustees or beneficial owners of the Trust. To the extent
possible, the Trustees shall conduct all business and execute all documents
relating to the Trust in the name of the Trust and not as trustees. The Trustees
may conduct the business of the Trust or hold its property under. other names as
necessary to comply with law or to further the affairs of the Trust as it deems
advisable in their sole discretion. This Declaration, the Certificate and any
other documents, and any amendments of any of the foregoing, required by law or
appropriate, shall be recorded in all offices or jurisdictions where the Trust
shall determine such recording to be necessary or advisable for the conduct of
the business of the Trust.

     1.2 Purpose. (a) The purpose of the Trust is to invest in the independent
power market, including, but not limited, to, activities relating to (i)
cogeneration facilities producing both electricity and heat energy, (ii)
independent power generation facilities producing electricity and other forms of
energy from natural gas, oil, coal, hydropower, geothermal or waste resources or
other technologies or other power related products or services, (iii) other
privately-owned, non-utility power production and related facilities, and (iv)
pre-development or preparatory activities relating to the evaluation, planning,
permitting and development of potential facilities described in clauses
(i)-(iii) above, all of the foregoing in such manner as the Trust shall
designate. The Trust may invest its funds or participate in entities organized
for the purpose of investigating, developing, acquiring, operating or disposing
of potential or existing facilities described in the preceding sentence. The
Trust will not participate in nuclear power facilities that produce electricity
or in their development. The Trust shall have the power to perform any and all
acts and activities with respect to this general purpose that are customary or
incidental thereto including by way of illustration the acquisition,
development, construction, management, operation, administration and disposition
of such independent power properties or any interest therein as the Trust shall
designate and the production and the marketing of the




Exhibit A
Declaration of Trust

products or output there from. Pending the commitment of Trust funds to
independent power properties, distribution of Trust funds to Shareholders (as
defined in Article 2) or application of reserve funds to their purposes, the
Trust shall have full authority and discretion to utilize Trust funds as
provided in Section 10.5.

     (b) The Trust may engage in independent power operations with others when,
in the judgment of the Trust, it is prudent and desirable under the
circumstances. In any such operations, the Trust may acquire, own, hold,
develop, construct, manage, operate and dispose of independent power projects,
either as principal, agent, partner, syndicate member, associate, joint venturer
or otherwise and may invest funds in any such business, and may do any and all
things necessary or incidental to the conduct of any such activities. Without
limiting the foregoing, the Trust may guarantee debt of Projects (as defined in
Article 2) or participants therein relating to such Projects, supply security
for such debt or for the issuance of letters of credit for a Project or enter
into lease transactions or acquire goods and services for the benefit of a
Project.

     (c) The Trust is authorized and empowered to elect to be a business
development company under the Investment Company Act of 1940, as amended (the
"1940 Act"), and to operate as such.

     1.3 Relationship among Shareholders; No Partnership. As among the Trust,
the Trustees, the Shareholders and the officers and agents of the Trust, a trust
and not a partnership is created by this Declaration irrespective of whether any
different status may be held to exist as far as others are concerned or for tax
purposes or in any other respect. The Shareholders hold only the relationship of
trust beneficiaries to the Trustees with only such rights as are conferred on
them by this Declaration.

     1.4 Organization Certificates. The parties hereto shall cause to be
executed and filed (a) the Certificate, (b) such certificates as may be required
by so-called "assumed name" laws in each jurisdiction in which the Trust has a
place of business, (c) all such other certificates, notices, statements or other
instruments required by law or appropriate for the formation and operation of a
Delaware business trust in all jurisdictions where the Trust may elect to do
business, and (d) any amendments of any of the foregoing required by law or
appropriate.

     1.5 Principal Place of Business. The principal place of business of the
Trust shall be The Ridgewood Commons, 947 Linwood Avenue, Ridgewood, New Jersey
07450 or such other place as the Trust may from time to time designate by notice
to all Investors. The Trust's office in the State of Delaware and the principal
place of business of Ridgewood Holding are 1105 North Market Street, Suite 1300,
Wilmington, Delaware 19899, or such other place as the Trust may designate from
time to time by notice to all Investors. The Trust may maintain such other
offices at such other places as the Trust may determine to be in the best
interests of the Trust.

     1.6 Admission of Investors. (a) The Trust shall have the unrestricted right
at all times prior to the Termination Date (as defined in Article 2) to admit to
the Trust such Investors as it may deem advisable, provided the aggregate
subscriptions received for Capital Contributions (as defined in Article 2) of
the Investors and accepted by the Trust do not exceed $15,000,000 immediately
following the admission of such Investors. The Trust in its sole discretion may
increase the $15,000,000 amount to not more than $40,000,000 at any time prior
to the Termination Date. After the Termination Date, the sale of Shares or
different series of Shares is governed by Section 9.5.

     (b) Each Investor shall execute a Subscription Agreement (as defined in
Article 2) and make such Capital Contributions to the Trust as subscribed by the
Investor. Subject to the acceptance thereof by the Trust, each Investor who
executes a Subscription Agreement shall be admitted to the Trust as an Investor.
All funds received from such subscriptions will be deposited in the Trust's name
in an interest-bearing escrow account at a commercial bank until the Escrow Date
(as defined in Article 2).

     (c) If, by the close of business on June 30, 1994, Investor Shares
representing Capital Contributions in the aggregate amount of at least
$1,500,000 have not been sold or if the Trust withdraws the offering of Investor
Shares in accordance with the terms of this Declaration, the Trust shall be
immediately dissolved at the expense of the Managing Shareholder and all
subscription funds shall be forthwith returned to the respective subscribers
together with any interest earned thereon. As soon after the Termination Date as
practicable, the Trust shall advise each Investor of the Termination Date and
the aggregate amount of Capital Contributions made by all Investors.

                                       2



                                                                       Exhibit A
                                                            Declaration of Trust

     (d) The full cash price for Shares must be paid to the Trust at the time of
subscription, unless, after subscriptions for at least an aggregate of 15
Investor Shares have been accepted by the Trust, a subsequent subscriber obtains
the consent of the Trust (which may be refused in its sole discretion) to delay
full payment until not later than the Termination Date in anticipation of
obtaining financing from other sources.

     1.7 Term of the Trust. For all purposes, this Declaration shall be
effective on and after the date hereof and the Trust shall continue in existence
until the fortieth anniversary of that date, at which time the Trust shall
terminate unless sooner terminated under any other provision of this
Declaration.

     1.8 Powers of the Trust. Without limiting any powers granted to the Trust
under this Declaration or applicable law, the Trust shall have the following
additional powers, subject to applicable law:

     (a) To borrow money or to loan money and to pledge or mortgage any and all
Trust Property and to execute conveyances, mortgages, security agreements,
assignments and any other contract or agreement deemed proper and in furtherance
of the Trust's purposes and affecting it or any Trust Property (including
without limitation the Management Agreement (as defined in Article 2));
provided, however, that the Trust shall not loan money to the Managing
Shareholder, the Trustees or any other Managing Person;

     (b) To pay all indebtedness, taxes and assessments due or to be due with
regard to Trust Property and to give or receive notices, reports or other
communications arising out of or in connection with the Trust's business or
Trust Property;

     (c) To collect all monies due the Trust;

     (d) To establish, maintain and supervise the deposit of funds or Trust
Property into, and the withdrawals of the same from, Trust bank accounts or
securities accounts;

     (e) To employ accountants to prepare required tax returns and provide other
professional services and to pay their fees as a Trust expense;

     (f) To make any election relating to adjustments in basis on behalf of the
Trust or the Shareholders which is or may be permitted under the Code,
particularly with respect to Sections 743 and 754 of the Code;

     (g) To employ legal counsel for Trust purposes and to pay their fees and
expenses as a Trust expense;

     (h) To conduct the affairs of the Trust with the general objective of
achieving capital appreciation and distributable income from the Trust Property;
and

     (i) To do business as a "business development company" as defined by the
1940 Act.

     1.9. Preferred Participation Rights. If not later than June 30, 1994 an
Investor's subscription for Shares is accepted by the Trust and the Investor has
delivered full payment for those Shares to the Trust by that date, the Trust
shall issue to that Investor whole or fractional Preferred Participation Rights
at the rate of one Preferred Participation Right for each Share so subscribed
for, multiplied by the number of whole months (a fractional month being
considered to be a whole month) from the date the subscription is accepted by
the Trust through December 31, 1994. The holders of Preferred Participation
Rights shall be entitled to distributions as provided under Section 8.1 (d) but
shall have no voting, liquidation or other rights in respect of the Preferred
Participation Rights, except for the class voting provision of this Section 1.9
and the right to receive, if available, any unpaid balance in respect of the
Preferred Participation Rights. Preferred Participation Rights are not
transferable apart from and must be transferred with the Shares with which they
are associated and may be repurchased at any time by the Trust, subject to
applicable law, at a price per Preferred Participation Right equal to $1,000
minus any distributions made under Section 8.1(d) in respect of that Preferred
Participation Right. The rights of holders of Preferred Participation Rights may
not be modified except by an amendment to this Declaration that is also
consented to by the affirmative vote of the holders of at least a majority of
the outstanding Preferred Participation Rights, voting as a class. If by June
30, 1994, an Investor either has not delivered full payment for Shares to the
Trust for any reason or the Investor's

                                        3


Exhibit A
Declaration of Trust

subscription is not accepted by the Trust for any reason, the Investor will not
be entitled to any Preferred Participation Rights.

                                    ARTICLE 2

                                   DEFINITIONS

     The following terms, whenever used herein, shall have the meanings assigned
to them in this Article 2 unless the context indicates otherwise. References to
sections and articles without further qualification denote sections and articles
of this Declaration. The singular shall include the plural and the masculine
gender shall include the feminine, and vice versa, as the context requires, and
the terms "person" and "he" and their derivations whenever used herein shall
include natural persons and entities, including, without limitation,
corporations, partnerships and trusts, unless the context indicates otherwise.

     "Act" - The federal Securities Act of 1933, as amended, and any rules and
regulations promulgated thereunder.

     "Adjusted Capital Account" - A Shareholders Capital Account at any time
(determined before any allocations for the current fiscal period) (a) increased
by (i) the amount of the Shareholder's share of partnership minimum gain (as
defined in Regulation Section 1.704-2(d)) at such time, (ii) the amount of the
Shareholders share of the minimum gain attributable to a partner nonrecourse
debt (as defined in Regulation Section 1.704-2(b)(4)) and (iii) the amount of
the deficit balance in the Shareholders Capital Account which the Shareholder is
obligated to restore under Regulation Section 1.704-1(b)(2)(ii)(c), if any, and
(b) decreased by reasonably expected adjustments, allocations and distributions
described in Regulation Sections 1.704-1 (b)(2)(ii)(d)(4), (5) and (6) (taking
into account the adjustments required by Regulation Sections 1.704-2(g)(i i) and
1.704-2(i)(5)).

     "Affiliate" - An "affiliate" of, or person "affiliated" with, a specified
person is a person that directly, or indirectly through one or more
intermediaries, controls, or is controlled by, or is under common control with,
the person specified.

     "Average Annual Capital Contributions" - For any calendar year or shorter
period, the Trust will compute on each day an amount equal to the total Capital
Contributions of the Investors (excluding Capital Contributions made in respect
of additional classes or series of Shares under Section 9.5(c)) minus all prior
distributions made under Section 8.1(c) to Investors. The "Average Annual
Capital Contributions" will equal the sum of the amounts computed under the
preceding sentence on each day in the year or period, divided by the actual
number of days in the year or period.

     "Board" - The Managing Shareholder and the Independent Trustees, acting
together in accordance with the terms hereof.

     "Capital Account" - The amount representing a Shareholders capital interest
in the Trust, as determined under Article 6 hereof.

     "Capital Contributions" - The aggregate capital contributions of the
Investors accepted by the Trust in payment of the purchase price of one or more
whole or fractional Investor Shares (inclusive of the amount of any fee or other
compensation waived by the Trust, the Managing Shareholder or the Placement
Agent) plus any amounts contributed by the Managing Shareholder pursuant to
Section 14.7.

     "Cash-Out Investors" - Those Investors who elect to have the Trust attempt
to liquidate their Investor Shares pursuant to Section 9.6 during the two-year
period beginning August 31, 2001.

     "Cash-Out Percentage" - The percentage that the Capital Contributions of
the Cash-Out Investors comprise of all Capital Contributions (excluding in each
case Capital Contributions made in respect of new series of Shares under Section
9.5(c)), determined as of August 31, 2001.

                                       4



                                                                       Exhibit A
                                                            Declaration of Trust

     "Certificate" - The Certificate of Trust of the Trust, as amended from time
to time.

     "Code" - The Internal Revenue Code of 1986, as amended from time to time,
and any rules and regulations promulgated thereunder.

     "Continuing Investors" - Those Investors who elect not to have the Trust
attempt to liquidate their Investor Shares pursuant to Section 9.6.

     "Corporate Trustee" - Ridgewood Holding or its successors as Corporate
Trustee. The Corporate Trustee acts as legal title holder of the Trust Property,
subject to the terms of this Declaration.

     "Declaration" - This Declaration of Trust, as amended from time to time.

     "Delaware Act" - The Delaware Business Trust Act, as amended from time to
time (currently codified as title 12, chapter 38 of the Delaware Code).

     "Escrow Date" - The latest to occur of the dates on which the Trust (i)
accepts the subscription that causes Capital Contributions in the initial
offering to Investors to be at least $1,500,000, (ii) deposits at least
$1,500,000 in collected funds in escrow under Section 1.6(b) and (iii) qualifies
as a "business development company" under the 1940 Act, provided however, the
Escrow Date shall not be later than June 30, 1994.

     "Independent Trustee" -Ralph Hellmold, Jonathan Kaledin or any other
individual who becomes a successor or additional Independent Trustee under the
terms of this Declaration.

     "Investor" - A purchaser of Investor Shares (which will include the
Managing Shareholder to the extent it acquires Investor Shares) whose
subscription is accepted by the Trust.

     "Investor Cash-Out and Continuation Options" - The option of each Investor
to elect whether or not to have the Trust attempt to liquidate his Investor
Shares pursuant to Section 9.6.

     "Investor Share" - Beneficial interests in the Trust representing an
initial Capital Contribution of $100,000.

     "Losses" - Defined at "Profits or Losses."

     "Majority" - Unless otherwise specified herein, when used with respect to
any consent to be given or decision to be made or action to be taken by the
Investors or group of Investors, a majority in interest of all the then current
Investors or members of the group including appropriate Cash-Out Investors to
the extent they remain Shareholders as provided in Section 9.6. Such Majority,
or any lesser or greater interest prescribed herein, shall be calculated based
upon the number of Shares owned by each Investor who has elected to be a
Continuing Investor under Section 9.6, plus a fraction (not to exceed 1.0) of
the number of Shares owned by each Cash-Out Investor equal to the ratio of the
Investor's Capital Account to his Capital Account on August 31, 2001.

     "Management Agreement" - The management agreement dated as of January
3,1994 between the Trust and the Managing Shareholder, as described in the
Memorandum and adopted by the Independent Trustees, or as modified or approved
by the Independent Trustees or the Shareholders as required by the 1940 Act.

     "Management Share" - Interest in the Trust that represents the beneficial
interests and management rights of the Managing Shareholder in its capacity as
Managing Shareholder, but excluding the Managing Shareholder's interest, if any,
attributable to Investor Shares acquired by it.

     "Managing Person" - Any of the following: (a) Trust officers, agents, or
Affiliates, the Managing Share- holder, the Trustees, or Affiliates of the
Managing Shareholder or a Trustee and (b) any directors, officers or agents of
any organizations named in (a) above when acting for a Trustee, the Managing
Shareholder or any of their Affiliates on behalf of the Trust.

                                        5



Exhibit A
Declaration of Trust

     "Managing Shareholder" - Ridgewood Power and any substitute or different
Managing Shareholder as may subsequently be created under the terms of this
Declaration.

     "Memorandum" - The Confidential Memorandum dated January 3, 1994 of the
Trust, as the same may be amended or supplemented from time to time, to which
this Declaration is an Exhibit.

     "Net Cash Flow" - The total gross receipts of the Trust, less cash
operating expenses, all other cash expenditures of the Trust and reasonable
reserves as determined by the Trust to cover anticipated Trust expenses. For
purposes of determining Net Cash Flow, gross receipts shall mean proceeds from
any source whatsoever, I including, but not limited to, income from operations
and the temporary investment of Trust funds under Section 10.5 and any proceeds
from the sale, exchange, financing or refinancing of Trust Property, but
excluding any Capital Contributions of the Shareholders.

     "1940 Act" - The federal Investment Company Act of 1940, as amended, and
any rules and regulations Promulgated thereunder.

     "Payout" - The point at which total cumulative distributions to Investors
from the Trust (exclusive of distributions in respect of Preferred Participation
Rights and distributions described in Section 9.5(g)) equal their total Capital
Contributions (exclusive of Capital Contributions made on the sale of a new
series of Shares under Section 9.5(c)).

     "Placement Agent" - Ridgewood Securities Corporation, a Delaware
corporation, with its principal place of business at The Ridgewood Commons, 947
Linwood Avenue, Ridgewood, New Jersey 07450.

     "Preferred Participation Right" - A right issued by the Trust under Section
1.9 to an Investor if not later than June 30, 1994 the Investor's subscription
for Shares has been accepted by the Trust and full payment has been delivered to
the Trust. A Preferred Participation Right entitles the holder to special
distributions under Section 8.1 (d) in recognition of the extra benefits the
Trust receives from early subscriptions for Shares.

     "Profits or Losses" - For a given fiscal period, an amount equal to the
Trust's taxable income or loss for such period, determined in accordance with
Code Section 703(a) (for this purpose, all items of income, gain, expense, loss,
deduction or credit required to be stated separately pursuant to Code Section
703(a)(1) shall be included in taxable income or loss), with the following
adjustments:

     (a) Any income of the Trust that is exempt from federal income tax and not
otherwise taken into account in computing Profits or Losses pursuant to this
definition and any income and gain described in Regulation Section 1.704-1
(b)(2)(iv)(i)(1) shall be added to such taxable income or loss;

     (b) Any expenditures of the Trust described in Code Section 705(a)(2)(B) or
treated as Code Section 705 (a)(2)(B) expenditures pursuant to Regulation
Section 1.704-1(b)(2)(iv)(i), and not otherwise taken into account in computing
Profits or Losses pursuant to this definition shall be subtracted from such
taxable income or loss;

     (c) In the event of a distribution in kind under Section 8.2, the amount of
any unrealized gain or loss deemed to have been realized on the property
distributed shall be added or subtracted from such taxable income or loss; and

     (d) Notwithstanding any other provision of this definition, any items which
are specially allocated pursuant to Sections 4.5, 4.6, 4.7, 4.8 and 7.4 shall
not be taken into account in computing Profits or Losses.

     "Project" - (a) An independent power generation facility (including a
cogeneration facility) that (i) is not owned exclusively by an electric utility
but that operates in connection with an electric utility or an electric utility
system or (ii) operates outside an electric utility system and supplies electric
power, other forms of energy or other power related products or services
directly to industrial users, or (b) is a proposed independent power generation
facility, as described in clause (a) above, or (c) is a facility implementing
other power-related technologies or other power-related products or services,
including in each case the preparatory, engineering, legal, siting, financial
and permitting work undertaken in anticipation of construction.

                                       6



                                                                       Exhibit A
                                                            Declaration of Trust


     "Project Entity" - The partnership or other legal entity that develops or
will own a Project and holds title to its assets.

     "Purchase Right" - As used herein shall have the meaning set forth in
Section 9.5(d).

     "Regulation" - A final or temporary Treasury regulation promulgated under
the Code.

     "Ridgewood Holding" - Ridgewood Power Holding Corporation, a Delaware
corporation having its principal office at 1105 North Market Street, Suite 1300,
Wilmington, Delaware 19899, which is the initial Corporate Trustee.

     "Ridgewood Power" - Ridgewood Power Corporation, a Delaware corporation
that is the initial Managing Shareholder.

     "Share" - An Investor Share or a Management Share.

     "Shareholder"- An owner of a beneficial interest in the Trust.

     "Subscription Agreement" - The form of subscription agreement (contained in
Exhibit F to the Memorandum, which is separately bound) which each prospective
Investor must execute in order to subscribe for an interest in the Trust.

     "Termination Date" - August 31, 1994, or an earlier or later date
determined by the Trust in its discretion as follows:

     (a) The Trust may designate any date prior to August 31, 1994 as the
Termination Date if the Escrow Date has occurred prior to such date;

     (b) The Trust from time to time may designate any date after August 31,
1994 as the Termination Date if the Escrow Date has occurred prior to the
extension of the Termination Date; and

     (c) If the Trust elects to withdraw the offering of Shares under this
Declaration, the Termination Date is the date of that election.

     "Trust" - Ridgewood Electric Power Trust III, a Delaware business trust.

     "Trustee" - A person serving as a Corporate Trustee or an Individual
Trustee under this Declaration.

     "Trust Property" - All property owned or acquired by the Corporate Trustee
as part of the trust estate under this Declaration.


                                    ARTICLE 3

                                   LIABILITIES

     3.1 Liability and Obligations of Corporate Trustee. (a) To the fullest
extent permitted by the Delaware Act, the Corporate Trustee in its capacity as a
trustee of the Trust shall not be personally liable to any person other than the
Trust and its Shareholders for any act or omission of the Trustees or the Trust,
or any obligation of the Trust or the Trustees. The trust estate shall be
directly liable for the payment or satisfaction of all obligations and
liabilities of the Trust incurred by the Trustees and the officers and agents of
the Trust within their authority.

                                       7



Exhibit A
Declaration of Trust

     (b) The Corporate Trustee shall not exercise any management or
administrative powers in respect of the Trust except on the direction of the
Managing Shareholder or the Managing Shareholder and the Independent Trustees
acting as the Board, as the case may be.

     (c) The Corporate Trustee, as trustee, may be made party to any action,
suit or proceeding to enforce an obligation, liability or right of the Trust,
but it shall not solely on account thereof be liable separate from the Trust and
it shall be a party in that case only insofar as may be necessary to enable such
obligation or liability to be enforced against the trust estate.

     3.2 Liability and Obligations of Independent Trustees. (a) As permitted by
Section 3808 of the Delaware Act, the Independent Trustees shall not hold title
to or have any legal or possessory interest in any Trust Property. It shall not
be necessary or effective for any Independent Trustee to be made a party to any
action, suit or proceeding to enforce an obligation, liability or right of the
Trust.

     (b) In performing their responsibilities under this Declaration, the
Independent Trustees shall be under a fiduciary duty and obligation to act in
the best interests of the Trust, including the safekeeping and use of all Trust
funds and assets for which they are responsible under this Declaration. In
interpreting the scope of this obligation, the Independent Trustees will have
the responsibilities of and will be entitled to the defenses of directors of a
Delaware corporation.

     3.3 Liability of Managing Shareholder to Third Parties. (a) The Managing
Shareholder shall be liable for any wrongful act or omission of the Corporate
Trustee, the Independent Trustees or the Trust, taken in the ordinary course of
the Trust's business or with the authority of the Independent Trustees or the
Managing Shareholder, that causes loss or injury to any person who is not a
Shareholder or that incurs any penalty.

     (b) The Managing Shareholder shall be liable for losses resulting from (i)
the misapplication by the Managing Shareholder of money or property received
from a person who is not a Shareholder by the Managing Shareholder within the
scope of the Managing Shareholder's apparent authority or (ii) the
misapplication of money or property received by the Trust in the course of its
business from a person who is not a Shareholder while the money or property is
in the custody of the Trust.

     (c) Subject to the remaining provisions of this Article 3, the Managing
Shareholder shall be liable for all other debts and obligations of the Trust,
but it may enter into a separate obligation to perform a Trust contract.

     3.4 Liability of Investors In General. No Investor in his capacity as an
Investor shall have any liability for the debts and obligations of the Trust in
any amount beyond the unpaid amount, if any, of the Capital Contributions
subscribed for by him. Each Investor shall have the same limitation on his
liability for the Trust's debts and obligations as a stockholder of a Delaware
corporation has for debts and obligations of the corporation.

     3.5 Liability of Investors to Trustees, Trust and Shareholders. No Investor
in his capacity as an Investor shall be liable, responsible or accountable in
damages or otherwise to any other Shareholder, the Trustees or the Trust for any
claim, demand, liability, cost, damage and cause of action of any nature
whatsoever that arises out of or that is incidental to the management of the
Trust's affairs.

     3.6 Liability of Managing Persons to Trust and Shareholders. (a) No
Managing Person shall have liability to the Trust or to any other Shareholder
for any loss suffered by the Trust that arises out of any action or inaction of
the Managing Person if the Managing Person, in good faith, determined that such
course of conduct was in the Trust's best interest and such course of conduct
was within the scope of this Declaration and did not constitute negligence or
misconduct of the Managing Person.

     (b) No act of the Trust shall be affected or invalidated by the fact that a
Managing Person may be a party to or has an interest in any contract or
transaction of the Trust if the interest of the Managing Person has been
disclosed or is known to the Shareholders or such contract or transaction is at
prevailing rates or is on terms at least as favorable to the Trust as those
available from persons who are not Managing Persons, provided that the
requirements of the 1940 Act are met.

                                        8


                                                                       Exhibit A
                                                            Declaration of Trust

     3.7 Indemnification of Managing Persons. (a) Each Managing Person shall be
indemnified from the Trust Property against any losses, liabilities, judgments,
expenses and amounts paid in settlement of any claims sustained by him in
connection with the Trust or claims by the Trust, in right of the Trust or by or
in right of any Shareholders, if the Managing Person would not be liable under
the standards of Section 3.6 and, in the case of Managing Persons other than the
Trustees and the Managing Shareholder, the indemnitees were acting within the
scope of authority validly delegated to them by the Trustees or the Managing
Shareholder. The termination of any action, suitor proceeding by judgment, order
or settlement shall not, of itself, create a presumption that the Managing
Person charged did not act in good faith and in a manner that he reasonably
believed was in the Trust's best interests. To the extent that any Managing
Person is successful on the merits or otherwise in defense of any action, suit
or proceeding or in defense of any claim, issue or matter herein, the Trust
shall indemnify that Managing Person against the expenses, including attorneys'
fees, actually and reasonably incurred by him in connection therewith.

     (b) Notwithstanding the foregoing, no Managing Person not any broker-dealer
shall be indemnified, nor shall expenses be advanced on its behalf, for any
losses, liabilities or expenses arising from or out of an alleged violation of
federal or state securities laws, unless (i) there has been a successful
adjudication on the merits of each count involving alleged securities law
violations as to the particular indemnitee, or (ii) those claims have been
dismissed with prejudice on the merits by a court of competent jurisdiction as
to the particular indemnitee or (iii) a court of competent jurisdiction approves
a settlement of the claims against the particular indemnitee. In any claim for
federal or state securities law violations, the party seeking indemnification
shall place before the court the positions of the Securities and Exchange
Commission, the Massachusetts Securities Division and other state securities
administrators to the extent required by them with respect to the issue of
indemnification for securities law violations.

     (c) The Trust shall not incur the cost of that portion of any insurance,
other than public liability insurance, that insures any person against any
liability for which indemnification hereunder is prohibited.

     3.8 General Provisions. The following provisions shall apply to all rights
of indemnification and advances of expenses under this Declaration and all
liabilities described in this Article 3:

     (a) Expenses, including attorneys' fees, incurred by a Managing Person in
defending any action, suit or proceeding may be paid by the Trust in advance of
the final disposition of the action, suit or proceeding upon receipt of an
undertaking by the recipient to repay such amount if it shall ultimately be
determined that the Managing Person is not entitled to be indemnified by the
Trust under this Declaration or otherwise and it at least one of the following
conditions is satisfied:

         (i)   The Managing Person provides appropriate security for the
               undertaking;

         (ii)  The Managing Person is insured against losses or expenses of
               defense or settlement so that the advances may be recovered or

         (iii) Either a majority of the Independent Trustees who are not
               parties to the action, suit or proceeding or independent legal
               counsel in a written opinion determines, based upon a review of
               the then readily- available facts, that there is reason to
               believe that the Managing Person will be found to be entitled to
               indemnification under Section 3.7. In so doing, it shall not be
               necessary to employ hearing or trial-like procedures.

     (b) Rights to indemnification and advances of expenses under this
Declaration are not exclusive of any other rights to indemnification or advances
to which a Managing Person or Investor may be entitled, both as to action in a
representative capacity or as to action in another capacity taken while
representing another.

     (c) Each Managing Person shall be entitled to rely upon the opinion or
advice of or any statement or computation by any counsel, engineer, accountant,
investment banker or other person retained by such Managing Person or the Trust
which he believes to be within such person's professional or expert competence.
In so doing, he will be deemed to be acting in good faith and with the requisite
degree of care unless he has actual knowledge concerning the matter in question
that would cause such reliance to be unwarranted.

                                       9



Exhibit A
Declaration of Trust

     3.9 Dealings with Trust. With regard to all rights of the Trust and all
actions to be taken on its behalf, the Trust and not the Trustees, nor the
Managing Shareholder, nor the Trust's officers and agents, nor the Investors
shall be the principal and the Trust shall be entitled as such to the extent
permitted by law to enforce the same, collect damages and take all other action.
All agreements, obligations and actions of the Trust shall be executed or taken
in the name of the Trust, by an appropriate nominee, or by the Corporate Trustee
as trustee but not in its individual capacity. Money may be paid and property
delivered to any duly authorized officer or agent of the Trust who may receipt
therefor in the name of the Trust and no person dealing in good faith thereby
shall be bound to see to the application of any moneys so paid or property so
delivered. No entity whose securities are held by the Trust shall be affected by
notice of such fact or be bound to see to the execution of the Trust or to
ascertain whether any transfer of its securities by or to the Trust or the
Corporate Trustee is authorized.

                                    ARTICLE 4

                          ALLOCATION OF PROFIT AND LOSS

     4.1. Profits. After giving effect to the provisions of Sections 4.5, 4.6,
4.7, 4.8 and 7.4, Profits for any fiscal period shall be allocated among the
Shareholders as follows:

     (a) First, 100% to the Managing Shareholder in an amount equal to the
excess, if any, of (i) the cumulative Losses allocated to the Managing
Shareholder pursuant to Section 4.2(c) for all prior fiscal periods, over (ii)
the cumulative Profits allocated to the Managing Shareholder pursuant to this
Section 4.1(a) for all prior fiscal periods; and

     (b) The balance, if any, 80% to the Investors and 20% to the Managing
Shareholder.

     4.2. Losses. After giving effect to the provisions of Sections 4.5, 4.6,
4.7, 4.8 and 7.4, Losses for any fiscal period shall be allocated among the
Shareholders as follows:

          (a)  First, 99% to the Investors and 1 % to the Managing Shareholder
               in an amount equal to the lesser of:

          (i)  The excess, if any, of Losses over Profits for the current and
               all prior fiscal periods (solely for this purpose, Profits and
               Losses for all years shall be computed as it Sections 4.7 and 4.8
               were not part of this Declaration) or

          (ii) The excess, if any, of (A) the aggregate items of income and gain
               allocated to the Shareholders under Section 4.8 for all prior
               fiscal periods over (B) the cumulative Losses allocated to the
               Shareholders pursuant to this Section 4.2(a) for all prior fiscal
               periods, provided that Losses shall not be allocated pursuant to
               this Section 4.2(a) to the extent that such allocation would
               cause any Investor to have a negative amount in the Investor's
               Adjusted Capital Account at the end of this fiscal period;

     (b) Second, 80% to the Investors and 20% to the Managing Shareholder,
provided that Losses shall not be allocated pursuant to this Section 4.2(b) to
the extent that such allocation would cause any Investor to have a negative
amount in the Investor's Adjusted Capital Account at the end of this fiscal
period; and

     (c) The balance, if any, 100% to the Managing Shareholder.

     4.3 General Allocation Provisions. (a) Except as otherwise provided in this
Declaration, all items of Trust income, gain, expense, loss, deduction and
credit for a particular fiscal period and any other allocations not otherwise
provided for shall be divided among the Shareholders in the same proportions as
they share Profits or Losses, as the case may be, for the fiscal period.

     (b) The Shareholders shall be bound by the provisions of this Declaration
in reporting their shares of Trust income and loss for income tax purposes.

                                       10


                                                                       Exhibit A
                                                            Declaration of Trust

     (c) The Trust may use any permissible method under Code Section 706(d) and
the Regulation thereunder to determine Profits, Losses and other items on a
daily, monthly or other basis for any fiscal period in which there is a change
in a Shareholder's interest in the Trust.

     (d) The definition of "Capital Account" and certain other provisions of
this Declaration are intended to comply with Regulations Sections 1.704-1(b) and
1.704-2 and shall be interpreted and applied, in a manner consistent with such
Regulations. These Regulations contain additional rules governing maintenance of
Capital Accounts that may not have been provided for in this Declaration
because, in part, these rules may relate to transactions that are not expected
to occur and in some instances are prohibited by this Declaration. If the Trust
after consultation with its regular accountants or tax counsel determines that
it is prudent to modify the manner in which the Capital Accounts, or any debits
or credits thereto, are computed in order to comply with such Regulations, or to
avoid the effects of unanticipated events that might otherwise cause this
Declaration not to comply with such Regulations, the Trust shall make such
modification without the need of prior notice to or consent of any Shareholder;
provided, that such modification is not likely to have a material effect on the
amounts distributable to any Shareholder.

     4.4 Among Investors. Each Investor shall be allocated that percentage part
of the aggregate amounts allocated to all Investors or to a subgroup of
Investors, as the case may be, as the number of Shares owned by the Investor
bears to the aggregate number of Shares owned by all Investors or Investors in
the subgroup.

     4.5 Minimum Allocation. Notwithstanding anything to the contrary in this
Declaration, in no event shall the Managing Shareholder's allocable share of
each material item of Trust income, gain, expense, loss, deduction or credit be
less than 1 % of such item.

     4.6 Tax Allocation. Notwithstanding anything to the contrary in this
Declaration, to the extent that the Managing Shareholder is treated for federal
income tax purposes as having received an interest in the Trust as compensation
for services which constitutes income to the Managing Shareholder under Code
Section 61, any amount allowed as a deduction for federal income tax purposes to
the Trust (whether as an ordinary and necessary business expense or as a
depreciation or amortization deduction) as a result of such characterization
shall be allocated solely for federal income tax purposes to the Managing
Shareholder.

     4.7 Allocation of Net Revenue from Dispositions. Prior to Payout, all net
revenues derived by the Trust from any sale, transfer, injury, destruction or
other disposition of Trust Property or an interest therein, other than in the
ordinary course of operation of Trust Property (including, without limitation,
proceeds from insurance, refinancing or condemnation) shall be allocated 99% to
the Investors and 1% to the Managing Shareholder. After Payout, all such revenue
shall be allocated 80% to the Investors and 20% to the Managing Shareholder. Net
revenues shall equal the total proceeds of the disposition less only the costs
of sale. Gain or loss allocable to each Shareholder will be the difference
between the Shareholder's basis in the property disposed of and the net revenues
from the disposition allocated to such Shareholder in accordance with this
Section 4.7.

     4.8. Priority Allocations. Prior to making allocations for a fiscal period
under Sections 4.1 and 4.2, all or a portion of the Trust's items of income or
gain shall be specially allocated among the Shareholders in proportion to the
cumulative distributions that each has received under Sections 8.1(d) and (e)
from the commencement of the Trust through a date 30 days after the end of the
fiscal period in an amount equal to the excess, if any, of:

     (a) The lesser of (i) the sum of the aggregate Losses allocated to the
Shareholders under Section 4.2(a) for all prior fiscal years, if any, and the
aggregate distributions pursuant to Sections 8.1(d) and (e) from the
commencement of the Trust through a date 30 days after the end of the fiscal
period or (ii) the excess, if any, of Profits over Losses for the current and
all prior fiscal periods (solely for this purpose, Profits and Losses shall be
computed as if Section 4.7 and this Section 4.8 were not part of this
Declaration), over

     (b) The aggregate items of income and gain allocated to the Shareholders
under this Section 4.8 for all prior fiscal periods.

                                       11



Exhibit A
Declaration of Trust

                                    ARTICLE 5

                      CAPITAL CONTRIBUTIONS OF SHAREHOLDERS

     5.1 Capital Contributions. The Capital Contributions of the Investors shall
aggregate not less than $1,500,000 nor more than $15,000,000 except as provided
in Section 1.6(a) and shall be made by the Investors in exchange for Investor
Shares represented by $100,000 each (or for a fraction of an Investor Share
represented by a proportionate price), payable as set forth in Section 5.2.

     5.2 Payment of Capital Contributions. The aggregate Capital Contributions
of the Investors, made with respect to the initial offering of Investor Shares,
shall be payable in cash on or before the Termination Date, as provided in
Section 1.6(d).

     5.3 Additional Capital Contributions. There shall be no additional Capital
Contributions by the Investors except as provided in Section 9.5.

     5.4 Managing Shareholder's Capital Contributions. The Managing Shareholder
in its capacity as Managing Shareholder shall make Capital Contributions in
accordance with Section 14.7.

                                    ARTICLE 6

                                CAPITAL ACCOUNTS

     6.1 Capital Accounts. A Capital Account shall be established and maintained
for each Shareholder and shall be adjusted as follows:

     (a)  The Capital Account of each Shareholder shall be increased by:

          (1)  The amount of such Shareholder's Capital Contributions to the
               Trust;

          (2)  The amount of Profits allocated to such Shareholder pursuant to
               Articles 4 and 7 and Sections 9.5 and 9.6;

          (3)  The fair market value of property contributed by the Shareholder
               to the Trust (net of liabilities secured by the contributed
               property that the Trust under Code Section 752 is considered to
               have assumed or taken subject to); and

          (4)  Any items in the nature of income or gain that are specially
               allocated to such Shareholder pursuant to Sections 4.5, 4.6, 4.7,
               4.8 and 7.4.

     (b) The Capital Account of each Shareholder shall be decreased by:

          (1)  The amount of Losses allocated to such Shareholder pursuant to
               Articles 4 and 7 and Sections 9.5 and 9.6;

          (2)  All amounts of money and the fair market value of property paid
               or distributed to such Shareholder pursuant to the terms hereof
               (other than payments made with respect to loans made by such
               Shareholder to the Trust), net of liabilities secured by that
               property that the Shareholder under Code Section 752 is
               considered to have assumed or taken subject to; and

          (3)  Any items in the nature of expenses or losses that are specially
               allocated to such Shareholder pursuant to Sections 4.5, 4.6, 4.7
               and 7.4.

                                       12



                                                                       Exhibit A
                                                            Declaration of Trust

     6.2 Calculation of Capital Account. Whenever it is necessary to determine
the Capital Account of any Shareholder, the Capital Account of such Shareholder
shall be determined in accordance with the rules of Regulation Sections 1.704-1
(b) (2) (iv) and 1.704-2 (as amended from time to time). If necessary to comply
with the Code, an Adjusted Capital Account may be employed.

     6.3 Effect of Loans. Loans by any Shareholder to the Trust shall not be
considered contributions to the capital of the Trust.

     6.4 Withdrawal of Capital. No Shareholder shall be entitled to withdraw any
part of his Capital Account or to receive any distribution from the Trust,
except as specifically provided herein.

     6.5 Capital Accounts of New Shareholders. Any person who shall acquire
Shares in accordance with the terms and conditions of Article 13 of this
Declaration shall have the Capital Account of his transfer or after adjustments
reflecting the transfer, if any, except as specifically provided herein.

     6.6 Limitation. Neither the Trustees, the Managing Shareholder nor any
other Managing Person shall be required or shall have any personal liability to
fund any or all of any negative Capital Account of any Investor, including
without limitation Capital Contributions.

                                   ARTICLE 7

                  INTEREST OF SHAREHOLDERS IN INCOME AND LOSSES

     7.1 Determination of Income and Loss. At the end of each Trust fiscal year,
and at such other times as the Trust shall deem necessary or appropriate, each
item of Trust income, gain, expense, loss, deduction and credit shall be
determined for the period then ending and shall be allocated to the Capital
Account of each Shareholder in accordance with the provisions hereof. With
respect to the admission of Shareholders, the Trust will use the "interim
closing date" method of accounting as permitted by the Regulations.

     7.2 Determination of Income and Loss In the Event of Transfer. In the event
that a Shareholder transfers his interest in the Trust in accordance with the
terms of this Declaration, the determination and allocation described in Section
7.1 shall be made as of the date of such transfer and thereafter all such
allocations shall be made to the account of the transferee of such interest;
provided. however, that the Trust may agree that such determination and
allocation shall be pro rata to the Shareholders based upon the actual number of
days in such fiscal year that each such Shareholder held an interest in the
Trust. In the event of a pro rata determination and allocation, the foregoing
provisions of this Section relating to a pro rata determination and allocation
will not be applicable to the distributive shares, with respect to the Shares
transferred, of items of Trust income, gain, expense, loss, deduction and credit
arising out of (a) the sale or other disposition of all or substantially all
Trust Property, or (b) other extraordinary nonrecurring items, all of which will
be allocated to the holder of such Trust interest on the date such items of
Trust income, gain, expense, loss, deduction and credit are earned or incurred.

     7.3 Allocation of Net Income and Net Losses. All items of income, gain,
expense, loss, deduction and credit of the Trust from operations and in the
ordinary course of operation of Trust Property shall be allocated among the
Shareholders in accordance with Article 4.

     7.4 Qualified Income Offset and Other Allocation Provisions. (a) If there
is a net decrease in "partnership minimum gain" (within the meaning of
Regulation Section 1.704-2(d)) during a fiscal period, then there shall be
allocated to each Shareholder items of income and gain for such fiscal period
(and, if necessary, subsequent fiscal periods) in proportion to, and to the
extent of, an amount equal to the portion of such Shareholder's share of the net
decrease in partnership minimum gain during such fiscal period that is allocable
to the disposition of Trust Property subject to one or more nonrecourse
liabilities of the Trust. However, such allocation shall be reduced to the
extent (i) the Shareholder contributes capital to the Trust that is used to
repay the nonrecourse liability and (ii) the Shareholder's share of the net
decrease in partnership minimum gain is caused by the repayment. The foregoing
is intended to be a "minimum gain chargeback" provision as described in
Regulation Section 1.704-2(f), and shall be interpreted and applied in all
respects in accordance with such Regulation. If there is a net decrease in the
minimum gain attributable to a "partner nonrecourse debt" (as defined in
Regulation Section 1.704-2(b) (4)) for a

                                       13



Exhibit A
Declaration of Trust


fiscal period, then, in addition to the amounts, if any, allocated pursuant to
the first sentence of this Subsection 7.4 non (a), there shall be allocated to
each Shareholder with a share of such minimum gain attributable to a "partner
nonrecourse debt" items of income and gain for such fiscal period (and, if
necessary, subsequent fiscal periods) in proportion to, and to the extent of, an
amount equal to the portion of such Shareholders share of the net decrease in
the minimum gain attributable to a partner nonrecourse debt during such fiscal
period that is allocable to the disposition of Trust Property subject to one or
more nonrecourse liabilities of the Trust. However, such amount shall be reduced
to the extent (i) the Shareholder contributes capital to the Trust that is used
to repay the nonrecourse liability and (ii) the Shareholder's share of the net
decrease in the minimum gain attributable to a partner nonrecourse debt is
caused by the repayment.

     (b) If during any fiscal period of the Trust a Shareholder unexpectedly
receives an adjustment, allocation or distribution described in Regulation
Section 1.704-1 (b)(2)(ii)(d)(4), (5) or (6), which causes or increases a
deficit balance in the Shareholder's Adjusted Capital Account, there shall be
allocated to the Shareholder items of income and gain (consisting of a pro rata
portion of each item of Trust income, including gross income, and gain for such
period) in an amount and manner sufficient to eliminate such deficit balance as
quickly as possible. The foregoing is intended to be a "qualified income offset"
provision as described in Regulation Section 1.704-1 (b)(2)(ii)(d), and shall be
interpreted and applied in all respects in accordance with such Regulation..

     (c) Notwithstanding anything to the contrary in Article 4 or this Article
7, any item of deduction, loss or Code Section 705(a)(2)(B) expenditure that is
attributable to "partner nonrecourse debt" shall be allocated in accordance with
the manner in which the Shareholders bear the economic risk of loss for such
debt (determined in accordance with Regulation Section 1.704-2(i)).


     (d) To the extent that any item of income, gain, loss or deduction has been
specially allocated pursuant to paragraph (a), (b) or (c) of this Section 7.4
("Required Allocations") and such allocation is inconsistent with how the same
amount Otherwise would have been allocated under Sections 4.1 and 4.2,
subsequent allocations under Sections 4.1 and 4.2 shall be made, to the extent
possible, in a manner consistent with paragraphs (a), (b) and (c) of this
Section 7.4 which negates as rapidly as possible the effect of all previous
Required Allocations.

     (e) Solely for federal, state and local income and franchise tax purposes
and not for book or Capital Account purposes, income, gain, loss and deduction
with respect to property carried on the Trust's books at a value other than its
tax basis shall be allocated (i) in the case of property contributed in kind, in
accordance with the requirements of Code Section 704(c) and such Regulations as
may be promulgated thereunder from time to time, and (ii) in the case of other
property, in accordance with the principles of Code Section 704(c) and the
Regulations thereunder, in each case, as incorporated among the requirements of
the relevant provisions of the Regulations under Code Section 704(b).

     (f) All or a portion of the remaining items of Trust income or gain for the
fiscal period, if any, shall be specially allocated to the Investors in
proportion to the cumulative distributions each has received pursuant to section
8.1(e) from the commencement of the Trust, until the aggregate amounts allocated
to each Investor pursuant to this Section 7.4 (f) for such period and all prior
periods equal the cumulative amount of such distributions to such Investor.

                                    ARTICLE 8

                 INTEREST OF SHAREHOLDERS IN CASH DISTRIBUTIONS

     8.1 Distribution of Net Cash Flow. Subject to the terms of this
Declaration, the Trust shall make distributions of Net Cash Flow out of the
Trust's funds, to the extent and at such times as it deems advisable, in the
following manner:

     (a) Indebtedness to Shareholders. First, Net Cash Flow shall be applied pro
rata (in accordance with the percentage of total loans that are owing to each
Shareholder) to the payment to the Shareholders of interest and principal, in
that order, on loans, if any, made by the Shareholders to the Trust.

     (b) Special Provisions. Distributions of Net Cash Flow in respect of an
additional series of Shares under Section 9.5 are governed by Section 9.5(g),
distributions of Net Cash Flow under the Investor Cash-Out and

                                       14



                                                                       Exhibit A
                                                            Declaration of Trust

Continuation Options are governed by Section 9.6 and distributions made in
connection with the dissolution and termination of the Trust under Section 14.1
are governed by Section 8.1(g). Net Cash Flow distributed under those provisions
shall be excluded from consideration under Sections 8.1(c) - (f).

     (c) Proceeds from Dispositions of Property. All Net Cash Flow remaining
after the application of Sections 8.1 (a) and (b) from the sale, transfer,
injury, destruction or other disposition of Trust Property or an interest
therein, other than in the ordinary course of operation of Trust Property (and
including, without limitation, proceeds from insurance, refinancing or
condemnation, but excluding sales or resales of interim investments under
Section 10.5) which the Trust determines to distribute, shall be distributed as
follows:

     (1) Prior to Payout, 99% to the Investors and 1% to the Managing
Shareholder; and

     (2) After Payout, 80% to the Investors and 20% to the Managing Shareholder.

     (d) Satisfaction of Preferred Participation Rights. All Net Cash Flow
remaining after the application of Sections 8.1(a) - (c) that the Trust
determines to distribute during a calendar year or shorter period shall first be
applied to the redemption of any outstanding Preferred Participation Rights in
the following order:

     (1)  Ninety-nine percent of Net Cash Flow subject to this Section 8.1(d)
          and distributed during 1995 shall be distributed pro rata among the
          holders of Preferred Participation Rights and the remaining 1% shall
          be distributed to the Managing Shareholder until total cumulative
          distributions to those holders under this Section 8.1(d) equal $500
          per outstanding Preferred Participation Right, and the remaining Net
          Cash Flow distributed during 1995, if any, shall be distributed under
          Sections 8.1(e) - (f) and (h);

     (2)  Ninety-nine percent of Net Cash Flow subject to this Section 8.1(d)
          and distributed during 1996 shall be distributed pro rata among the
          holders of Preferred Participation Rights and the remaining 1% shall
          be distributed to the Managing Shareholder until total cumulative
          distributions to those holders under this Section 8.1(d) equal $1,000
          per outstanding Preferred Participation Right, and the remaining Net
          Cash Flow distributed during 1996, if any, shall be distributed under
          Sections 8.1(e) - (f) and (h); and

     (3)  If after 1996 cumulative distributions under this Section 8.1(d) to
          holders of Preferred Participation Rights are less than $1,000 per
          outstanding Preferred Participation Right, 99% of all Net Cash Flow
          subject to this Section 8.1(d) that is distributed thereafter shall be
          distributed pro rata to the holders of outstanding Preferred
          Participation Rights and the remaining 1% shall be distributed to the
          Managing Shareholder until total cumulative distributions to the
          holders under this Section 8.1(d) equal $1,000 per Preferred
          Participation Right, and all remaining Net Cash Flow shall be
          distributed under the remaining provisions of this Article 8.

     (e) Investor Priority for Distribution -- Payout. Until Payout is achieved,
all Net Cash Flow that remains after the application of Sections 8.1(a) - (d)
and that the Trust determines to distribute shall be distributed as follows:

     (1)  Until total distributions of Net Cash Flow subject to this Section
          8.1(e) during a calendar year to Investors equal the greater of (A)
          14% of the Investors' Average Annual Capital Contributions or (B) 80%
          of Net Cash Flow distributed in that year after deducting amounts
          governed by Sections 8.1(a) - (d), 99% of all distributions made under
          this Section 8.1(e) in that year (or shorter period ending on Payout)
          shall be made to the Investors and the remaining 1% shall be made to
          the Managing Shareholder; and

     (2)  Thereafter, 100% of distributions made during the remainder of the
          calendar year (or shorter period ending on Payout) shall be made to
          the Managing Shareholder.

                                       15



Exhibit A
Declaration of Trust

     (f) Distributions - - Post-Payout. After Payout is achieved, 80% of all
distributions made in any calendar year or portion thereof after the application
of Sections 8.1(a) - (e) shall be made to the Investors and the remaining 20%
shall be made to the Managing Shareholder.

     (g) Proceeds Available Upon Dissolution. Upon dissolution and termination
of the Trust under Section 14.1, the proceeds of the sale or other disposition
of the Trust Property shall be paid or distributed in the following order of
priority:

          (1)  First, there shall be paid to the Trust's creditors, other than
               Shareholders, funds, to the extent available, sufficient to
               extinguish current Trust liabilities and obligations, including
               costs and expenses of liquidation (or provision for payment shall
               be made, which provision may include a distribution of assets
               subject to the obligations in question); 12rovided, however. that
               all loans made to fund expenditures under Section 9.5(e) shall
               be paid only from assets allocable to the Share- holders who
               benefitted from such expenditures and only in proportion to such
               benefit;

          (2)  Second, any loans owed by the Trust to the Shareholders shall be
               paid in proportion thereto; provided, however. that all loans
               made to fund expenditures under Section 9.5 (e) shall be paid
               only from assets allocable to the Shareholders who benefitted
               from such expenditures and only in proportion to such benefit;

          (3)  Third, to the Shareholders in proportion to, and to the extent of
               the excess, if any, of (i) the cumulative distributions to which
               a Shareholder is entitled under Sections 8.1 (d) and (e) from the
               inception of the Trust until the date on which the liquidating
               distribution is made over (ii) the sum of all prior distributions
               made to the Share- holders under Sections 8.1(d),(e) and (g)(3);
               provided, however, that no distribution shall be made under this
               Section 8.1(g)(3) that creates or increases a negative amount in
               the Investor's Adjusted Capital Account at the end of this fiscal
               period. This proviso shall be determined as follows:
               distributions shall be first determined tentatively pursuant to
               this Section 8.1(g)(3) without regard to the Shareholders'
               Capital Accounts and then the allocation provisions of Article 4
               shall be applied tentatively as if such tentative distributions
               had been made. If any Investor shall thereby have a negative
               amount in the Investor's Adjusted Capital Account, the actual
               distribution to the Investor under this Section 8.1 (g)(3) shall
               be equal to the tentative distribution to the Investor less the
               negative amount in the Adjusted Capital Account after application
               of the tentative allocation; and

          (4)  Fourth, the balance, if any, to the Shareholders, in accordance
               with their Capital Accounts, after giving effect to all
               adjustments to Capital Accounts for all fiscal periods through
               and including the fiscal period in which dissolution occurs.

     (h) Limitation. Notwithstanding any other provision of this Declaration, no
distribution may be made selectively to one Shareholder or group of Shareholders
but must be made ratably to all Shareholders entitled to that type of
distribution at that time, subject to the provisions of Section 12.11(b).

     8.2 Distribution In Kind. If the Trust elects to make distribution in kind
of any of the assets of the Trust, it shall give notice of its election to each
Shareholder, specifying the nature and value of all such assets to be
distributed in kind, the deadline for giving notice of refusal to accept a
distribution in kind and to the extent advisable, the estimated time necessary
for the Trust to liquidate assets if those assets are not distributed and other
information as required. In making such election, the Trust shall not
arbitrarily value assets to be distributed in kind nor shall it specify assets
to be distributed in kind in such a manner as to unreasonably advantage or
disadvantage any Shareholder. A Shareholder may refuse to accept a distribution
in kind by giving written notice to the Trust not later than 30 days after the
effective date of the Trust's notice of distribution. If a Shareholder refuses
distribution in kind, the Trust shall retain in the Trust's name the portion of
the assets which were to be distributed in kind and which were to be allocated
to the refusing Shareholder (the "Retained Assets") and shall liquidate the
Retained Assets in accordance with this Declaration. Upon liquidation of the
Retained Assets, the sum realized shall be distributed to

                                       16


                                                                       Exhibit A
                                                            Declaration of Trust

the Shareholder refusing distribution in kind in full discharge of the Trust's
obligation to distribute the Retained Assets. In determining the Capital
Accounts of the Shareholders, a distribution of assets in kind shall be
considered a sale of the property distributed so that any unrealized gain or
loss with respect to such property shall be deemed to have been realized and
allocated among the Shareholders in accordance with Article 4.

     8.3 Amounts Withheld. All amounts withheld pursuant to the Code or any
provision of any state or local tax law with respect to any payment or
distribution to the Trust or the Shareholders shall be treated as amounts
distributed to the Shareholders pursuant to this Article 8 for all purposes
under this Declaration. The Trust may allocate any such amounts among the
Shareholders in any manner that is in accordance with applicable law.

     8.4 Limitation. Distributions to Shareholders shall not be made to the
extent they are prohibited by restrictions contained in the 1940 Act, the
Delaware Act or other provisions of this Declaration.

                                    ARTICLE 9

                               OPERATION OF TRUST

     9.1 Investment Fee. The Trust shall pay the Managing Shareholder out of
Trust Property an investment fee in an amount equal to 2% of each Capital
Contribution from the initial offering or any future offering of Investor
Shares. The investment fee payable in respect of Investors whose subscriptions
for Shares are accepted by the Managing Shareholder in 1994 is for its services
in investigating and evaluating investment opportunities and effecting
transactions for investing the capital contributed through 1994, and the fee
payable by Investors whose subscriptions for Shares are accepted by the Managing
Shareholder in a later year is for those services for capital contributed in
that year. The fee shall be payable on the Escrow Date as to Shares purchased
through that date and on each date thereafter on which the Trust receives and
collects full payment for additional accepted subscriptions for Shares. In
addition, an investment fee shall be paid to the Managing Shareholder in an
amount equal to 2% of additional Capital Contributions received under Section
9.5, for similar services rendered by the Managing Shareholder during the year
in which such funds are received by the Trust. The fee in respect of services
performed by the Managing Shareholder during any year in which such additional
funds are received by the Trust under Section 9.5 shall be payable upon the
later of each date on which payment is accepted by the Trust or the fulfillment
of any applicable escrow conditions.

     9.2 Selling Commissions and Placement Agent Fee. The Trust shall pay out of
Trust Property to Ridgewood Securities Corporation or to any broker-dealer who
effects the-sale of one or more whole or fractional Shares, cash selling
commissions in an aggregate amount equal to 8% of each Capital Contribution. For
serving as Placement Agent, Ridgewood Securities Corporation shall also be
entitled to receive out of Trust Property a fee in an amount equal to 1% of each
Capital Contribution. Such commissions and fees payable in respect of sales of
Shares under the initial offering of Shares shall be due and payable promptly
after the latest to occur of (i) acceptance by the Trust of an Investor's
subscription, (ii) the Escrow Date or (iii) the receipt by the Trust of the
gross purchase price for the Shares. Such commissions and fees in respect of
additional Capital Contributions shall be due and payable upon the later of such
date on which funds are accepted by the Trust or the fulfillment of any
applicable escrow conditions.

     9.3 Other Expenses. (a) The Trust shall pay the Managing Shareholder out of
Trust Property an organizational, distribution and offering fee in an amount
equal to 5% of each Capital Contribution to cover all expenses incurred in the
offer and sale of Shares, including legal, accounting, and consulting fees,
printing, filing, postage and other expenses of organizing the Trust,
distribution and selling costs and closing costs for the offering. The fee shall
be payable on the Escrow Date as to Shares purchased through that date and on
each date thereafter on which the Trust receives and collects full payment for
additional accepted subscriptions for Shares. If these expenses exceed 5% of the
aggregate Capital Contributions, the Managing Shareholder shall pay such excess.

     (b) The Trust shall reimburse the Managing Shareholder for all other actual
and necessary direct expenses paid or incurred in connection with the operation
of the Trust, including but not limited to accounting, legal and consulting
fees, to the extent that those expenses were incurred by the Managing
Shareholder in carrying out responsibilities assigned to it by this Declaration,
were consistent with this Declaration and do not constitute Organizational,
Distribution and Offering Fees. The Trust shall reimburse the Corporate Trustee
for all actual and

                                       17



Exhibit A
Declaration of Trust


necessary expenses paid or incurred in connection with the operation of the
Trust, including the Trust's allocable share of the Corporate Trustee's
overhead.

     (c) As compensation for the Managing Shareholder's performance under the
Management Agreement, the Trust shall pay the Managing Shareholder a management
fee, pay expenses of the Trust and reimburse the Managing Shareholder for Trust
expenses paid by the Managing Shareholder, all in accordance with the terms of
the agreement.

     (d) In respect of the acquisition or disposition of all or a portion of the
investments that the Trust may make in Projects or Project Entities on its own
behalf (rather than through its participation in any entity organized to develop
multiple Projects), the Trust may be required to or may find it most
advantageous to engage a broker or similar adviser and to pay a brokerage fee to
the broker or other persons responsible for bringing the acquisition or
disposition o opportunity to the Trust's attention or for investigating,
evaluating or negotiating the acquisition or those service f the Trust's
interest therein. Where permitted, if the Managing Shareholder or an Affiliate
performs in respect of an investment acquisition or disposition opportunity
for the Trust relating to a particular Project or Project Entity (but not
including an investment made through a multiple Project development entity or in
Projects developed by that entity), the Managing Shareholder or Affiliate so
providing those services shall be entitled to receive a brokerage fee from the
Trust not exceeding 2% of the gross proceeds of or amount paid in the
transaction.

     9.4 Payment and Recoupment of Fees. As soon as funds have been released to
the Trust from the escrow account referred to in Section 1.6, they may be used
to pay the fees referred to in Sections 9.1, 9.2 and 9.3 then due. If the
Managing Shareholder withdraws the offering of Shares, any person that has
received payments from the proceeds of the offering shall return such payments
to the Trust upon demand by the Managing

     9.5 Additional Offers of Shares. (a) Beginning six months and one day after
the Termination Date, the Trust may sell additional Shares if the Managing
Shareholder determines that the best interests of the Trust so require. All
actions under this Section 9.5 are subject to any applicable requirements of the
1940 Act, and the Managing Shareholder may amend this Section 9.5 without notice
to or ratification by the Investors as necessary to comply with the 1940 Act.

     (b) Additional Shares shall have equal voting rights with other Shares.

     (c) The Managing Shareholder may cause the Trust to issue additional Shares
of the same class as the Investor Shares initially offered to Investors in any
number to such persons and on such terms as the Managing Shareholder may
determine. Further, if the Managing Shareholder determines that the Trust
requires additional funds to develop or invest in an existing or new Project or
Project Entity, the Trust may create additional series of Shares in such numbers
without limitation or prior authorization under this Declaration, to be offered
to such persons and having such terms and conditions as the Managing Shareholder
may determine. Each additional series shall be limited to investments in
Projects or Project Entities that are not coextensive with the entire Trust
Property. When adopted by the Trust (with the approval of the Board if necessary
under the 1940 Act), the terms and conditions of the Shares of an additional
series shall be deemed an amendment of this Declaration and shall be effective
without any notice, action by or approval of the Investors.

     (d) If the Trust creates an additional series of Shares, it may, but shall
not be required to, offer the opportunity to purchase Shares of that series to
all Investors (a "Purchase Right") in proportion to their Capital Contributions,
except that no Investor who declined to subscribe to a previous series of Shares
whose net proceeds were invested in a Project or Project Entity in which any net
proceeds of the proposed series are to be invested shall be entitled to a
Purchase Right for the proposed series. A Purchase Right may be exercisable
prior to or concurrent with the offering of the series to other persons. If the
Trust offers a Purchase Right, the Trust shall give each Investor entitled
thereto a notice specifying the total Shares of the additional series that it is
offering, the price thereof, the Projects or Project Entities in which the net
proceeds are expected to be invested, pertinent information regarding the
proposed uses of the proceeds of the Shares offered and a description of the
consequences of electing not to purchase the Shares offered, together with any
other required information. The Trust will require the Investors to notify the
Trust of their decision to exercise the Purchase Right and to deliver the
subscription documents and

                                       18



                                                                       Exhibit A
                                                            Declaration of Trust

the price for the Shares offered within a reasonable period set by the Trust and
specified in the notice, which shall not be less than 10 days after the
effective date of the notice.

     (e) If a Purchase Right is offered and the Investors do not purchase all
the offered Shares within the period specified in the Trust's notice, the Trust
may do all or any of the following: (i) allow the Managing Shareholder to
purchase the remaining offered Shares, (ii) notify all the Investors of the
shortfall and accept additional subscriptions for the Shares offered without
regard to prior contributions, (iii) obtain the funds as a loan from any or all
of the Investors or from the Managing Shareholder in accordance with Section
12.4(d), (iv) not participate or fund the proposed activity in whole or in part
or (v) sell the remaining Shares to, or obtain a loan from, such other persons
and on such terms and conditions as the Trust in its discretion may determine.
Persons who were not previously Investors and who purchase Shares offered under
this Section 9.5(e) shall be considered Investors in all respects except that
they shall have no rights or interest in items relating to Trust Property not
purchased with proceeds of their Shares.

     (f) All Losses and associated items that are paid from or that are
attributable to the expenditure of the proceeds of the sale of an additional
series of Shares shall be allocated only to the purchasers of those Shares.

     (g) All Profits, Losses and other items (except for Losses and items
allocated under Section 9.5(f)) attributable to Trust Property acquired in whole
or in part with proceeds of Shares of an additional series shall be allocated
under Articles 4 and 7 (unless inconsistent with this Section 9.5) as if that
Trust Property were the only property of the Trust, as if the Allocable Capital
Contributions (as defined in Section 9.5(h)) were the only Capital Contributions
and as if distributions made from revenues derived from that Trust Property were
the only distributions made by the Trust. The Trust shall segregate Net Cash
Flow attributable to that Trust Property and shall make distributions from that
Net Cash Flow as specified in the terms of those Shares. The Trust shall consult
with its independent certified public accountants prior to making any changes in
an allocation under this Section 9.5.

     (h) Each Investor's "Allocable. Capital Contributions" for a Project or a
Project Entity are the amount of the Investor's Capital Contributions actually
invested therein. The Trust shall not be required to specifically track each
Investor's funds for purposes of determining Allocable Capital Contributions;
instead, each Investor shall be credited with a portion of each expenditure
equal to the proportion of the Capital Contributions that funded that
expenditure that was supplied by that Investor. In determining Allocable Capital
Contributions, the Trust has full discretion to use any reasonable method
(including subjective allocations) so long as no Investor or identifiable group
of Investors is intentionally or recklessly disadvantaged and the Trust acts in
good faith. The Trust shall consult with its independent certified public
accountants prior to making any allocation under this Section 9.5(h). As the
proceeds of additional series of Shares are expended, allocations under this
Section 9.5(h) shall be adjusted as of the end of each calendar quarter.

     9.6. Investor Cash-Out and Continuation Options. (a) At a reasonable time
prior to August 31, 2001 (which may be before specific proposals or alternatives
have been developed for the Trust Property), the Trust will canvass each
Investor as to whether he wishes either (i) to have the Investor's Shares
liquidated through sales-or dispositions of Trust Property or (ii) to continue
participating in the Trust on an ongoing basis. In connection with this
decision, the Trust shall provide the Investors with information relevant to the
election to the extent then reasonably available to the Trust. The Trust's
communications with Investors under this Section 9.6 shall be made by any
reasonable method that does not unduly disadvantage any Investor relative to
others and need not be made under the provisions of Section 15.2. An Investor's
election to liquidate his Shares must be made as to all Shares owned and is
irrevocable.

     (b) The "Cash-Out Percentage" shall be determined as of August 31, 2001 and
shall equal the percentage that the Capital Contributions of the Investors who
have elected to liquidate their interests ("Cash-Out Investors") comprises of
all Capital Contributions (excluding in each case Capital Contributions made in
respect of new series of Shares under Sections 9.5(c) and (d)).

     (c) Not later than August 31, 2001 and for a two-year period thereafter,
the Trust will make good faith efforts to sell or otherwise dispose of a portion
of each material Trust Property equal to the Cash-Out Percentage of each such
property. The Trust shall have full and sole discretion to effect the sales or
dispositions and shall not be obligated to offer or sell an interest in any
Trust Property in excess of the Cash-Out Percentage of that Trust Property.

                                       19



Exhibit A
Declaration of Trust

     (d) Until any Trust Property is disposed of under this Section 9.6,
Profits, Losses, tax items and other items relating to that Trust Property shall
be allocated among all Investors in accordance with the other provisions of this
Declaration. Profits, Losses, tax items and other items relating to sales or
dispositions of Trust Property under this Section 9.6 shall be allocated in
accordance with Section 4.7, except that the Investors entitled to allocations
thereunder shall be limited to the Cash-Out Investors. Distributions of the
proceeds of sales or dispositions of Trust Property under this Section 9.6 shall
be made in accordance with Sections 8.1(a)-(f) and (h), except that the
Investors entitled to distributions of those proceeds shall be limited to the
Cash-Out Investors.

     (e) If the Trust determines in its sole discretion that it is impracticable
or not in the best interests of the Investors to sell or dispose of an interest
in a Trust Property equal to the Cash-Out Percentage of that property, the Trust
may sell an interest in that property that is less than the Cash-Out Percentage.
In that case, distributions of the proceeds of the sale or disposition of such
Trust Property shall be made in accordance with the second and third sentences
of Section 9.6(d) and future Profits, Losses, tax items and other items from
that property shall be determined separately and each Investor's allocable share
thereof shall be determined as follows:

          (i)  The Cash-Out Investors shall collectively be entitled to a share
               of the future allocations to Investors from that property equal
               to (A) the Cash-Out Percentage minus the percentage interest in
               the property that was sold or disposed of under this Section 9.6,
               divided by (B) 100% minus the percentage interest in the property
               that was sold or disposed of under this Section 9.6;


          (ii) The remaining Investors (the "Continuing Investors") shall
               collectively be entitled to the remainder of allocations from
               that property to Investors; and

          (iii) Section 4.4 shall govern the allocation of amounts to Investors
               in each subgroup.

     (f) If the Trust determines in its sole discretion that it is in the best
interests of the Investors to sell or dispose of more than the Cash-Out
Percentage of any Trust Property, it may do so. In that event, the interest
sold, up to the Cash-Out Percentage, will be allocated and distributed under
this Section 9.6 (except Section 9.6(e)) and the remainder will be allocated and
distributed among the Continuing Investors and the Managing Shareholder.

     (g) If and when all interests in Trust Properties corresponding to the
Cash-Out Percentages are sold or disposed of, the Cash-Out Investors will cease
to be Shareholders at the time the last proceeds of such sales or dispositions
are distributed to them. In the event that the Trust were to dissolve, the
dissolution provisions set forth in Section 14 would apply in place of the
provisions of this Section 9.6.

     (h) In carrying out their responsibilities under this Section 9.6, the
Trust and the Managing Shareholder shall have full discretion to determine the
order in which Trust Properties shall be sold, the method of offer, the terms of
sale and the substantive and procedural aspects of any transaction. The Trust
and the Managing Persons shall have no obligation other than to use their
reasonable best efforts to carry out this Section 9.6 and no warranty is made
that any Trust Property can be disposed of or can be disposed on terms and In
proportions sufficient to liquidate all or any portion of a Cash-Out Investor's
Shares. The provisions of this Section 9.6 as to rights and responsibilities of
the Trust, the Managing Shareholder and other Managing Persons are in addition
to and not in substitution for the other provisions of this Declaration.

                                   ARTICLE 10

                                   ACCOUNTING

     10.1 Elections. The Trust shall elect the calendar year as its fiscal year.
The Trust shall adopt the accrual method of accounting or such other method of
accounting as the Trust shall determine. The Trust shall elect to be taxed only
as a partnership. The Trust shall not be required to make an election under
Section 754 of the Code or corresponding state taxation laws.

     10.2 Books and Records. The Trust's books and records shall be kept at the
principal place of business of the Trust and shall be maintained on the basis
utilized in preparing the Trust's federal income tax return with

                                       20



                                                                       Exhibit A
                                                            Declaration of Trust

such adjustments in accounting as are required by this Declaration or as the
Trust determines would be in the best interests of the Trust.

     10.3 Reports. (a) The Trust will keep each Investor and assignees complying
with Article 13 currently advised as to activities of the Trust by reports
furnished at least quarterly. Each quarterly report will contain a condensed
statement of "cash flow from operations" for the year to date as determined by
the Managing Shareholder in-conformity with generally accepted accounting
principles on a basis consistent with that of the annual and quarterly financial
statements and showing its derivation from net income. An independent certified
public accounting firm selected by the Trust will prepare the Trust's federal
income tax return as soon as practicable after the conclusion of each year and
each Shareholder will be furnished, at that time, with the necessary accounting
information for each Shareholder to take into account and report separately such
Shareholder's distributive share of the income and deductions of the Trust. The
Trust will use its reasonable best efforts to obtain the information necessary
for the accounting firm as soon as practicable and to transmit the resulting
accounting and tax information to the Shareholders as soon as possible after
receipt from the accounting firm. The Trust shall furnish each Shareholder as
soon as practicable after the conclusion of each year annual financial
statements of the Trust which have been audited by the Trust's independent
certified public accounting firm. The annual financial statements will include
in the notes thereto a reconciliation of net income as reported therein to the
annual reported cash flow from operations and to net income for tax purposes.

     (b) Within 180 days after the end of each year following the fourth
anniversary of the Termination Date, the Trust shall provide the Investors with
an estimated valuation per Share based, if possible, upon a generally accepted
method or methods of valuation of the Trust Property.

     10.4 Bank Accounts. The Trust shall maintain separate segregated accounts
in its name at one or more commercial banks, and the cash funds of the Trust
shall be kept in any of those accounts as determined by the Trust.

     10.5 Interim Assets.. The Trust may purchase, to the extent the Trust's
funds are not otherwise committed to transactions or required for other
purposes, either or both of the following:

     (a) Obligations of banks or savings and loan associations that either (i)
have assets in excess of $5 billion or (ii) are insured in their entirety by
agencies of the United States government; and

     (b) Obligations of or guaranteed by the United States government or its
agencies.

                                   ARTICLE 11

                       RIGHTS AND OBLIGATIONS OF INVESTORS

     11.1 Participation In Management. No Investor (other than the Managing
Shareholder acting in its capacity as such) shall have the right, power,
authority or responsibility to participate in the ordinary and routine
management of the Trust's affairs or to bind the Trust in any manner.

     11.2 Rights to Engage In Other Ventures. No Investor or any officer,
director, shareholder or other person holding a legal or beneficial interest in
any Investor shall, by virtue of his ownership of a direct or indirect interest
in the Trust, be in any way prohibited from or restricted in engaging in, or
possessing an interest in, any other business venture of a like or similar
nature including any venture involving the independent power industry.

     11.3 Limitations on Transferability. The interest of an Investor shall not
be transferable except under the conditions set forth in Article 13 hereof.

     11.4 Information. (a) Each Investor's rights to obtain information from the
Trust from time to time are set forth in this Section. In addition to
information provided under Section 10.3, each investor shall be provided on
request with the following:

                                       21



Exhibit A
Declaration of Trust

          (1)  True and full information regarding the status of the Trust's
               business and financial condition;

          (2)  Promptly after becoming available, a copy of the Trust's federal,
               state and local income tax returns or information returns for the
               preceding year and prior years to the extent reasonably
               available;

          (3)  A current list of the name and last known business, residence or
               mailing address of each Shareholder and of any confidential
               representative of each Shareholder, if specifically designated as
               such in writing (unless such Shareholder has specified that the
               Trust is not to disclose such information, in which case the
               Trust, at the requesting Investor's cost, shall forward
               communications, sealed or unsealed, from the requesting Investor
               to such Shareholder or representative upon assertion by the
               Investor in writing to the Trust of a proper purpose for the
               communication);

          (4)  A copy of the Certificate and this Declaration and all amendments
               thereto;

          (5)  True and full information regarding the amount of cash and a
               description and statement of the agreed value of any other
               property or services contributed by each Shareholder and which
               any Shareholder has agreed to contribute in the future, and the
               date on which each current Shareholder acquired his Shares; and

          (6)  Such other information regarding the Trust's affairs as is just
               and reasonable.

     (b) The Trust shall establish reasonable standards governing without
limitation the information and documents to be furnished and the time and the
location, if appropriate, of furnishing that information and documents. Costs of
providing information and documents shall be borne by the requesting Investor
except for de minimis amounts consistent with the Trust's ordinary practices.
The Trust shall be entitled to reimbursement for its direct, out-of-pocket
expenses incurred in declining unreasonable requests (in whole or in part) for
information.

     (c) The Trust may keep confidential from Investors for such period of time
as it deems reasonable any information that it reasonably believes to be in the
nature of trade secrets or other information that the Trust in good faith
believes would not be in the best interests of the Trust to disclose or that
could damage the Trust or its business or that the Trust is required by law or
by agreement with a third party to keep confidential.

     (d) The Trust may keep its records in other than written form if capable of
conversion into written form within a reasonable time.

     (e) All demands or requests for information under this Section shall be
solely for a purpose reasonably related to the Investor's interest in the Trust.
All requests or demands for information under this Section shall be in writing
and shall state the purpose of the demand; the Trust's acceptance of oral
requests shall not waive or limit the scope of this provision. Any action to
enforce rights under this Section may be brought in the Delaware Court of
Chancery, subject to Section 15.4.

                                   ARTICLE 12

POWERS, DUTIES AND LIMITATIONS OF MANAGING SHAREHOLDER AND INDEPENDENT TRUSTEES

     12.1 Management of the Trust. The Managing Shareholder shall have full,
exclusive and complete discretion in the management and control of the Trust,
except as otherwise provided herein. The Managing Shareholder agrees to manage
and control the affairs of the Trust to the best of its ability and to conduct
the operations contemplated under this Declaration in a careful and prudent
manner and in accordance with good industry practice. The Managing Shareholder
may bind the Trust.

     12.2 Acceptance of Subscriptions. The Managing Shareholder shall not cause
the Trust to accept any subscription for Shares except as provided in Article 1
or in Section 9.5, as the case may be.

                                       22



                                                                       Exhibit A
                                                            Declaration of Trust

     12.3 Specific Limitations. (a) The Managing Shareholder shall not take any
of the following actions without the approval of all Investors:

          (1)  Any act in contravention of this Declaration or the Certificate;

          (2)  Any act that would make it impossible to carry on the Trust's
               ordinary business;

          (3)  Effecting a confession of judgment against the Trust in an amount
               exceeding 10% of the aggregate Capital Contributions;

          (4)  Causing the dissolution or termination of the Trust prior to the
               expiration of its term, except as provided under Article 14;

          (5)  Possessing Trust Property or assigning rights in specific Trust
               Property for other than a Trust purpose; or

          (6)  Constituting any other person as a Managing Shareholder, except
               as provided in Article 14.

     (b) The Managing Shareholder shall not sell, exchange, lease, mortgage,
pledge or transfer all or substantially all of the Trust's assets if not in the
ordinary course of operation of Trust Property or amend this Declaration without
the approval of a Majority of the Investors except as specified in this
Declaration or except pursuant to Section 9.6.

     (c) The Trustees, the Trust or the Trust's agents shall not take any action
that is prohibited to the Managing Shareholder by this or any other provision of
this Declaration and shall take all actions necessary or advisable to carry out
actions specified in this Section that are approved as specified herein.

     12.4 Specific Powers. In addition to the powers and duties otherwise
provided for in this Declaration, the Managing Shareholder has the following
powers and duties, subject to the supervision and review of the Board under
Section 12.5:

     (a) To direct or supervise the Corporate Trustee, the Trust and the Trust's
agents in the exercise of any action relating to the Trust's affairs, including
without limitation the powers described in Section 1.8;

     (b) To take the actions specified in Section 12.3 if the approvals
specified therein are obtained;

     (c) To amend this Declaration as specified in Section 15.8(a) or other
provisions of this Declaration;

     (d) To lend money to the Trust (without being obligated to do so) if such
loan bears interest at a reasonable rate not exceeding the Managing
Shareholder's interest cost or the amount that would be charged to the Trust by
an unrelated lender on a comparable loan for the same purpose (without reference
to the financial abilities or guarantees of the Managing Shareholder). The
Managing Shareholder may not receive points or other financing charges or fees
regardless of the amount loaned to the Trust. Before making any loans to the
Trust, a Managing Shareholder will attempt to obtain a loan from an unrelated
lender secured, if at all, only by Trust Property;

     (e) To approve in its sole discretion any transfer of Investor Shares;

     (f) To terminate the offering of Shares at any time prior to the
Termination Date, provided that the Escrow Date has occurred;

     (g) To withdraw the offering of Shares at any time as provided in Section
1.6;

                                       23



Exhibit A
Declaration of Trust

     (h) To take any action in its discretion that may be necessary, advisable
or appropriate to maintain the Trust's status as a business development company
under the 1940 Act, without any requirement to give notice to or to obtain the
prior or subsequent consent of any Investor;

     (i) To acquire such assets or properties, real or personal, as the Managing
Shareholder in its sole discretion deems necessary or appropriate for the
conduct of the Trust's business and to sell, exchange, distribute to
Shareholders in kind or otherwise dispose of any part of the Trust Property in
the ordinary course of the operation of the Trust Property;

     (j) To waive any fees or compensation payable to it and to credit such
waived amount in its discretion against any obligations it may have to
contribute capital under Section 14.7;

     (k) To provide, or arrange for the provision of, managerial assistance to
those persons in which the Trust invests; and

     (I) To establish valuation principles and to periodically apply such
principles to the Trust's investment portfolio.

     12.5. Independent Trustees. (a) There shall be at least two Independent
Trustees at all times. The number of Independent Trustees may be increased (but
to not more than eight) or decreased (but to not fewer than two) from time to
time by action of a majority of the Managing Shareholder and the Independent
Trustees, acting (collectively, the "Board"). At all times a majority of the
members of the Board shall be Independent Trustees who are not "interested
persons" of the Trust as defined by Section 2(a)(19) of the 1940 Act. If at any
time 50% or more of the members of the Board are "interested persons," the Trust
will take action under Section 12.5(b) within 90 days to correct that condition.
The Independent Trustees shall have terms of indefinite duration, subject only
to removal, incapacity or resignation under this Section 12.5.

     (b) Vacancies, however caused, in the authorized number of Independent
Trustees shall be filled by a majority of the remaining Board members. If no
Independent Trustee remains, the Managing Shareholder shall call a special
meeting of Investors for the purpose of electing Independent Trustees within 90
days after the last vacancy results.

     (c) The Trust shall not take any of the following actions except after (x)
a meeting of the Board at which at least a majority of the Board and a majority
of the Independent Trustees approve the action (if there are only two
Independent Trustees, both shall be required to approve) or majority of the
Independent Trustees at a meeting (if there are only two Independent Trustees, h
both Investors required to approve):

          (i)  Execution of and renewal of a Management Agreement between the
               Trust and the Managing Share-holder or any other agreement under
               which a person is to act as an investment adviser for the Trust
               (the initial execution of a Management Agreement or investment
               adviser agreement shall also require the approval of a Majority
               of the Investors);

          (ii) Execution and renewal of any agreement with a person who
               undertakes regularly to serve or act as principal underwriter for
               the Trust; and

          (iii) Appointment of independent certified public accountants for the
               Trust.

     (d) The Trust shall not effect any sale of Investor Shares below the then
current net asset value (as defined in the 19 40 Act) unless at a meeting of the
Board at least a majority of the Board and a majority of the independent it
Trustees approve the action (if there are only two Independent Trustees, both
shall be required to approve).

     (e) The Board shall also supervise and review the actions of the Managing
Shareholder in managing the Trust and shall have the right to require action by
the Managing Shareholder to the extent necessary to carry out the fiduciary
duties of the Board's members. The Board shall also perform all other duties
imposed on directors of business development companies by the 1940 Act. Except
as expressly authorized by this Declaration or the 1940

                                       24



                                                                       Exhibit A
                                                            Declaration of Trust

Act, the Independent Trustees shall not have any management or administrative
powers over the Trust or the Trust Property. The Independent Trustees shall not
take any action except at a meeting of the Board or by unanimous written consent
of the Independent Trustees and the Managing Shareholder.

     (f) The Board shall meet at least quarterly on the call of the Managing
Shareholder and at such other times as determined by the Board. Except to the
extent conflicting with the Delaware Act, the 1940 Act or this Declaration, the
law of Delaware governing meetings of directors of corporations shall govern
meetings, voting and consents by the members of the Board. The Managing
Shareholder may be represented for any purpose by any of its officers.

     (g) As compensation for services rendered to the Trust, each Independent
Trustee who is not an "interested director" as defined by the 1940 Act shall be
paid by the Trust the sum of $5,000 annually in quarterly installments and shall
be reimbursed for all reasonable out-of-pocket expenses relating to attendance
at meetings or otherwise performing his duties hereunder. The Board may review
the compensation payable to the Independent Trustees annually and may increase
or decrease it as the Board sees reasonable. No compensation for consulting
services shall be paid to Independent Trustees without prior Board approval. No
compensation shall be payable by the Trust to other Managing Persons for their
services except as specified by this Declaration, under a management or
underwriting agreement approved under this Section 12.5 or indirectly as an
officer, director, stockholder or employee of the Managing Shareholder or other
Managing Person otherwise entitled to receive compensation hereunder.

     (h) Any Independent Trustee may resign if he gives notice to the Trust of
his intent to resign and cooperates fully with any successor Independent Trustee
appointed under Section 12.5(b), effective on the designation of the successor
Independent Trustee.

     (i) Any Independent Trustee may be removed (x) for cause by the action of
at least two-thirds of the remaining members of the Board or (y) by action of
the holders of at least two-thirds of the Investor Shares. Removal of an
Independent Trustee shall not affect the validity of any actions taken prior to
the date of removal.

     12.6 Officers of Trust. (a) The Managing Shareholder shall appoint a
President, one or more Vice Presidents as designated by the Managing
Shareholder, a Secretary and such other officers and agents as the Managing
Shareholder may from time to time consider appropriate, none of whom need be a
Shareholder. Except as otherwise prescribed by the Managing Shareholder or in
this Declaration, each officer shall have the powers and duties usually
appertaining to a similar officer of a Delaware corporation under the direction
of the Managing Shareholder and shall hold office during the pleasure of the
Managing Shareholder. Any two or more offices may be held by the same person.
Any officer may resign by delivering a written resignation to the Managing
Shareholder and such resignation shall take effect upon delivery or as specified
therein.

     (b) All conveyances of real property or any interest therein by the Trust
may be made by the Corporate Trustee, which shall execute on behalf of the Trust
any instruments necessary to effect the conveyance. A certificate of the
Secretary of the Trust stating compliance with this Section 12.6(b) shall be
conclusive in favor of any person relying thereon.

     (c) All other documents, agreements, instruments and certificates that are
to be made, executed or endorsed on behalf of the Trust shall be made, executed
or endorsed by such officers or persons as the Managing Shareholder shall from
time to time authorize and such authority may be general or confined to specific
instances. In the absence of other provisions, the President is authorized to
execute any document, to take any action on behalf of the Trust within this
Section 12.6(c), and to authorize other officers to execute confirmatory
documents or certificates.

     12.7 Presumption of Power. The execution by the Corporate Trustee, the
Managing Shareholder or the officers on behalf of the Trust of leases,
assignments, conveyances, contracts or agreements of any kind whatsoever shall
be sufficient to bind the Trust. No person dealing with the Managing Shareholder
or the Trust's officers shall be required to determine their authority to make
or execute any undertaking on behalf of the Trust, nor to determine any fact or
circumstances bearing upon the existence of their authority nor to see the
application or distribution of revenues or proceeds derived there from, unless
and until such person has received written notice to the contrary.

                                       25



Exhibit A
Declaration of Trust


     12.8 Obligations Not Exclusive. The Managing Shareholder and the Trustees
shall be required to devote only such part of their time as is reasonably needed
to manage the business of the Trust, it being understood that the Managing
Shareholder and Trustee have and shall have other business interests and
therefore shall not be required to devote their time exclusively to the Trust.
The Managing Shareholder and the Trustees shall in no way be prohibited from or
restricted in engaging in, or possessing an interest in, any other business
venture of a like or similar nature including and venture involving the
independent power industry. Nothing in this Section 12.8 Shall relieve the
Managing Shareholder of other fiduciary obligations to the Investors, except as
limited in Article 3. Notwithstanding anything to the contrary contained in this
Article or elsewhere in this Declaration, the Managing Shareholder shall have no
duty to take any affirmative action with respect to management of the Trust
business or The Trust Property which might require the expenditure of monies
by-the Trust or the Managing Shareholder unless the Trust is then possessed of
such monies available for the proposed expenditure. Under no circumstances shall
the Managing Shareholder be required to expend its own funds in connection with
the day to day operation of Trust

     12.9 Managing to Deal with Affiliates. No act of the Trust shall be
affected or invalidated by the fact that a Managing Person may be a party to or
have an interest in any contract or transaction of the Trust, provided that the
fact of the Managing Person's interest shall be disclosed or shall have been
known to the Shareholders or the transaction is at prevailing rates or on terms
at least as favorable to the Trust as those available from persons who are not
Managing Persons, except that no Managing Person shall acquire assets from the
Trust and to acquire any asset from a Managing Person except to the extent
permitted by the 1940 Act.

     12.10 shall have no Management Share. The Managing Shareholder shall be
credited with a Management Share which voting rights and shall be deemed to have
attached to it the rights appertaining to the Managing Shareholder under this
Declaration. No Management Share shall be held by or transferred to a person who
is not a Managing Shareholder except as provided by Section 13.1.

     12.11 Removal of Managing Shareholder. (a) The holders of at least 10% of
the Investor Shares may propose the removal of a Managing Shareholder, either
by calling a meeting or soliciting consents in accordance with the terms of this
Declaration. On the affirmative vote of a Majority of the Investors (excluding
Investor Shares held by the Managing Shareholder that is the subject of the
vote or by its Affiliates), such Managing Shareholder shall be removed. A
majority of the Independent Trustees may also remove the Managing Shareholder.

     (b) In the event of any such removal or other incapacity (other than
voluntary resignation without cause) of a Managing Shareholder as enumerated in
Section 14.1(c), the former Managing Shareholder may elect in its sole
discretion to take and to cause the Trust to take one of the following courses
of action:

          (1)  The former Managing Shareholder may elect to exchange its
               Management Share for a series of cash payments from the Trust to
               the former Managing Shareholder in amounts equal to the amounts
               of distributions to which the former Managing Share- holder would
               otherwise have been entitled under this Declaration in respect of
               investments made by the Trust prior to the date of the removal or
               other incapacity. Such payments shall be payable out of the
               Trust's available cash before any distributions are made to the
               Investors pursuant to this Declaration. For purposes of this
               Section 12.11(b)(1), from and after the date of any such removal
               or other incapacity: (i) the former Managing Shareholder's
               interest in the Trust attributable to its Management Share
               shall be terminated and its Capital Account shall be reduced by
               the amount which is attributable to its Management Share and (ii)
               the former Managing Share- holder shall continue to receive its
               pro rata share of all allocations to Investors provided in this
               Declaration that are attributable to Investor Shares acquired by
               the Managing Shareholder.

                                       26


                                                                       Exhibit A
                                                            Declaration of Trust

          (2)  In the alternative, subject to the Trust's obtaining an exemptive
               order from the Securities and Exchange Commission, if required,
               the former Managing Shareholder may elect to engage a qualified
               independent appraiser and cause the Trust to engage a separate
               qualified independent appraiser (at the Trust's expense in each
               case), who shall value the Trust Property as of the date of such
               removal or other incapacity as if the Trust Property had been
               sold at its fair market value so as to include all unrecognized
               gains or losses. If the two appraisers cannot agree on a value,
               they shall appoint a third independent appraiser *(whose cost
               shall be borne by the Trust) whose determination, made on the
               same basis, shall be final and binding. Based on the appraisal,
               the Trust shall make allocations to the former Managing
               Shareholder's Capital Account of Profits, Losses and other items
               resulting from the appraisal as of the date of such removal or
               other incapacity as if the Trust's fiscal year had ended solely
               for the purpose of determining the former Managing Shareholder's
               Capital Account. If the former Managing Shareholder has a
               positive Capital Account after such allocation, the Trust shall
               deliver a promissory note of the Trust to the former Managing
               Shareholder, with a principal amount equal to the former Managing
               Shareholder's Capital Account and which shall bear interest at a
               rate per annum equal to the prime rate in effect at Chase
               Manhattan Bank, N.A. on the date of removal or other incapacity,
               with interest payable annually and principal payable only from
               20% of any available cash before any distributions thereof are
               made to the Investors under this Declaration. If the Capital
               Account of the former Managing Shareholder has a negative balance
               after such allocation, the former Managing Shareholder shall con-
               tribute to the capital of the Trust in its discretion either cash
               in an amount equal to the negative balance in its Capital Account
               or a promissory note to the Trust in such principal amount
               maturing five years after the date of such removal or other
               incapacity, bearing interest at the rate specified above. For
               purposes of this Section 12.11(b)(2), from and after the date of
               any such removal or other incapacity, the former Managing
               Shareholder's interest in the Trust shall be terminated and the
               former Managing Shareholder shall no longer have any interest in
               the Trust other than the right to receive the promissory note and
               payments thereunder as provided above.

     (c) In the event that a Managing Shareholder is removed or no longer serves
as a Managing Shareholder due to an incapacity enumerated in Section 14.1(c),
the former Managing Shareholder shall not be entitled to any uncollected fees
specified in Article 9 to the extent not accrued before the date of such removal
or other incapacity.

     12.12 Indemnification of Placement Agent. (a) The Placement Agent shall not
have any duty, responsibility or obligation to the Trust, the Trustees or any
Shareholder as a consequence of its right to receive any selling commissions or
placement agent fees from the Trust in connection with any offering of Shares,
except to the extent provided under the Act. The Placement Agent has not
assumed, and will not assume, any responsibility with respect to the Trust nor
will it be permitted by the Trust to assume any duties, responsibilities or
obligations regarding the management, operations or any of the business affairs
of the Trust, subsequent to any offering of Shares.

     (b) The Placement Agent shall be indemnified and held harmless by the Trust
against any losses, damages, liabilities or costs (Including attorneys' fees)
arising from any threatened, pending or completed action, suit, claim or
proceeding by any Shareholder against the Placement Agent (except as may be
limited by the Act or applicable state statutes, including, but not limited to,
the Massachusetts Securities Act and the Tennessee Securities Act), based upon
the assertion that the Placement Agent has any continuing duty or obligation,
subsequent to any offering of Shares, to the Trust, the Trustees or any
Shareholder or otherwise to monitor Trust operations or report to Investors
concerning Trust operations.

     12.13 Contribution. Each of the initial Managing Shareholder and subsequent
Managing Shareholders agrees that it shall remain jointly or jointly and
severally liable as required by law for any obligation or recourse liability of
the Trust incurred during the period in which it is a Managing Shareholder.
However, the existing and subsequent Managing Shareholders hereby agree among
themselves to contribute to each other the amount of funds necessary to
effectuate a sharing of Trust obligations and recourse liabilities in proportion
to each Managing Shareholders share of such obligations and liabilities as they
accrue.


                                       27



Exhibit A
Declaration of Trust

                                   ARTICLE 13

                               TRANSFERS OF SHARES


     13.1 Transfer or Resignation by Managing Shareholder. The Managing
Shareholder shall not sell, assign or otherwise transfer its Management Share or
resign without cause (which cause shall not include the fact or the
determination that continued service would be unprofitable to the Managing
Shareholder) without first obtaining the consent of a Majority of the Investors,
except that (i) the Managing Shareholder may pledge its Management Share for a
loan to the Managing Shareholder provided that such pledge does not reduce the
cash flow of the Trust distributable to other Shareholders and (ii) the Managing
Shareholders may not waive or assign compensation or fees payable to it.

     13.2 Transfers; by Investors. An Investor may sell, exchange or transfer
his Shares except as restricted by and upon compliance with all applicable laws
and all of the following provisions of this Section 13.2:

     (a) Shares may not be transferred to any person or entity if, as determined
by the Trust; such assignment would have adverse regulatory consequences to
the Trust or any Trust Property.

     (b) Within 30 days after written notice of a proposed sale or assignment is
received by the Trust from an Investor, the Trust may request in its sole
discretion an opinion of counsel acceptable to the Trust that the proposed
transfer (i ) would not invalidate the exemption afforded by Section 4(2) of the
Act or by Regulation D promulgated under the Act and the exemption afforded by
any applicable state securities laws as to any offering of interests in the
Trust and (ii) complies with the exemption afforded by Section 4(1) of the Act
and qualifies for an exemption from registration under any applicable state
securities laws (including any investor suitability standard applicable to the
transferee or the Trust).

     (c) The written approval of the Managing Shareholder must be obtained, the
granting or denial of which shall be within its sole and absolute discretion.

     (d) The transferor and transferee must deliver a dated notice in writing
signed by each, confirming that at (i) transferee accepts and agrees to comply
with all the terms of this Declaration and (ii) the transfer was made in
compliance with this Declaration and all applicable laws and regulations.

     (e) The transferor, transferee and the Trust must execute all other
certificates, instruments and documents and take all such additional action as
the Trust may deem appropriate.

     (f) The Trust may require as a condition to any transfer that may create a
future interest that an opinion of counsel acceptable to the Trust be delivered
to the Trust confirming that the proposed transfer does not have adverse effects
on the Trust under the rule against perpetuities or similar provisions of law.

Transfers shall be effective and recognized upon fulfillment of the requirements
of clauses (a) through (f) above and the transferee shaft be an Investor owning
Investor Shares with the same rights as appertained to the transferor. Any
purported sale or transfer consummated without first complying with this
Section 13.2 shall be void.

     13.3 Assignments by Operation of Law. If any Investor shall die, with or
without leaving a will, or become non compos mentis, bankrupt or insolvent, or
if a corporate, partnership or trust Investor dissolves during the Trust term or
if any other involuntary transfer of an Investor's Shares is made, the legal
representatives, heirs and-legatees (and spouse, if the Shares have been
community property of such investor and his or her spouse), bankruptcy
assignees, successors, assigns and corporate, partnership or trust distributees
or such other involuntary transferees shall not become transferees but shall
have (subject to the other terms and provisions hereof) such rights as are
provided with respect to such persons under the law; and legatees, spouse,
bankruptcy, bankruptcy assignees, successors, assigns and corporate, partnership
or trust distributees or involuntary transferees may become transferees in
accordance with the provisions of Section 13.2.

     13.4 Expenses of Transfer. In the sole discretion of the Trust, the any of
the provisions of this Article 13 may be required to bear all costs and expenses
neecessary so effect a transfer

                                       28



                                                                       Exhibit A
                                                            Declaration of Trust

of such Shares including, without limitation, reasonable attorney's fees
incurred in preparing any required amendments to this Declaration and the
Certificate to reflect such transfer or acquisition and the cost of filing such
amendments with the appropriate governmental officials.

     13.5 Survival of Liabilities. No sale or assignment of Shares shall release
the transferor from those liabilities to the Trust which survive such assignment
or sale as a matter of law or that are imposed under Section 3.4.

     13.6 No Accounting. No transfer of Shares, whether voluntary, involuntary
or by operation of law, shall entitle the transferor or transferee to demand or
obtain immediate valuation, accounting or payment of the transferred Shares.

                                   ARTICLE 14

                    DISSOLUTION, TERMINATION AND LIQUIDATION

     14.1 Dissolution. Unless the provisions of Section 14.2 are elected, the
Trust shall be dissolved and its business shall be wound up upon the decision of
the Managing Shareholder to withdraw the offering of Shares described in the
Memorandum in accordance with Section 12.4(g) or on the earliest to occur of:

     (a) Forty years from the effective date of this Declaration;

     (b) The sale of all or substantially all of the Trust Property;

     (c) The death, removal, dissolution, resignation, insolvency, bankruptcy or
other legal incapacity of the Managing Shareholder or any other event which
would legally disqualify the Managing Shareholder from acting hereunder;

     (d) The decision of all Investors or the Managing Shareholder and a
Majority of Investors; or

     (e) The occurrence of any other event which, by law, would require the
Trust to be dissolved.

     14.2 Continuation of the Trust. Upon the occurrence of any event of
dissolution described in Sections 14.1 (a) through (e), inclusive, the Trust
shall be dissolved and wound up unless (i) the Managing Shareholder and a
Majority of the Investors (calculated without regard to Investor Shares owned by
the Managing Shareholder or its Affiliates) within 90 days after the occurrence
of any such event of dissolution elect to continue the Trust or, (ii) it there
is no remaining Managing Shareholder, within 90 days after the occurrence of any
such event of dissolution, a Majority of the Investors shall elect, in writing,
that the Trust shall be continued on the terms and conditions herein contained
and shall designate one or more persons willing to be substituted as a Managing
Shareholder or Managing Shareholders. In the event there is no remaining
Managing Shareholder and a Majority of the Investors elect to continue the
Trust, it shall be continued with the new Managing Shareholder or Managing
Shareholders who shall succeed to and assume all of the powers, privileges and
obligations of the previous Managing Shareholder or Managing Shareholders
hereunder except as specified in Section 12.11. In the event of a dissolution
under this Section 14.2, the former Managing Shareholder or Managing
Shareholders shall have the rights specified in Section 12.11.

     14.3 Obligations on Dissolution. The dissolution of the Trust shall not
release any of the parties hereto from their contractual obligations under this
Declaration.

     14.4 Liquidation Procedure. Upon dissolution of the Trust for any reason:

     (a) A reasonable time shall be allowed for the orderly liquidation of the
assets of the Trust and the discharge of liabilities to creditors so as to
enable the Trust to minimize the losses normally attendant to a liquidation;

                                       29


Exhibit A
Declaration of Trust

     (b) The Shareholders shall continue to receive Net Cash Flow, subject to
the other provisions of this Declaration and to the provisions of subsection (c)
hereof, and shall share Profits and Losses for all tax and other purposes during
the period of liquidation; and

     (c) Ridgewood Power shall act as liquidating Managing Shareholder (or, in
its absence, any other Managing Shareholder shall act) and shall proceed to
liquidate the Trust Properties to the extent that they have not already been
reduced to cash unless the liquidating Managing Shareholder elects to make
distributions in kind to the extent and in the manner herein provided and such
cash, If any, and property in kind, shall be applied and distributed in
accordance with Article 8 and Section 9.5(g) (if applicable).

     14.5 Liquidating Trustee. (a) If the dissolution of the Trust is caused by
circumstances under which no Managing Shareholder shall be acting as a Managing
Shareholder or if all liquidating Managing Shareholders are unable or refuse to
act, a Majority of the Investors shall appoint a liquidating trustee who shall
proceed to wind up the business affairs of the Trust. The liquidating trustee
shall have no liability to the Trust onto any Shareholder for any loss suffered
by the Trust which arises out of any action or Inaction of the liquidating
trustee if the liquidating trustee, in good faith, determined that such course
of conduct was in the best interests of the Shareholders and such course of
conduct did not constitute negligence or misconduct of the liquidating trustee.
The liquidating trustee shall be indemnified by the Trust against any losses,
judgments, liabilities, expenses and amounts paid in settlement of any claims
sustained by it in connection with the Trust, provided that the same were not
the result of negligence or misconduct of the liquidating trustee.

     (b) Notwithstanding the above, the liquidating trustee shall not be
indemnified and no expenses shall be advanced on its behalf for any losses,
liabilities or expenses arising from or out of an alleged violation of federal
or state securities laws, unless (1) there has been a successful adjudication on
the merits of each count involving alleged securities law violations as to the
particular indemnitee, or (2) such claims have been dismissed with prejudice on
the merits by a court of competent jurisdiction as to the particular indemnitee,
or (3) a court of competent jurisdiction approves a settlement of the claims
against a particular indemnitee.

     (c) In any claim for indemnification for federal or state securities law
violations, the party seeking indemnification shall place before the court the
position of the Securities and Exchange Commission and the Massachusetts
Securities Division (if. applicable) and the Tennessee Securities Division (if
applicable), or other applicable securities administrators if required, with
respect to the issue of indemnification for securities law violations.

     (d) The Trust shall not incur the cost of that portion of any insurance,
other than public liability insurance, which insures any party against any
liability the indemnification of which is herein prohibited.

     14.6 Death, Insanity, Dissolution or insolvency of an Investor or Trustee.
The death, insanity, dissolution, winding up, insolvency, bankruptcy,
receivership or other legal termination of a Trustee or an Investor who is not a
Managing Shareholder shall have no effect on the life of the Trust and the Trust
shall not be dissolved thereby.

     14.7 Managing Shareholder's Capital Contributions. Upon or prior to the
first distribution in liquidation, the Managing Shareholder shall contribute to
the capital of the Trust an amount equal to any deficit in the Capital Account
of such Managing Shareholder calculated just prior to the date of such
distribution, to the extent not previously contributed.

     14.8 Withdrawal of Offering. Dissolution of the Trust resulting from
withdrawal of the offering of Shares is governed by Section 1.6(c) and Section
12.4(g).

                                   ARTICLE 15

                                  MISCELLANEOUS

     15.1 Notices. Notices or instruments of any kind which may be or are
required to be given hereunder by any person to another shall be in writing and
deposited In the United States Mail, certified or registered, postage

                                       30



                                                                       Exhibit A
                                                            Declaration of Trust


prepaid, addressed to the respective person at the address appearing in the
records of the Trust. Any Investor may change his address by giving notice in
writing, stating his new address, to the Trust. Any notice shall be deemed to
have been given effective as of 72 hours, excluding Saturdays, Sundays and
holidays, after the depositing of such notice in an official United States Mail
receptacle. Notice to the Trust may be addressed to its principal office.

     15.2 Meetings of Shareholders. (a) Meetings. The Managing Shareholder may
call meetings of the Shareholders, the Investors or any subgroup thereof
concerning any matter on which they may vote as provided by this Declaration or
by law or to receive and act upon a report of the Managing Shareholder on
matters pertaining to the Trust's business and activities. Investors holding 10%
or more of the outstanding securities or Shares entitled to vote on the matter
may also call meetings by giving notice to the Trust demanding a meeting and
stating the purposes therefor. After calling a meeting or within 20 days after
receipt of a written request or requests meeting the requirements of the
preceding sentence, the Trust shall mail to all Shareholders entitled to vote on
the matter written notice of the place and purposes of the meeting, which shall
be held on a date not less than 15 days nor more than 45 days after the Trust
mails the notice of meeting to the Shareholders. Any Shareholder or Investor
entitled to vote on the matter may appear and vote or consent at a meeting by
proxy, provided that such authority is granted by a writing signed by the
Shareholder or Investor and delivered to the Trust at or prior to the meeting.

     (b) Consents. Any consent required by this Declaration or any vote or
action by the Shareholders, the Investors or any subgroup thereof may be
effected without a meeting by a consent or consents in writing signed by the
persons required to give such consent, to vote or to take action. The Managing
Shareholder may solicit consents or Investors holding 10% or more of the
outstanding securities or Shares entitled to vote on the matter may demand a
solicitation of consents by giving notice to the Trust stating the purpose of
the consent and including a form of consent. The Trust shall effect a
solicitation of consents by giving those Shareholders or the Investors, as
the case may be, a notice of solicitation stating the purpose of the consent, a
form of consent and the date on which the consents are to be tabulated, which
shall be not less than 15 days nor more than 45 days after the Trust transmits
the notice of solicitation for consents. If Investors holding 10% or more of the
outstanding securities or Shares entitled to vote on the matter demand a
solicitation, the Trust shall transmit the notice of solicitation not later than
20 days after receipt of the demand.

     (c) General. To the extent not inconsistent with this Declaration, Delaware
law governing stockholders' meetings, proxies and consents for corporations
shall apply as to the procedure, validity and use of meetings, proxies and
consents. Any Shareholder may waive notice of or attendance at any meeting or
notice of any consent, whether before or after any action is taken. The date on
which the Trust transmits the notice of meeting or notice soliciting consents
shall be the record date for determining the right to vote or consent. A list of
the names, addresses and shareholdings of all Shareholders shall be maintained
as part of the Trust's books and records.

     15.3 Loan to Trust by Shareholder. If any Shareholder shall, in addition to
his Capital Contribution to the Trust, lend any monies to the Trust, the amount
of any such loan shall not increase his Capital Account nor shall it entitle him
to any increase in his share of the distributions of the Trust, but the amount
of any such loan shall be an obligation on the part of the Trust to such
Shareholder and shall be repaid to him on the terms and at the interest rate
negotiated at the time of the loan, and the loan shall be evidenced by a
promissory note executed by the Trust except that no Shareholder shall be
personally obligated to repay the loan, which shall be payable and collectible
only out of the assets of the Trust.

     15.4 Delaware Laws Govern. This Declaration shall be governed and construed
in accordance with the laws of the State of Delaware, and venue for any
litigation between or against any of the parties hereto may be maintained in New
Castle County, Delaware; however, residents of Massachusetts may, at their
option, choose to maintain any such litigation in the Commonwealth of
Massachusetts.

     15.5 Power of Attorney. Each Investor irrevocably constitutes and appoints
the Managing Shareholder as his true and lawful attorney-in-fact and agent to
effectuate and to act in his name, place and stead, in effectuating the purposes
of the Trust including the execution, verification, acknowledgment, delivery,
filing and recording of this Declaration as well as all authorized amendments
thereto and hereto, all assumed name and doing business certificates, documents,
bills of sale, assignments and other instruments of conveyances, leases,
contracts, loan documents and counterparts thereof, and all other documents
which may be required to effect a continuation of the Trust and which the Trust
deems necessary or reasonably appropriate, including documents required to be
executed in order to correct typographical errors in documents previously
executed by such Investor and all conveyances

                                       31



Exhibit A
Declaration of Trust

and other instruments or other certificates necessary or appropriate to effect
an authorized dissolution and liquidation of the Trust. The power of attorney
granted herein shall be deemed to be coupled with an interest, shall be
irrevocable and shall survive the death, incompetency or legal disability of an
Investor.

     15.6 Dlsclaimer. In forming this Trust, all Investors recognize that the
independent power business Is highly speculative and that neither the Trust nor
the Managing Shareholder nor any Trustee nor any other Managing Person makes any
guaranty or. representation to any Investor as to the probability or amount of
gain or loss from the conduct of Trust business.

     15.7 Corporate Trustee Resignation and Replacement. The Managing
Shareholder may increase or decrease the number of Corporate Trustees so long as
there is at least one Corporate Trustee which meets the requirements of Section
3807 of the Delaware Act. A Corporate Trustee may resign by delivering a written
resignation to the Managing Shareholder not less than 60 days prior to the
effective date of the resignation. The Managing Shareholder may remove a
Corporate Trustee at any time, provided that if there is no incumbent, at least
one new Corporate Trustee is concurrently appointed. In the event of the
absence, death, resignation, removal, dissolution, insolvency, bankruptcy or
legal incapacity of a Corporate Trustee or if an additional Corporate Trustee is
to be appointed, the Managing Shareholder shall appoint the Corporate Trustee in
writing and shall subsequently give notice to the Investors, although such
notice is not necessary to the validity of the appointment. A Corporate Trustee
so appointed shall qualify by filing his written acceptance at the Trust's
principal place of business. If there are multiple Corporate Trustees, each is
vested with an undivided interest in the trust estate and may exercise all
powers vested in the Corporate Trustee as directed by the Managing Shareholder.

     15.8 Amendment and Constriction of Declaration. (a) This Declaration may be
amended by the Managing Shareholder, without notice to or the approval of the
Investors, from time to time for the following purposes: (1) to cure any
ambiguity, formal defect or omission or to correct or supplement any provision
herein that may be inconsistent with any other provision contained herein or in
the Memorandum or to effect any amendment without notice to or approval by
Investors as specified in other provisions of this Declaration; (2) to make such
other changes or provisions in regard to matters or questions arising under this
Declaration that will not materially and adversely affect the interest of any
Investor; (3) to otherwise equitably resolve issues arising under the Memorandum
or this Declaration so long as similarly situated Investors are not treated
materially differently; (4) to maintain the federal tax status of the Trust and
any of its Shareholders (so long as no Investors liability is materially
increased without his consent) or as provided in Section 4.3(d); and (5) to
comply with law.

     (b) Other amendments to this Declaration may be proposed by either the
Managing Shareholder or Investors owning 10% or more of the outstanding Shares,
in each case by calling a meeting of Investors or requesting consents under
Section 15.2 and specifying the text of the amendment and the reasons therefor.
No amendment under this Section 15.8(b) that increases any Shareholders
liability, changes the Capital Contributions required of him or his rights in
interest in the Profits, Losses, deductions, credits, revenues or distributions
of the Trust in more than a de minimis manner, his rights on dissolution, or any
voting or management rights set forth in this Declaration shall become effective
as to that Shareholder without his written approval thereof. Unless otherwise
provided herein, all other amendments must be approved by the holders of a
Majority of the outstanding Shares (calculated without regard to Shares owned by
the Managing Shareholder and its Affiliates), and, if the terms of a series of
Shares or securities so require, by the vote of the holders of such class,
series or group specified therein.

     (c) The Managing Shareholder has power to construe this Declaration and to
act upon any such construction. Its construction of the same and any action
taken pursuant thereto by the Trust or a Managing Person in good faith shall be
final and conclusive.

     15.9 Bonds and Accounting. The Trustees and other Managing Persons shall
not be required to give bond or otherwise post security for the performance of
their duties and the Trust waives all provisions of law requiring or permitting
the same. No person shall be entitled at any time to require the Trustees, the
Trust or any Shareholder to submit to a judicial or other accounting or
otherwise elect any judicial, administrative or executive supervisory proceeding
applicable to non-business trusts.

     15.10 Binding Effect. This Declaration shall be binding upon and shall
inure to the benefit of the Shareholders (and their spouses if the Shares of
such Shareholders shall be community property) as well as their respective
heirs, legal representatives, successors and assigns. This Declaration
constitutes the entire agreement


                                       32



                                                                       Exhibit A
                                                            Declaration of Trust

among the Trust, the Trustees and the Shareholders with respect to the formation
and operation of the Trust, other than the Subscription Agreement entered into
between the Trust and each Investor and the Management Agreement.

     15.11 Headings. Headings of Articles and Sections used herein are for
descriptive purposes only and shall not control or alter the meaning of this
Declaration as set forth in the text.

     15.12 Tax Matters Partner. The Managing Shareholder or its designee shall
be designated the tax matters partner of the Trust pursuant to Code Section
6221.


     IN WITNESS WHEREOF, the undersigned have signed this Declaration as of the
date first above written.

                                           RIDGEWOOD ENERGY HOLDING CORPORATION,
                                              Grantor and Corporate Trustee

                                           By: /s/ Robert E. Swanson
                                              ----------------------------------
                                               Robert E. Swanson, President


                                           RIDGEWOOD POWER CORPORATION,
                                               Managing Shareholder

                                           By: /s/ Robert E. Swanson
                                              ----------------------------------
                                               Robert E. Swanson, President




                                       33

EX-3.IID

                                                                Exhibit 3(ii)(D)

                             January 2005 Amendment
                                     of the
                              Declaration of Trust
                                       of
                       Ridgewood Electric Power Trust III


     This January 2005 Amendment of the Declaration of Trust of Ridgewood
Electric Power Trust III (the "January 2005 Amendment") is made by Ridgewood
Renewable Power LLC, as Managing Shareholder of Ridgewood Electric Power Trust
III (the "Trust") effective as of January 1, 2005.

     Whereas, the Declaration of Trust which created the Trust was executed by
the Managing Shareholder and Ridgewood Energy Holding Corporation as grantor and
corporate trustee ("Corporate Trustee") as of January 3, 1994 and was amended
and restated in its entirety by the Managing Shareholder by Written Consent
dated November 21, 1994 (together, the "Original Declaration"); and

     Whereas, by letter dated August 18, 1997 (the "August 1997 Amendment"), the
Managing Shareholder informed the Shareholders of the Trust that the Managing
Shareholder was voluntarily modifying the sharing arrangements between the
Shareholders and the Managing Shareholder under the Original Declaration for the
benefit of the Shareholders; and

     Whereas, the Original Declaration was further amended by the Managing
Shareholder pursuant to a "Consent in Writing" effective January 1, 2000 (the
"January 2000 Amendment"); and

     Whereas, the Original Declaration was further amended by a written
instrument executed by the Corporate Trustee of the Trust, as of December 20,
2001 (the "December 2001 Amendment"); and

     Whereas, the Original Declaration was further amended by a written
instrument executed by the Corporate Trustee of the Trust, as of December 18,
2003 (the "December 2003 Amendment"); and

     Whereas, the Original Declaration, as amended by the August 1997 Amendment,
the January 2000 Amendment, the December 2001 Amendment and the December 2003
Amendment is herein referred to as the "Amended Declaration"; and


                                       1


     Whereas, except as set forth herein, terms set forth in capital letters
herein shall have the meanings assigned to such terms in the Amended
Declaration; and

     Whereas, Section 15.8 of the Amended Declaration authorizes the Managing
Shareholder to make amendments to the Amended Declaration without notice to or
approval of the Shareholders in a variety of circumstances, including, without
limitation, amendments to maintain the tax status of the Trust; and

     Whereas, tax counsel for the Trust has recommended that certain provisions
of the Trust be amended to clear up potential ambiguity and to maintain the tax
status of the Trust; and

     Whereas, the Managing Shareholder has reviewed the proposed amendments to
the Amended Declaration recommended by tax counsel for the Trust, and has
concluded that the amendment of the Amended Declaration in the manner
recommended by tax counsel for the Trust will not materially and adversely
affect the interests of the Shareholders in the Trust.

     Now, therefore, the Amended Declaration is further amended as follows:

          1. Article 4 of the Amended Declaration is hereby amended by inserting
     new Sections 4.9 through 4.13 immediately following the end of existing
     Section 4.8 as follows:

          "4.9 General Application. Notwithstanding any other provision of this
          Declaration, for all fiscal periods beginning on or after January 1,
          2005, the rules set forth below in Sections 4.10 through 4.13 shall
          apply for the purposes of determining each Shareholder's allocable
          share of the items of income, gain, loss and expense of the Trust
          comprising Profits or Losses of the Trust for each fiscal period,
          determining special allocations of other items of income, gain, loss
          and expense, and adjusting the balance of each Shareholder's Capital
          Account to reflect the aforementioned general and special allocations.
          For each fiscal period, the special allocations in Section 4.11 and
          Article VII shall be made immediately prior to the general allocations
          of Section 4.10. The provisions of Sections 4.3(b), 4.3(d) and 4.4
          shall continue to apply."

          "4.10 General Allocations.

               (a) Hypothetical Liquidation. The items of income, expense, gain
          and loss of the Trust comprising Profits or Losses for a fiscal period



                                       2



          shall be allocated among the Shareholders in a manner that will, as
          nearly as possible, cause the Capital Account balance of each
          Shareholder at the end of such fiscal period to equal the excess
          (which may be negative) of:

               (i) the amount of the hypothetical distribution (if any) that
          such Shareholder would receive if, on the last day of the fiscal
          period, (x) all Trust assets, including cash, were sold for cash equal
          to their book values, taking into account any adjustments thereto for
          such Fiscal Year, (y) all Trust liabilities were satisfied in cash
          according to their terms (limited, with respect to each nonrecourse
          liability, to the book values of the assets securing such liability),
          and (z) the net proceeds thereof (after satisfaction of such
          liabilities) were distributed in full pursuant to Section 8.1(g), over

               (ii) the sum of (x) the amount, if any, without duplication, that
          such Shareholder would be obligated to contribute to the capital of
          the Trust, (y) such Shareholder's share of Partnership Minimum Gain
          determined pursuant to Regulations Section 1.704-2(g), and (z) such
          Shareholder's share of Partner Nonrecourse Debt Minimum Gain
          determined pursuant to Regulations Section 1.704-2(i)(5), all computed
          as of the hypothetical sale described in Section 4.10 (a)(i).

               (b) Determination of Items Comprising Allocations.

               (i) If the Trust has Profits for a fiscal period,

               (A) for any Shareholder as to whom the allocation pursuant to
          Section 4.10 (a) would reduce its Capital Account, such allocation
          shall be comprised of a proportionate share of each of the Trust's
          items of expense or loss entering into the computation of Profits for
          such fiscal period; and

               (B) the allocation pursuant to Section 4.10(a) in respect of each
          Shareholder (other than a Shareholder referred to in Section
          4.10(b)(i)(A) hereof) shall be comprised of a proportionate share of
          each Trust item of income, gain, expense and loss entering into the
          computation of Profits for such fiscal period (other than the portion
          of each Trust item of expense and loss, if any, that is allocated
          pursuant to Section 4.10(b)(i)(A) hereof).

               (ii) If the Trust has a Loss for a fiscal period,

               (A) for any Shareholder as to whom the allocation pursuant to
          Section 4.10 (a) hereof would increase its Capital Account, such
          allocation shall be comprised of a proportionate share of each of the
          Trust's items of income and gain entering into the computation of Loss
          for such fiscal period; and

               (B) the allocation pursuant to Section 4.10(a) hereof in respect
          of each Shareholder (other than a Shareholder referred to in Section



                                       3


          4. 1 0(b)(ii)(A) hereof) shall be comprised of a proportionate share
          of each Trust item of income, gain, expense and loss entering into the
          computation of Loss for such fiscal period (other than the portion of
          each Trust item of income and gain, if any, that is allocated pursuant
          to Section 4.10(b)(ii)(A) hereof).

               (c) Loss Limitation. Notwithstanding anything to the contrary
          contained in this Section 4.10, the amount of items of Trust expense
          and loss allocated pursuant to this Section 4.10 to any Shareholder
          shall not exceed the maximum amount of such items that can be so
          allocated without causing such Shareholder (other than a Managing
          Shareholder) to have a deficit in his Adjusted Capital Account at the
          end of any fiscal period. All such items in excess of the limitation
          set forth in this Section 4.10(c) shall be allocated first to
          Shareholders who would not have a deficit in his Adjusted Capital
          Account, pro rata, until no Shareholder would be entitled to any
          further allocation, and thereafter to the Managing Shareholder.

               (d) No Deficit Restoration Obligation. At no time during the term
          of the Trust or upon dissolution and liquidation thereof shall a
          Shareholder with a negative balance in its Capital Account have any
          obligation to the Trust or the other Shareholders to restore such
          negative balance, except as may be required by law or in respect of
          any negative balance resulting from a withdrawal of capital or
          dissolution in contravention of this Declaration."

          "4.11 Special Allocations. The following special allocations shall be
          made in the following order:

               (a) Deficit Capital Accounts Generally. If a Shareholder has a
          deficit Capital Account balance at the end of any fiscal period which
          is in excess of the sum of (i) the amount such Shareholder is then
          obligated to restore pursuant to this Declaration, and (ii) the amount
          such Shareholder is then deemed to be obligated to restore pursuant to
          the penultimate sentences of Regulations Sections 1.704-2(g)(1) and
          1.704-2(i)(5), respectively, such Shareholder shall be specially
          allocated items of Trust income and gain in an amount of such excess
          as quickly as possible, provided that any allocation under this
          Section 4.11(a) shall be made only if and to the extent that a
          Shareholder would have a deficit Capital Account balance in excess of
          such sum after all allocations provided for in this Article 4 have
          been tentatively made as if this Section 4.11(a) were not in this
          Declaration.

               (b) Allocation of Nonrecourse Deductions. Each Nonrecourse
          Deduction of the Trust shall be specially allocated 1% to the Managing
          Shareholder and 99% to all of the Investors in proportion to their
          Capital Contributions.


                                       4


          The allocations pursuant to Sections 4.11(a) and (b) shall be
          comprised of a proportionate share of each of the Trust's items of
          income and gain."

          "4.12 Allocation of Nonrecourse Liabilities. For purposes of
          determining each Shareholder's share of Nonrecourse Liabilities, if
          any, of the Trust in accordance with Regulations Section
          1.752-3(a)(3), the Shareholders' interests in Trust Profits shall be
          determined in the same manner as prescribed by Section 4.11(b)."

          "4.13 Credits. All tax credits shall be allocated among the
          Shareholders as determined by the Managing Shareholder in its sole and
          absolute discretion, consistent with applicable law (including IRC
          Section 704(b) and the Treasury Regulations promulgated thereunder)."

          2. Section 6.1 (a)(4) of the Amended Declaration is hereby amended by
     inserting the phrase ",4.11" after the phrase "4.8" and before the phrase
     "and 7.4" at the end of such subsection.

          3. Section 6.1 (b)(3) of the Amended Declaration is hereby amended by
     inserting the phrase ",4.11" after the phrase "4.7" and before the phrase
     "and 7.4" at the end of such subsection.

          4. Section 7.4(d) of the Amended Declaration is hereby amended as
     follows:

               (a) by deleting the phrase "Sections 4.1 and 4.2" in the third
               line thereof and inserting in lieu thereof the phrase "Sections
               4.1, 4.2 and 4.10;"

               (b) by deleting the phrase "Sections 4.1 and 4.2" in the fourth
               line thereof and inserting in lieu thereof the phrase "Sections
               4.1, 4.2 and 4.10," and

               (c) by inserting the phrase "or Section 4.11" following the
               phrase "Section 7.4" in the fifth line thereof.

          5. Section 8.1 (e)(1) of the Amended Declaration is hereby amended by
     deleting clause (A) in the second line thereof and inserting a new clause A
     in lieu thereof, as follows:

               (A) the sum of (x) an amount equal to 14% of the Investors
               Average Annual Capital Contribution, plus (y) an additional
               amount equal to the amount by which distributions of Net Cash
               Flow to Investors with respect to all prior calendar years are
               less than the priority distribution amounts determined under this
               Section 8.1(e) for such calendar years; or"

          6. Section 8.1 (g)(3) of the Amended Declaration is hereby amended by
     inserting a period immediately after the phrase "Sections 8.1 (d), (e) and
     (g) (3)" in the fifth line thereof and deleting the remainder of such
     subsection.


                                       5


               7. Section 8.1 (g)(4) of the Amended Declaration is hereby
          amended by deleting such provision in its entirety and inserting a new
          provision in lieu thereof as follows:

               "(4) Fourth, the balance, if any, to the Shareholders in
               accordance with Section 8.1(c)."

               8. The Amended Declaration is hereby further amended by deleting
          Section 14.7 in its entirety.

               Notwithstanding anything herein to the contrary, the provisions
          of this January 2005 Amendment shall not be construed or interpreted
          in a manner that adversely affects the interests of the Investors as
          such existed immediately prior to the adoption of this January 2005
          Amendment. The Amended Declaration, as amended by this January 2005
          Amendment, continues in full force and effect.

               IN WITNESS WHEREOF, Ridgewood Renewable Power LLC, as Managing
          Shareholder of the Trust, has executed this January 2005 Amendment
          effective as of January 1, 2005.


                                            Ridgewood Renewable Power LLC

                                            By: /s/ Douglas R. Wilson
                                                -------------------------
                                            Name: Douglas R. Wilson
                                            Title: EVP/CFO



                                       6

EX-10.2

                                                                    Exhibit 10.2

                                AMENDMENT TO THE

                            POWER PURCHASE AGREEMENT

                                     BETWEEN

                           BYRON POWER PARTNERS, L.P.

                                       AND

                        PACIFIC GAS AND ELECTRIC COMPANY

                              (PG&E LOG NO. 16C047)


     THIS AMENDMENT ("Amendment") is by and between PACIFIC GAS AND ELECTRIC
COMPANY ("PG&E"), a California corporation and Byron Power Partners, L.P., a
California limited partnership ("Seller"). PG&E and Seller are sometimes
referred to herein individually as "Party" and collectively as the "Parties"


                                    RECITALS

     A. On April 15, 1985, Seller (or Seller's predecessor, as applicable) and
entered into a Power Purchase Agreement, (as amended, "the PPA") pursuant to
which PG&E purchases electric power from Seller and Seller sells electric power
to PG&E.

     B. On April 6, 2001, PG&E filed voluntary petition under chapter 11 of the
United States Bankruptcy Code in the San Francisco Division of the United States
Bankruptcy Court for the Northern District of California (the "Bankruptcy
Court") (In re Pacific Gas and Electric Company, Banks. Case No. 01-03923).

     C. On June 14, 2001, the Commission issued D.01-06-015, which approved as
reasonable certain non-standard PPA price modifications.

     D. Seller and PG&E now desire to enter into the PPA price modification set
forth below. Seller has advised PG&E that Seller is unable to enter into the
PPA price modification unless the Bankruptcy Court has approved this Amendment
and Seller is provided a limited option to terminate this Amendment following
Bankruptcy Court approval if Seller is unable to


                                     1 of 3



Arrange for fuel purchases to accommodate the price modification contemplated
under this Amendment.


                                    AMENDMENT

     In consideration of the mutual promises and covenants contained herein,
PG&E and Seller agree to as follows:

     1. INTERIM ENERGY PRICE

     Unless otherwise set fourth in the PPA, for the period commencing with the
date on which this Amendment has been executed by the Parties and ending upon
the commencement of the Fixed Rate Period, as defined in Section 2 below, the
price for energy delivered, if any, to PG&E by Seller shall be determined
pursuant to the PPA, without reference to this Amendment.

     2. FIXED ENERGY PRICE

     Commencing with this date that is the earlier of, August 1, 2001, August
16, 2001 or September 1, 2001 following approval of the Bankruptcy Court as
specified in Section 4 below (hereafter, the "Bankruptcy Court Approval Date")
and ending on July 15, 2006 (this period referred to hereafter as the "Fixed
Rate Period"), Seller elects to replace the energy price term specified in the
PPA (PG&E's "full short-run avoided costs" or "full short-run avoided operating
costs" as the case may be) with the applicable energy prices as specified in
Attachment A. No provision of the PPA other than the energy price term is or
shall be deemed to be modified, amended, waived or otherwise affected by this
Amendment. The parties agree to reasonably cooperate and contest any challenge
in any Commission proceeding that seeks to alter or modify the energy pricing
terms set fourth in Attachment A, including, but not limited to any challenge to
the reasonableness of PG&E having entered into this Amendment.

                                    2 of 3


     3. SELLER'S OPTION PERIOD

     For a fifteen-day period following the Bankruptcy Court Approval Date,
Seller shall have the sole right to terminate this Amendment. Upon termination
of this Amendment pursuant to this section 3, this Amendment shall be deemed a
nullity.

     4. EFFECTIVENESS

     This Amendment shall not become effective unless and until it has been
approved by the Bankruptcy Court. If the Bankruptcy Court has not approved this
Amendment by August 31, 2001, this Amendment shall be deemed a nullity.

     5. SIGNATURES

     IN WITNESS WHEREOF, Seller and PG&E have caused this Amendment to be
executed by their authorized representatives.


PACIFIC GAS AND ELECTRIC COMPANY
 a California corporation

By:   [illegible]
      -------------------------

Title: [illegible]
      -------------------------

Date: 7/14/01
      -------------------------

BYRON POWER PARTNERS, L.P.
a California limited partnership

By:   [illegible]
      -------------------------

Title: Ex VP & COO
      -------------------------

Date: 7/13/01
      -------------------------


                       3 of 3


Pacific Gas and Electric Company




June 1, 1993

[LOGO OMITTED]    ALTAMONT COGENERATION CORPORATION
                  Attn: Bob Pollock
                  c/o Wankesha-Pearce
                  12320 South Main
                  HOUSTON, TX 77235-5068

                  Dear Sir/Madam:

                  This is to notify you of a change of address for Article 9,
                  "Notices", of the Power Purchase Agreement (PPA) between PG&E
                  and Altamont Cogeneration Corporation. Please direct all
                  future written notices to:

                                   Mr. Richard A. Lavne
                                   Director, Power Finance Department, B13D
                                   Pacific Gas and Electric Company
                                   77 Beale Street, Room 1311
                                   P.O. Box 770000 San
                                   Francisco, CA 94177

                  The address in the PPA relating to insurance matters has also
                  changed. All insurance certificates, endorsements.
                  cancellations, terminations, alterations, and material changes
                  of such insurance must be issued and submitted to the
                  following:

                                   Pacific Gas and Electric Company
                                   Power Contracts Department - B23C
                                   Attn: Insurance Coordinator
                                   P.O. Box 770000, Room 2354
                                   San Francisco, CA 94177

                  CPUC Decision 93-04-001 dated April 7, 1993, adopted the
                  Division of Ratepayer Advocate's recommendation for modifying
                  the reporting requirements applicable to the quarterly report
                  of negative avoided cost or hydro spill. The above decision
                  ordered that: Decision (D) 82-01-103, Ordering Paragraph 17,
                  is modified to read in full as follows:

                        "Each utility shall promptly file a report for any
                        quarter in which a negative avoided cost or hydro
                        spill condition occurs."

                  Please inform all parties in your organization of the above
                  information. If you have any questions please call me at (415)
                  973-4966.


                  Sincerely,


                  /s/ Dave Harrison
                  Dave Harrison
                  Power System Analyst
                  (415)973-4966



                        PACIFIC GAS AND ELECTRIC COMPANY

                               STANDARD OFFER #4

                            POWER PURCHASE AGREEMENT

                                      FOR

                         LONG-TERM ENERGY AND CAPACITY




     Seller: Fayette Manufacturing Corporation

     Location: Altamont Pass

     Nameplate Rating: 6,500 kW

     Firm Capacity: 5,700 kW

     Energy Source: Natural Gas







                                    MAY 1984


                                                                          S.O #4
                                                                     May 7, 1984

                                       1


                               STANDARD OFFER #4:
                          LONG-TERM ENERGY AND CAPACITY
                            POWER PURCHASE AGREEMENT



                                    CONTENTS



     Article                                                                Page
     -------                                                                ----

     1         QUALIFYING STATUS                                             3

     2         COMMITMENT OF PARTIES                                         4

     3         PURCHASE OF POWER                                             5

     4         ENERGY PRICE                                                  6

     5         CAPACITY ELECTION AND CAPACITY PRICE                         10

     6         LOSS ADJUSTMENT FACTORS                                      11

     7         CURTAILMENT                                                  11

     8         RETROACTIVE APPLICATION OF CPUC ORDERS                       12

     9         NOTICES                                                      12

     10        DESIGNATED SWITCHING CENTER                                  13

     11        TERMS AND CONDITIONS                                         13

     12        TERM OF AGREEMENT                                            14



     Appendix A:       GENERAL TERMS AND CONDITIONS

     Appendix B:        ENERGY PAYMENT OPTIONS

     Appendix C:        CURTAILMENT OPTIONS

     Appendix D:        AS-DELIVERED CAPACITY

     Appendix E:        FIRM CAPACITY

     Appendix F:        INTERCONNECTION


                                       2                                  S.O #4
                                                                     May 7, 1984




                          LONG-TERM ENERGY AND CAPACITY

                            POWER PURCHASE AGREEMENT

                                     BETWEEN

                        FAYETTE MANUFACTURING CORPORATION

                                       AND

                        PACIFIC GAS AND ELECTRIC COMPANY



          FAYETTE MANUFACTURING CORPORATION, a Pennsylvania corporation
     ("Seller"), and PACIFIC GAS AND ELECTRIC COMPANY ("PGandE"), referred to
     collectively as "Parties" and individually as "Party", agree as follows:


                          ARTICLE 1 QUALIFYING STATUS

          Seller warrants that, at the date of first power deliveries from
     Seller's Facility' and during the term of agreement, its Facility shall
     meet the qualifying facility requirements established as of the effective
     date of this Agreement by the Federal Energy Regulatory Commission's rules
     (18 Code of Federal Regulations 292) implementing the Public Utility
     Regulatory Policies Act of 1978 (16 U.S.C.A. 796, at seq.).




     ---------------

     1    Underlining identifies those terms which are defined in Section S-1 of
          Appendix A.

                                       3                                  S.O #4
                                                                     May 7, 1984


                         ARTICLE 2 COMMITMENT OF PARTIES



          The prices to be paid Seller for energy and/or capacity delivered
     pursuant to this Agreement have wholly or partly been fixed at the time of
     execution. Actual avoided costs at, the time of energy and/or capacity
     deliveries may be substantially above or below the prices fixed in this
     Agreement. Therefore, the Parties expressly commit to the prices fixed in
     this Agreement for the applicable period of performance and shall not seek
     to or have a right to renegotiate such prices for any reason. As part of
     its consideration for the benefit of fixing part or all of the energy
     and/or capacity prices under this Agreement, Seller waives any and all
     rights to judicial or other relief from its obligations and/or prices set
     forth in Appendices B, D, and E, or modification of any other term or
     provision for any reasons whatsoever.

          This Agreement contains certain provisions which set forth methods of
     calculating damages to be paid to PGandE in the event Seller fails to
     fulfill certain performance obligations. The inclusion of such provisions
     is not intended to create any express or implied right in Seller to
     terminate this Agreement prior to the expiration of the term of agreement.
     Termination of this Agreement by Seller prior to its expiration date shall
     constitute a breach of this Agreement and the damages expressly set forth
     in this


                                       4                                  S.O #4
                                                                     May 7, 1984


     Agreement shall not constitute PGandE's sole remedy for such breach.


                           ARTICLE 3 PURCHASE OF POWER



          (a) Seller shall sell and deliver and PGandE shall purchase and accept
     delivery of capacity and energy at the voltage level of 115 kW.


          (b) Seller shall provide capacity and energy from its 6,500 kW
     Facility located in the Altamont Pass.


          (c) The scheduled operation date of the Facility is February 1, 1987.
     At the end of each calendar quarter Seller shall give written notice to
     PGandE of any change in the scheduled operation date.


          (d) To avoid exceeding the physical limitations of the interconnection
     facilities, Seller shall limit the Facility's actual rate of delivery into
     the PGandE system to 6,500 kW.

     (e) The primary energy source for the Facility is natural gas.


                                       5                                  S.O #4
                                                                     May 7, 1984


          (f) If Seller does not begin construction of its Facility by November
     30, 1986, PGandE may reallocate the existing capacity on PGandE's
     transmission and/or distribution system which would have been used to
     accommodate Seller's power deliveries to other uses. In the event of such
     reallocation, Seller shall pay PGandE for the cost of any upgrades or
     additions to PGandE's system necessary to accommodate the output from the
     Facility. Such additional facilities shall be installed, owned and
     maintained in accordance with the applicable PGandE tariff.


     (g) The transformer loss adjustment factor is ____________1


                             ARTICLE 4 ENERGY PRICE


          PGandE shall pay Seller for its surplus energy output2 under the
     energy payment option checked below3:



     X     Energy Payment Option 1 - Forecasted Energy Prices
     -



     -----------------

     1    If Seller chooses to have meters placed on Seller's side of the
          transformer, an estimated transformer loss adjustment factor of 2
          percent, unless the Parties agree otherwise, will be applied. This
          estimated transformer loss figure will be adjusted to a measurement of
          actual transformer losses performed at Seller's request and expense.
          In addition, a line loss percentage to the low side meter will be
          determined by the Parties and added to the transformer loss adjustment
          factor.

     2    Insert either "net energy output" or "surplus energy output" to show
          the energy sale option selected by Seller.

     3    Energy Payment option 2 is not available to oil or gas-fired
          cogenerators.


                                       6                                  S.O #4
                                                                     May 7, 1984


          During the fixed price period, Seller shall be paid for energy
     delivered at prices equal to 01 percent of the prices set forth in Table
     B-1, Appendix B, plus 1002 percent of PGandE's full short-run avoided
     operating costs.

          For the remaining years of the term of agreement, Seller shall be paid
     for energy delivered at prices equal to PCandE's full short-run avoided
     operating costs.

          If Seller's Facility is not an oil or gas-fired cogeneration facility,
     Seller may convert from Energy Payment Option 1 to Energy Payment option 2
     and be subject to the conditions therein, provided that Seller shall not
     change the percentage of energy prices to be based on PGandE's full
     short-run avoided operating costs. Such conversion must be made at least 90
     days prior to the date of initial energy deliveries and must be made by
     written notice in accordance with Section A-17, Appendix A.


     _____  Energy Payment Option 2 - Levelized Energy Prices


     -----------------

     (1)  Insert either 0, 20, 40, 60, 80, or 100, at Seller's option. If
          Seller's Facility is an oil or gas-fired cogeneration facility, either
          0 or 20 must be inserted.

     (2)  Insert the difference between 100 and the percentage selected under
          footnote 1 above.


                                       7                                  S.O #4
                                                                     May 7, 1984


          During the fixed price period, Seller shall be paid for energy
     delivered at prices equal to ________ 1 percent of the levelized energy
     prices set forth in Table B-2, Appendix B for the year in which energy
     deliveries begin and term of agreement, plus ___________2 percent of
     PGandE's full short-run avoided operating costs. During the fixed price
     period, Seller shall be subject to the conditions and terms set forth in
     Appendix B, Energy Payment Option 2.

          For the remaining years of the term of agreement, Seller shall be paid
     for energy delivered at prices equal to PGandE's full short-run avoided
     operating costs.


     Seller may convert from Energy Payment Option 2 to Energy Payment Option 1,
provided that Seller shall not change the percentage of energy prices to be
based on PGandE's full short-run avoided operating costs. Such conversion must
be made at least 90 days prior to the date of initial energy deliveries and must
be made by written notice in accordance with Section A-17, Appendix A.



     -----------------

     1    Insert either 20, 40, 60, 80, or 100, at Seller's option.

     2    Insert the difference between 100 and the percentage selected under
          footnote 1 above.


                                       8                                  S.O #4
                                                                     May 7, 1984


     _____  Energy Payment Option 3 - Incremental Energy Rate


          Beginning with the date of initial energy deliveries and continuing
     until ______________1, seller shall be paid monthly for energy delivered at
     prices equal to PGandE's full short-run avoided operating costs, provided
     that adjustments shall be made annually to the extent set forth in Appendix
     B, Energy Payment Option 3.


          The incremental Energy Rate Band widths specified by Seller in Table I
     below shall be used in determining the annual adjustment, if any.


                                     Table I
                                     -------

     Year                 Incremental Energy Rate Band Widths
     ----                 -----------------------------------
                          (must be multiples of 100 or zero)

     1984                          -------------
     1985                          -------------
     1986                          -------------
     1987                          -------------
     1988                          -------------
     1989                          -------------
     1990                          -------------
     1991                          -------------
     1992                          -------------
     1993                          -------------
     1994                          -------------
     1995                          -------------
     1996                          -------------
     1997                          -------------
     1998                          -------------


     -----------------

     1    Specified by Seller must be December 31, 1998 or prior.


                                       9
                                                                          S.O #4
                                                                     May 7, 1984


          After __________, Seller shall be paid to: energy delivered at prices
     equal to PGandE's full short-run, avoided operating costs.


                 ARTICLE 5 CAPACITY ELECTION AND CAPACITY PRICE


          Seller may elect to deliver either firm capacity or as-delivered
     capacity, and Seller's election is indicated below. PGandE's prices fox
     firm capacity and as-delivered capacity die derived from PGandE's full
     avoided costs as approved by the CPUC.


     X   Firm capacity - 5,700 kW for 30 years from the firm capacity
         availability date with payment determined in accordance with
         Appendix E. Except for hydro- electric facilities, PGandE shall
         pay Seller for capacity delivered in excess of firm capacity on
         an as-delivered capacity basis in accordance with As-Delivered
         Capacity Payment Option 1 set forth in Appendix D.


                                       OR

     __  As-delivered capacity with payment determined in accordance with
         As-Delivered Capacity Payment Option set forth in Appendix D.


                                       10                                 S.O #4
                                                                     May 7, 1984


                        ARTICLE 6 LOSS ADJUSTMENT FACTORS


          Capacity Loss Adjustment Factors shall be as shown in Appendix D and
     Appendix E, dependent upon Seller's capacity election set forth in Article
     5 of this Agreement.

          Energy Loss Adjustment Factors shall be considered as unity for all
     energy payments related to Energy Payment Options I and 2 set forth in
     Appendix B for the entire fixed price period of this Agreement, except for
     the percentage of' payments that Seller elected in Article 4 to have
     calculated based on PGandE's full short-run avoided operating costs. Energy
     Loss Adjustment Factors for all payments related to PGandE's full short-run
     avoided operating costs are subject to CPUC rulings for the entire term of
     agreement.


                              ARTICLE 7 CURTAILMENT

          Seller has two options regarding possible curtailment by PGandE of
     Seller's deliveries, and Seller's selection is indicated below:

     X   Curtailment Option A - Hydro Spill and Negative Avoided Cost
    --
    __   Curtailment Option B - Adjusted Price Period

         The two options are described in Appendix C.


                                       11                                 S.O #4
                                                                     May 7, 1984


                ARTICLE 8 RETROACTIVE APPLICATION OF CPUC ORDERS


          Pursuant to Ordering Paragraph l (f) of CPUC Decision No. 83-09-054
     (September 7, 1983), after the effective date of the CPUC's Application
     B2-03-26 decision relating to line loss factors, Seller has the option to
     retain the relevant terms of this Agreement or have the results of that
     decision incorporated into this Agreement. To retain the terms herein,
     Seller shall provide written notice to PGandE within 30 days after the
     effective date of the relevant CPUC decision on Application 82-03-26.
     Failure to provide such notice will result in the amendment of this
     Agreement to comply with that decision.


          As soon as practicable following the issuance of a decision in
     Application 82-03-26, PGandE shall notify Seller of the effective date
     thereof and its results.


                                ARTICLE 9 NOTICES


          All written notices shall be directed as follows:

          To PGandE:     Pacific Gas and Electric Company
                         Attention: Vice President -
                         Electric Operations
                         77 Beale Street
                         San Francisco, CA 94106


                                       12                                 S.O #4
                                                                     May 7, 1984


          To Seller:     Fayette Manufacturing Corporation
                         Attention: Arthur C. Beard
                         P.O. Box 1149
                         Tracy, CA 95376



                     ARTICLE 10 DESIGNATED SWITCHING CENTER


          The designated PGandE switching center shall be, unless changed by
     PGandE:

                         Tesla Substation
                         Patterson Pass Road
                         Tracy, CA 95376
                         (209)835-6391


                         ARTICLE 11 TERMS AND CONDITIONS


          This Agreement includes the following appendices which are attached
     and incorporated by reference:

     Appendix A -   GENERAL TERMS AND CONDITIONS

     Appendix B -   ENERGY PAYMENT OPTIONS

     Appendix C -   CURTAILMENT OPTIONS

     Appendix D -   AS-DELIVERED CAPACITY

     Appendix E -   FIRM CAPACITY

     Appendix F -   INTERCONNECTION


                                       13                                 S.O #4
                                                                     May 7, 1984


                          Article 12 TERM OF AGREEMENT


          This Agreement shall be binding upon execution and remain in effect
     thereafter for 30 years' from the firm capacity availability date2;
     provided, however, that it shall terminate if energy deliveries do not
     start within five years of the execution date.

          IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to
     be executed by their duly authorized representatives- and it is effective
     as of the last date set forth below.


     FAYETTE MANUFACTURING CORPORATION         PACIFIC GAS AND ELECTRIC COMPANY



     BY:/s/ JOHN S. PRESTON                    BY: /s/ NOLAN H. DAINES
        -------------------                        -------------------
            JOHN S. PRESTON                            NOLAN H. DIANES

                                                      Vice President -
     TITLE: General Counsel                    TITLE: Planning and Research

     DATE SIGNED: April 12, 1985               DATE SIGNED: 4/15/85
                  --------------                            -------



          ------------

          1    The minimum contract term is 15 years and the maximum contract
               term is 30 years.

          2    Insert "firm capacity availability date" if Seller has elected to
               deliver firm capacity or "date of initial energy deliveries" if
               Seller has elected to deliver as-delivered capacity.


                                       14                                 S.O #4
                                                                     May 7, 1984


                                   APPENDIX A

                          GENERAL TERMS AND CONDITIONS


                                    CONTENTS



     Section                                                   Page
     -------                                                   -----

       A-1          DEFINITIONS                                  A-2

       A-2          CONSTRUCTION                                 A-7

       A-3          OPERATION                                    A-11

       A-4          PAYMENT                                      A-14

       A-5          ADJUSTMENTS OF PAYMENTS                      A-15

       A-6          ACCESS TO RECORDS AND PGandE DATA            A-15

       A-7          INTERRUPTION OF DELIVERIES                   A-16

       A-8          FORCE MAJEURE                                A-16

       A-9          INDEMNITY                                    A-17

       A-10         LIABILITY; DEDICATION                        A-18

       A-11         SEVERAL OBLIGATIONS                          A-19

       A-12         NON-WAIVER                                   A-19

       A-13         ASSIGNMENT                                   A-19

       A-14         CAPTIONS                                     A-20

       A-15         CHOICE OF LAWS                               A-20

       A-16         GOVERNMENTAL JURISDICTION AND                A-20
                    AUTHORIZATION

       A-17         NOTICES                                      A-21

       A-18         INSURANCE                                    A-21


                                       A-1


                                   APPENDIX A

                          GENERAL TERMS AND CONDITIONS



     A-1 DEFINITIONS



          Whenever used in this Agreement, appendices, and attachments hereto,
     the following terms shall have the following meanings:

          Adjusted firm capacity price - The $/kW-year purchase price for firm
     capacity from Table E-2, Appendix E for the period of Seller's actual
     performance.


          As-delivered capacity - Capacity delivered to PGandE in excess of firm
     capacity or in lieu of a firm capacity commitment.


          CPUC - The Public Utilities Commission of the State of California.


          Current firm capacity price - The $/kW-year capacity price from
     PGandE's firm capacity price schedule effective at the time PGandE Berates
     the firm capacity pursuant to Section E-4(b), Appendix E or Seller
     terminates performance under this Agreement, for a term equal to the period
     from the date of deration or termination to the end of the term of
     agreement.


                                      A-2


          Designated PGandE switching center - That switching center or other
     PGandE installation identified in Article 10.


          Facility - That generation apparatus described in Article 3 and all
     associated equipment owned, maintained, and operated by Seller.


          Firm capacity - That capacity, if any, identified as firm in Article 5
     except as otherwise changed as provided herein.


          Firm capacity availability date - The day following the day during
     which all features and equipment of the Facility are demonstrated to
     PGandE's satisfaction to be capable of operating simultaneously to deliver
     firm capacity continuously into PGandE's system as provided in this
     Agreement.

          Firm capacity price - The price for firm capacity applicable for the
     firm capacity availability date and the number of years of firm capacity
     delivery from the firm capacity price schedule, Table E-2, Appendix E.


                                      A-3


          Firm capacity price schedule - The periodically published schedule of
     the $/kW-year prices that PGandE offers to pay for firm capacity. See Table
     E-2, Appendix E.


          Fixed price Period - The period during which forecasted or levelized
     energy prices, and/or forecasted as-delivered Capacity prices, are in
     effect; defined as the first five years of the term of agreement if the
     term of agreement is 15 or 16 years; the first six years of the term of
     agreement if the term of agreement is 17, 18, or 19 years; or the first ten
     years of the term of agreement if the term of agreement is anywhere from 20
     through 30 years.


          Forced outage - Any outage resulting from a design defect, inadequate
     construction, operator error or a breakdown of the mechanical or electrical
     equipment that fully or partially curtails the electrical output of the
     Facility.


          Full short-run avoided operating costs - CPUC-approved costs which are
     the basis of PGandE's published energy prices. PGandE's current energy
     price calculation is shown in Table B-5, Appendix B. PGandE's published
     off-peak hours' prices shall be adjusted, as appropriate, if Seller has
     selected Curtailment Option B.


                                      A-4


          Interconnection facilities - All means required and apparatus
     installed to interconnect and deliver power from the Facility to the PGandE
     system including, but not limited, to, connection, transformation,
     switching, metering, communications, and safety equipment, such as
     equipment required to protect (1) the PGandE system and its customers from
     faults occurring at the Facility, and (2) the Facility from faults
     occurring on the PGandE system or on the systems of others to which the
     PGandE system is directly or indirectly connected. Interconnection
     facilities also include any necessary additions and reinforcements by
     PGandE to the PGandE system required as a result of the interconnection of
     the Facility to the PGandE system.


          Net energy output - The Facility's gross output in kilowatt-hours less
     station use and transformation and transmission losses to the point of
     delivery into the PGandE system. Where PGandE agrees that it is impractical
     to connect the station use on the generator side of the power purchase
     meter, PGandE may, at its option, apply a station load adjustment.


          Prudent electrical practices - Those practices, methods, and
     equipment, as changed from time to time, that are commonly used in prudent
     electrical engineering and operations to design and operate electric
     equipment lawfully and with safety, dependability, efficiency, and economy.


                                      A-5


          Scheduled operation date - The day specified in Article 3 (c) when the
     Facility is, by Seller's estimate, expected to produce energy that will be
     available for delivery to PGandE.


          Special facilities - Those additions and reinforcements to the PGandE
     system which are needed to accommodate the maximum delivery of energy and
     capacity from the Facility as provided in this Agreement and those parts of
     the interconnection facilities which are owned and maintained by PGandE at
     Seller's request, including metering and data processing equipment. All
     special facilities shall be owned, operated, and maintained pursuant to
     PGandE's electric Rule No. 21, which is attached hereto.


          Station use - Energy used to operate the Facility's auxiliary
     equipment. The auxiliary equipment includes, but is not limited to, forced
     and induced draft fans, cooling towers, boiler feed pumps, lubricating oil
     systems, plant lighting, fuel handling systems, control systems, and sump
     pumps.


          Surplus energy output - The Facility's gross output, in
     kilowatt-hours, less station use, and any other use by Seller, and
     transformation and transmission losses to the point of delivery into the
     PGandE system.


                                      A-6


          Term of agreement - The number of years this Agreement will remain in
     effect as provided in Article 12.


          Voltage level - The voltage at which the Facility interconnects with
     the PGandE system, measured at the point of delivery.


     A-2  CONSTRUCTION


     A-2.1  Land Rights

          Seller hereby grants to PGandE all necessary rights of way and
     easements, including adequate and continuing access rights on property of
     Seller, to install, operate, maintain, replace, and remove the special
     facilities. Seller agrees to execute such other grants, deeds, or documents
     as PGandE may require to enable it to record such rights :of way and
     easements. If any part of PGandE's equipment is to be installed on property
     owned by other than Seller, Seller shall, at its own cost and expense,
     obtain from the owners thereof all necessary rights of way and easements,
     in a form satisfactory to PGandE, for the construction, operation,
     maintenance, and replacement of PGandE's equipment upon such property. If
     Seller is unable to obtain such rights of way and easements, Seller shall


                                      A-7


     reimburse PGandE for all costs incurred by PGandE in obtaining them. PGandE
     shall at all times have the right of ingress to and egress from the
     Facility at all reasonable hours for any purposes reasonably connected with
     this Agreement or the exercise of any and all rights secured to PGandE by
     law or its tariff schedules.


      A-2.2 Design, Construction, Ownership, and Maintenance


          (a) Seller shall design, construct, install, own, operate, and
     maintain all interconnection facilities, except special facilities, to the
     point of interconnection with the PGandE system as required for PGandE to
     receive capacity and energy from the Facility. The Facility and
     interconnection facilities shall meet all requirements of applicable codes
     and all standards of prudent electrical practices and shall be maintained
     in a safe and prudent manner. A description of the interconnection
     facilities for which Seller is solely responsible is set forth in Appendix
     F, or if the interconnection requirements have not yet been determined at
     the time of the execution of this Agreement, the description of such
     facilities will be appended to this Agreement at the time such
     determination is made.

          (b) Seller shall submit to PGandE the design and all specifications
     for the interconnection facilities (except special facilities) and, at
     PGandE's option, the Facility, for review and written acceptance prior to


                                      A-8



          their release for construction purposes. PGandE shall notify Seller in
     writing of the outcome of PGandE's review of the design and specifications
     for Seller's interconnection facilities (and the Facility, if requested)
     within 30 days of the receipt of the design and all of the specifications
     for the interconnection facilities (and the Facility, if requested). Any
     flaws perceived by PGandE in the design and specifications for the
     interconnection facilities (and the Facility, if requested) will be
     described in PGandE's written notification. PGandE's review and acceptance
     of the design and specifications shall not be construed as confirming or
     endorsing the design and specifications or as warranting their safety,
     durability, or reliability. PGandE shall not, by reason of such review or
     lack of review, be responsible for strength, details of design, adequacy,
     or capacity of equipment built pursuant to such design and specifications,
     nor shall PGandE's acceptance be deemed to be an endorsement of any of such
     equipment. Seller shall change the interconnection facilities as may be
     reasonably required by PGandE to meet changing requirements of the PGandE
     system.


          (c) In the event it is necessary for PGandE to install interconnection
     facilities for the purposes of this Agreement, they shall be installed as
     special facilities.


                                      A-9


          (d) Upon the request of Seller, PGandE shall provide a binding
     estimate for the installation of interconnection facilities by PGandE.


     A-2.3  Meter Installation



          (a) PGandE shall specify, provide, install, own, operate, and maintain
     as special facilities all metering and data processing equipment for the
     registration and recording of energy and other related parameters which are
     required for the reporting of data to PGandE and for computing the payment
     due Seller from PGandE.


          (b) Seller shall provide, construct, install, own, and maintain at
     Seller's expense all that is required to accommodate the metering and data
     processing equipment, such as, but not limited to, metal-clad switchgear,
     switchboards, cubicles, metering panels, enclosures, conduits, rack
     structures, and equipment mounting pads.


          (c) PGandE shall permit meters to be fixed on PGandE's side of the
     transformer. If meters are placed on PGandE's side of the transformer,
     service will be provided at the available primary voltage and no
     transformer loss adjustment will be made. If Seller chooses to have meters
     placed on Seller's side of the transformer, an estimated transformer loss
     adjustment factor of 2 percent, unless the Parties agree otherwise, will be
     applied.


                                      A-10


     A-3  OPERATION


     A-3.1  Inspection and Approval


          Seller shall not operate the Facility in parallel with PGandE's system
     until an authorized PGandE representative has inspected the interconnection
     facilities, and PGandE has given written approval to begin parallel
     operation. Seller shall notify PGandE of the Facility's start-up date at
     least 45 days prior to such date. PGandE shall inspect the interconnection
     facilities within 30 days of the receipt of such notice. If parallel
     operation is not authorized by PGandE, PGandE shall notify Seller in
     writing within five days after inspection of the reason authorization for
     parallel operation was withheld.


     A-3.2  Facility Operation and Maintenance


          Seller shall operate and maintain its Facility according to prudent
     electrical practices, applicable laws, orders, rules, and tariffs and
     shall provide such reactive power support as may be reasonably required by
     PGandE to maintain system voltage level and power factor. Seller shall
     operate the Facility at the power factors or voltage levels prescribed by
     PGandE's system dispatcher or designated- representative. If Seller fails
     to provide reactive power support, PGandE may do so at Seller's expense.


                                      A-11


     A-3.3  Point of Delivery


          Seller shall deliver the energy at the point where Seller's electrical
     conductors (or those of Seller's agent) contact PGandE's system as it shall
     exist whenever the deliveries are being made or at such other point or
     points as the Parties may agree in writing. The initial point of delivery
     of Seller's power to the PGandE system is set forth in Appendix F.


     A-3.4  Operating Communications


          (a) Seller shall maintain operating communications with the designated
     PGandE switching center. The operating communications shall include, but
     not be limited to, system paralleling or separation, scheduled and
     unscheduled shutdowns, equipment clearances, levels of operating voltage or
     power factors and daily capacity and generation reports.


          (b) Seller shall keep a daily operations log for each generating unit
     which shall include information on unit availability, maintenance outages,
     circuit breaker trip operations requiring a manual reset, and any
     significant events related to the operation of the Facility.


          (c) if Seller makes deliveries greater than one megawatt, Seller shall
     measure and register on a graphic recording device power in kW and voltage
     in kV at a location within the Facility agreed to by both Parties.


                                      A-12


          (d) If Seller makes deliveries greater than one and up to and
     including ten megawatts, Seller shall report to the designated PGandE
     switching center, twice a day at agreed upon times for the current day's
     operation, the hourly readings in kW of capacity delivered and the energy
     in kWh delivered since the last report.


          (e) If Seller makes deliveries of greater than ten megawatts, Seller
     shall telemeter the delivered capacity and energy information, including
     real power in kW, reactive power in kVAR, and energy in kWh to a switching
     center selected by PGandE. PGandE may also require Seller to telemeter
     transmission kW, kVAR, and kV data depending on the number of generators
     and transmission configuration. Seller shall provide and maintain the data
     circuits required for telemetering. When telemetering is inoperative,
     Seller shall report daily the capacity delivered each hour and the energy
     delivered each day to the designated PGandE switching center.


     A-3.5  Meter Testing and Inspection


          (a) All meters used to provide data for the computation of the
     payments due Seller from PGandE shall be sealed, and the seals shall be
     broken only by PGandE when the meters are to be inspected, tested, or
     adjusted.


                                      A-13


          (b) PGandE shall inspect and test all meters upon their installation
     and annually thereafter. At Seller's request and expense, PGandE shall
     inspect or test a meter more frequently. PGandE shall give reasonable
     notice to Seller of the time when any inspection or test shall take place,
     and Seller may have representatives present at the test or inspection. If a
     meter is found to be inaccurate or defective, PGandE shall adjust, repair,
     or replace it at its expense in order to provide accurate metering.


     A-3.6  Adjustments to Meter Measurements


          If a meter fails to register, or if the measurement made by a meter
     during a test varies by more than two percent from the measurement made by
     the standard meter used in the test, an adjustment shall be made correcting
     all measurements made by the inaccurate meter for --(1) the actual period
     during which inaccurate measurements were made, if the period can be
     determined, or if not, (2) the period immediately preceding the test of the
     meter equal to one-half the time from the date of the last previous test of
     the meter, provided that the period covered by the correction shall not
     exceed six months.


     A-4  PAYMENT


          PGandE shall mail to Seller not later than 30 days after the end of
     each monthly billing period (1) a statement showing the energy and capacity


                                      A-14


     delivered to PGandE during on-peak, partial-peak, and off-peak periods
     during the monthly billing period, (2) PGandE's computation of the amount
     due Seller, and (3) PGandE's check in payment of said amount. Except as
     provided in Section A-5, if within 30 days of receipt of the statement
     Seller does not make a report in writing to PGandE of an error, Seller
     shall be deemed to have waived any error in PGandE's statement,
     computation, and payment, and they shall be considered correct and
     complete.


     A-5  ADJUSTMENTS OF PAYMENTS


          (a) In the event adjustments to payments are required as a result of
     inaccurate meters, PGandE shall use the corrected measurements described
     in. Section A-3.6 to recompute the amount due from PGandE to Seller for the
     capacity and energy delivered under this Agreement during the period of
     inaccuracy.

          (b) The additional payment to Seller or refund to PGandE shall be made
     within 30 days of notification of the owing Party of the amount due.


     A-6  ACCESS TO RECORDS AND PGandE DATA

          Each Party, after giving reasonable written notice to the other Party,
     shall have the right of access to all metering and related records


                                      A-15


     including operations logs of the Facility. Data filed by PGandE with the
     CPUC pursuant to CPUC orders governing the purchase of power from
     qualifying facilities shall be provided to Seller upon request; provided
     that Seller shall reimburse PGandE for the costs it incurs to respond to
     such request.


     A-7 INTERRUPTION OF DELIVERIES

          PGandE shall not be obligated to accept or pay for and may require
     Seller to interrupt or reduce deliveries of energy (1) when necessary in
     order to construct, install, maintain, repair, replace, remove,
     investigate, or inspect any of its equipment or any part of its system, or
     (2) if it determines that interruption or reduction is necessary because of
     PGandE system emergencies, forced outages, force majeure, or compliance
     with prudent electrical practices; provided that PGandE shall not interrupt
     deliveries pursuant to this section in order to take advantage, or make
     purchases, of less expensive energy elsewhere. Whenever possible, PGandE
     shall give Seller reasonable notice of the possibility that interruption or
     reduction of deliveries may be required.


     A-8  FORCE MAJEURE


          (a) The term force majeure as used herein means unforeseeable causes,
     other than forced outages, beyond the reasonable control of and without


                                      A-15


     the fault or negligence of the Party claiming force majeure including,
     but not limited to, acts of God, labor disputes, sudden actions of the
     elements, actions by federal, state, and municipal agencies, and actions of
     legislative, judicial, or regulatory agencies which conflict with the terms
     of this Agreement.


          (b) If either Party because of force majeure is rendered wholly or
     partly unable to perform its obligations under this Agreement, that Party
     shall be excused from whatever performance is affected by the force majeure
     to the extent so affected provided that:


               (1) the non-performing Party, within two weeks after the
          occurrence of the force majeure, gives the other Party written notice
          describing the particulars of the occurrence,

               (2) the suspension of performance is of no greater scope and of
          no longer duration than is required by the force majeure,

               (3) the non-performing Party uses its best efforts to remedy its
          inability to perform (this subsection shall not require the settlement
          of any strike, walkout, lockout or other labor dispute on terms which,
          in the sole judgment of the Party involved in the dispute, are
          contrary to its interest. It is understood and agreed that the
          settlement of strikes, walkouts, lockouts or other labor disputes


                                      A-16


          shall be at the sole discretion of the Party having the difficulty),

               (4) when the non-performing Party is able to resume performance
          of its obligations under this Agreement, that Party shall give the
          other Party written notice to that effect, and

               (5) capacity payments during such periods of force majeure on
          Seller's part shall be governed by Section E-2(c), Appendix E.


          (c) In the event a Party is unable to perform due to legislative,
     judicial, or regulatory agency action, this Agreement shall be renegotiated
     to comply with the legal change which caused the non-performance.


     A-9  INDEMNITY


          Each Party as indemnitor shall save harmless and indemnify the other
     Party and the directors, officers, and employees of such other Party
     against and from any and all loss and liability for injuries to persons
     including employees of either Party, and property damages including
     property of either Party resulting from or arising out of (1) the
     engineering, design, construction, maintenance, or operation of, or (2) the
     making of replacements, additions, or betterments to, the indemnitor's
     facilities. This indemnity and save harmless provision shall apply
     notwithstanding the active or passive negligence of the indemnitee. Neither


                                      A-17


     Party shall be indemnified hereunder for its liability or loss resulting
     from its sole negligence or willful misconduct. The indemnitor shall, on
     the other Party's request, defend any suit asserting a -claim covered by
     this indemnity and shall pay all costs, including reasonable attorney fees,
     that may be incurred by the other Party in enforcing this indemnity.


     A-l0 LIABILITY; DEDICATION


          (a) Nothing in this Agreement shall create any duty to, any standard
     of care with reference to, or any liability to any person not a Party to
     it. Neither Party shall be liable to the other Party for consequential
     damages.


          (b) Each Party shall be responsible for protecting its facilities from
     possible damage by reason of electrical disturbances or faults caused by
     the operation, faulty operation, or noncooperation of the other Party's
     facilities, and' such other Party shall not be liable for any such damages,
     so caused.


          (c) No undertaking by one Party to the other under any provision of
     this Agreement shall constitute the dedication of that Party's system or
     any portion thereof to the other Party or to the public or affect the
     status of PGandE as an independent public utility corporation or Seller as
     an independent individual or entity and not a public utility.


                                      A-18


     A-11 SEVERAL OBLIGATIONS

          Except where specifically stated in this Agreement to be otherwise,
     the duties, obligations, and liabilities of the Parties are intended to be
     several and not joint or collective. Nothing contained in this Agreement
     shall ever be construed to create an association, trust, partnership, or
     joint venture or impose a trust or partnership duty, obligation, or
     liability on or with regard to either Party. Each Party shall be liable
     individually and severally for its own obligations under this Agreement.


     A-12 NON-WAIVER

          Failure to enforce any right or obligation by either Party with
     respect to any matter arising in connection with this Agreement shall not
     constitute a waiver as to that matter or any other matter.


     A-13 ASSIGNMENT

          Neither Party shall voluntarily assign its rights nor delegate its
     duties under this Agreement, or any part of such rights or duties, without
     the written consent of the other Party, except in connection with the sale
     or merger of a substantial portion of its properties. Any such assignment


                                      A-19


     or delegation made without such written consent shall be null and
     void. Consent for assignment shall not be withheld unreasonably. Such
     assignment shall include, unless otherwise specified therein, all of
     Seller's rights to any refunds which might become due under this Agreement.


     A-14 CAPTIONS


          All indexes, titles, subject headings, section titles, and similar
     items are provided for the purpose of reference and convenience and are not
     intended to affect the meaning of the contents or scope of this Agreement.


     A-15 CHOICE OF LAWS


          This Agreement shall be interpreted in accordance with the laws of the
     State of California, excluding any choice of law rules which may direct the
     application of the laws of another jurisdiction.


     A-16 GOVERNMENTAL JURISDICTION AND AUTHORIZATION


          Seller shall obtain any governmental authorizations and permits
     required for the construction and operation of the Facility. Seller shall
     reimburse PGandE for any and all losses, damages, claims, penalties, or
     liability it incurs as a result of Seller's failure to obtain or maintain
     such authorizations and permits.


                                      A-20


     A-17 NOTICES

          Any notice, demand, or request required or permitted, to be given by
     either Party to the other, and any instrument required or permitted to be
     tendered or delivered by either Party to the other, shall be in writing
     (except as provided in Section E-3) and so given, tendered, or delivered,
     as the case may be, by depositing the same in any United States Post Office
     with postage prepaid for transmission by certified mail, return receipt
     requested, addressed to the Party, or personally delivered to the Party, at
     the address in Article 9 of this Agreement. Changes in such designation may
     be made by notice similarly given.


     A-18 INSURANCE


     A-18.1 General Liability Coverage



          (a) Seller shall maintain during the performance hereof, General
     Liability Insurance' of not less than $1,000,000 if the Facility is over
     100 kW, $500,000 if the Facility is over 20 kW to 100 kW, and $100,000 if
     the Facility is 20 kW or below of combined single limit or equivalent for
     bodily injury, personal injury, and property damage as the result of any
     one occurrence.


     ----------------

     1.   Governmental agencies which have an established record of
          self-insurance may provide the required coverage through
          self-insurance.


                                      A-21


          (b) General Liability Insurance shall include coverage for
     Premises-operations, Owners and Contractors Protective, Products/Completed
     Operations Hazard, Explosion, Collapse, Underground, Contractual Liability,
     and Broad Form Property Damage including Completed Operations.


          (c) such insurance, by endorsement to the policy(ies), shall include
     PGandE as an additional insured if the Facility is over 100 kW insofar as
     work performed by Seller for PGandE is concerned, shall contain a
     severability of interest clause, shall provide that PGandE shall not by
     reason of its inclusion as an additional insured incur liability to the
     insurance carrier for payment of premium for such insurance, and shall
     provide for 30-days' written notice to PGandE prior to cancellation,
     termination, alteration, or material change of such insurance.


     A-18.2 Additional Insurance Provisions

          (a) Evidence of coverage described above in Section A-18.1 1 shall
     state that coverage provided is primary and is not excess to or
     contributing with any insurance or self-insurance maintained by PGandE.

          (b) PGandE shall have the right to inspect or obtain a copy of the
     original policy(ies) of insurance.


                                      A-22


          (c) Seller shall furnish the required certificates' and endorsements
     to PGandE prior to commencing operation.


          (d) All insurance certificates', endorsements, cancellations,
     terminations, alterations, and material changes of such insurance shall be
     issued and submitted to the following:


                     PACIFIC GAS AND ELECTRIC COMPANY
                     Attention: Manager - Insurance Department
                     77   Beale Street, Room E280
                     San Francisco, CA 94106



     ----------------

     1    A governmental agency qualifying to maintain self-insurance should
          provide a statement of self-insurance.


                                      A-23


                                   APPENDIX B

                             ENERGY PAYMENT OPTIONS



          Energy Payment Option 1 - Forecasted Energy Prices


          Pursuant to Article 4, the energy payment calculation for Seller's
     energy deliveries during each year of the fixed price period shall include
     the appropriate prices for such year in Table B-l, multiplied by the
     percentage Seller has specified in Article 4. If Seller has selected
     Curtailment Option B in Article 7, the forecasted off-peak hours' energy
     prices listed in Table B-1 shall be adjusted upward by 7.7% for Period A
     and 9.6% for Period B.


                                      B-1


                                    TABLE B-I

                        Forecasted Energy Price Schedule




                            Forecasted Energy Prices*, (cent)/kWh
     Year of                -------------------------------------
     Energy                  Period A                        Period B             Weighted
     Deliv-     ------------------------------  -------------------------------  Annual
     eries      On-Peak  Partial-Peak Off-Peak  On-Peak  Partial-Peak  Off-Peak  Average
     -----      -------  ------------ --------  -------  ------------  --------  -------

                                                              
       1983       5.36      5.12        4.94      5.44       5.31        5.19      5.18
       1984       5.66      5.40        5.22      5.74       5.61        5.48      5.47
       1985       5.75      5.48        5.30      5.83       5.69        5.56      5.55

       1986       5.99      5.72        5.52      6.08       5.94        5.80      5.79
       1987       6.38      6.08        5.88      6.47       6.32        6.17      6.16
       1988       6.94      6.62        6.39      7.03       6.87        6.71      6.70

       1989       7.60      7.25        7.00      7.70       7.53        7.35      7.34
       1990       8.12      7.74        7.48      8.23       8.04        7.85      7.84
       1991       8.64      8.24        7.96      8.75       8.56        8.35      8.34

       1992       9.33      8.90        8.60      9.46       9.24        9.02      9.01
       1993      10.10      9.63        9.30     10.23      10.00        9.76      9.75
       1994      10.91     10.41       10.06     11.06      10.81       10.55     10.54

       1995      11.79     11.25       10.87     11.96      11.68       11.40     11.39
       1996      12.67     12.09       11.68     12.85      12.56       12.25     12.24
       1997      13.61     12.98       12.54     13.79      13.48       13.15     13.14



     -------------------

     *    These prices are differentiated by the time periods as defined in
          Table B-4.


                                      B-2


     Energy Payment option 2 - Levelized Energy Prices

          Pursuant to Article 4, the energy payment calculation. for Seller's
     energy deliveries during the fixed price period shall include the
     appropriate prices set forth in Table B-2 for the year in which energy
     deliveries begin and term of agreement, multiplied by the percentage Seller
     has specified in Article 4. If Seller has selected Curtailment Option B in
     Article 7, the levelized off-peak hours' energy prices listed in Table B-2
     shall be adjusted upward by 7.7% for Period A and 9.6% for Period B. The
     discount specified in (c)(vi) below, if applicable; will be applied to the
     energy payments during the fixed price period.


          During the fixed price period, Seller shall be subject to the
     following conditions and terms:


     (a)  Minimum Damages

          The Parties agree that the levelized energy prices which PGandE pays
          Seller for the energy which Seller delivers to PGandE is based on the
          agreed value to PGandE of Seller's energy deliveries during the entire
          fixed price period. In the event PGandE does not receive such full
          performance by reason of a termination, Seller shall pay PGandE an
          amount based on the difference between the net present values, at the


                                      B-3


          time of termination, of the payments Seller would receive at the
          forecasted energy prices in Table B-1 and the payments Seller would
          receive at the levelized energy prices, for the remaining years of the
          fixed price period. This amount shall be calculated by assuming that
          Seller continued to generate for the remaining years of the fixed
          price period at a level equal to the average annual energy generation
          during the period of performance, and by applying the weighted annual
          average levelized price applicable to Seller's Facility and the
          weighted annual average forecasted energy prices in Table B-i for the
          remaining years of the fixed E rice period. The following formula
          shall be used to make this calculation:

                                 Y     (Fn)(A)(W)        Y    (L)(A)(W)
                           P =         ----------   -          ---------
                               (Sigma)  (1.15)n       (Sigma)  (1.15)n
                                 n=1                    n=1

          where:



                P    =   amount due PGandE.

                Y    =   number of years remaining in the fixed price period.

                Fn   =   weighted annual average forecasted energy price in the
                         ninth year after the breach, failure to perform, or
                         expiration of security, as shown in Table B-1 for the
                         corresponding calendar year.


                                      B-4


                L    =   weighted annual average levelized energy price
                         applicable to Seller's Facility.

                A    =   average annual energy generation by Seller during the
                         period of performance.

                n    =   summation index; refers to the nth year following
                         termination.

                W    =   percent of Seller's energy payments based on the
                         levelized energy prices, as specified in Article 4.



     (b)  Performance Requirements

          Seller shall operate and maintain the Facility in accordance with
          prudent electrical practices in order to maximize the likelihood that
          the Facility's output as delivered to PGandE during the part of the
          fixed price period when the levelized price is below the forecasted
          price ("last part") shall equal or exceed 70% of the Facility's output
          during the part of the fixed price period when the levelized price is
          above the forecasted price ("first part"). In the event that the
          Facility's output during any year or series of years in the last part
          of the fixed price period is less than 70% of the average annual
          production during the first part of the fixed price period, PGandE
          may, at its discretion (taking into consideration events occurring
          during such year or series of years such as curtailment by PGandE,
          Seller's choice not to operate during adjusted price periods, or


                                      B-5



          scheduled maintenance including major overhauls, and the probability
          that Seller's future performance will be adequate), either' request
          payment from Seller or immediately draw on the security posted, up to
          the amount equal to


          P x A-B,
              ---- , where:
               A

               P and A are as defined in Section (a) above.
               B  = Seller's average annual energy generation during the year or
               series of years in which the 70% performance requirement was not
               met.


          PGandE shall not request payment from Seller or draw on the security
          posted if the Facility's output during the last part of the fixed
          price period falls below 70% of the average annual energy generation
          during the first part of the fixed Brice period solely because of
          force majeure as defined in Section A-8, Appendix A or a lack of or
          limited availability of the primary energy resource of the Facility,
          if such energy resource is wind, water, or sunlight.


     (c)  Security



          (1)  As security for amounts which Seller may be obligated to pay
               PGandE pursuant- to Sections (a) and (b) above, Seller shall
               provide and maintain one or more of the following in an amount as
               described in Section (c)(2) below.


                                      B-6


          (i)  An irrevocable bank letter of credit, delivered to and in favor
               of PGandE with terms acceptable to PGandE.

          (ii) A payment bond providing for payment to PGandE in the event of
               any failure to meet the performance requirements set forth in
               Section (b) above or breach of this Agreement by Seller. Such
               bond shall be issued by a surety company acceptable to PGandE and
               shall have terms acceptable to PGandE.


          (iii) Fully paid up, noncancellable Project Failure Insurance made
               payable to PGandE with terms of such policy(ies) acceptable to
               PGandE.

          (iv) A performance bond providing for payment to PGandE in the event
               of any failure to meet the performance requirements set forth in
               Section (b) above or breach of this Agreement by Seller. Such
               bond shall be issued by a surety company acceptable to PGandE and
               shall have terms acceptable to PGandE.


          (v)  A corporate guarantee of payment to PGandE which PGandE deems, in
               its sole discretion, to provide at least the same quality of


                                      B-7


               security as subsections (i) through (iv) above.



          (vi) Other forms of security which PGandE does not deem to be
               equivalent security to those listed in subsections (i) through
               (v) above, and which PGandE, in its sole discretion, deems
               adequate. Such other forms of security may include, for example,
               a corporate guarantee or a lien, mortgage or deed of trust on the
               Facility or land upon which it is located. A 1.5% discount will
               be applied against the levelized energy price portion of PGandE's
               payments to Seller during the fixed price period if this type of
               security is provided.


     (2)  (i)  Commencing 90 days prior to the scheduled operation date and
               continuing until December 1 of the following calendar year,
               security as described in Section (c)(1) above shall be in place
               in an amount calculated in accordance with the formula set forth
               in Section (a) above, assuming Seller delivered energy through
               the and of the following calendar year and then terminated this
               Agreement. For purposes of determining the required amount of


                                      B-8


               security, it shall be assumed that Seller's deliveries through
               the end of the following calendar year would. equal R x C x H,
               where:


                    R  =   nameplate rating, in kW, of the Facility.

                    C  =   estimated capacity factor of the Facility, which
                           shall be established by mutual agreement of the
                           Parties at the time of execution of this Agreement.

                    H  =   number of hours from the scheduled operation date
                           through the end of the following calendar year.


          (ii) In the second calendar year of operation and each year thereafter
               until the end of the fixed price period, from December 1 through
               December 1 of the following year, security I shall be in place in
               an amount calculated by the formula set forth in Section (a)
               above assuming Seller continued to deliver energy in each month
               through the and of the following calendar year, at a level equal
               to the average monthly energy deliveries to date, and then
               terminated this Agreement.


                                      B-9


          (3)  Security must be maintained throughout the fixed price period as
               specified above. Any security with a fixed expiration date must
               be renewed by, Seller prior to that date. If such security is not
               renewed at least 30 days prior to its expiration, PGandE may, at
               its discretion, either request payment from Seller or immediately
               draw on the security posted, up to the amount calculated in
               accordance with the formula set forth in Section (a) above.


          (4)  If, at any time during the fixed price period, PGandE believes
               Seller is in material breach of this Agreement, PGandE shall so
               notify Seller in writing and Seller must remedy such breach
               within a reasonable period of time. If Seller does not so remedy,
               PGandE may, at its discretion, either request payment from Seller
               or immediately draw upon the security posted, up to the amount
               calculated in accordance with the formula set forth in Section
               (a) above, provided that if during Seller's period to remedy,
               Seller disputes PGandE's conclusion that Seller is in material
               breach, and PGandE elects to draw upon the security, the amount
               drawn upon by PGandE shall be deposited in an interest earning
               escrow account and held in such account until the dispute is
               resolved in accordance with Section (c)(5) below.


                                      B-10


          (5)  Upon the written request of either Party, any controversy or
               dispute between the Parties concerning Section (c)(4) above shall
               be subject to arbitration in accordance with the provisions of
               the California Arbitration Act, Sections 1280-1294.2 of the
               California Code of Civil Procedure except as provided otherwise
               in this section. Either Party may demand arbitration by first
               giving written notice of the existence of a dispute and then
               within 30 days of such notice giving a second written notice of
               the demand for arbitration.

               Within ten days after receipt of the demand for arbitration, each
               Party shall appoint one person, who shall not be an employee of
               either Party, to hear and determine the dispute. After both
               arbitrators have been appointed, they shall within five (5) days
               select a third arbitrator.


               The arbitration hearing shall take place in San Francisco,
               California, within 30 days of the appointment of the arbitrators,
               at such time and place as they select. The arbitrators shall give
               written notice of the time of the bearing to both Parties at
               least ten days prior to the hearing. The arbitrators shall not be
               authorized to alter, extend, or modify the terms of this
               Agreement. At the hearing, each Party shall submit a proposed


                                      B-11


               written decision, and any relevant evidence may be presented. The
               decision of the arbitrators must' consist of selection of one of
               the two proposed decisions, in its entirety.

               The decision of any two arbitrators shall be binding and
               conclusive as to disputes relating to Section (c)(4) only. Upon
               determining the matter, the arbitrators shall promptly execute
               and acknowledge their decision and deliver a copy to each Party.
               A judgment confirming the award may be rendered by any superior
               court having jurisdiction. Each Party shall bear its own
               arbitration costs and expenses, including the cost of the
               arbitrator it selected, and the costs and expenses of the third
               arbitrator shall be divided equally between both Parties, except
               as provided otherwise elsewhere in this Agreement.

               Pending resolution of any controversy or dispute hereunder,
               performance by each Party shall continue so as to maintain the
               status quo prior to notice of such controversy or dispute.
               Resolution of the controversy or dispute shall include payment of
               any interest accrued in the escrow account.


                                      B-12


                                    TABLE B-2
                         Levelized Energy Price Schedule


          For a term of agreement of 15-16 years:

          Year in
          Which                    Levelized Energy Prices*, (cent)/kWh
          Energy                   ------------------------------------
          Deliv-               Period A                         Period B              Weighted
          eries     -------------------------------  -------------------------------  Annual
          Begin     On-Peak  Partial-Peak  Off-Peak  on-Peak  Partial-Peak  Off-Peak  Average
          -----     -------  ------------  --------  -------  ------------  --------  -------
                                                                  
          1983       5.76        5.50        5.31      5.85       5.71        5.58     5.57
          1984       6.06        5.78        5.58      6.14       6.00        5.86     5.85
          1985       6.41        6.11        5.91      6.50       6.35        6.20     6.19

          1986       6.85        6.54        6.32      6.95       6.79        6.63     6.62
          1987       7.37        7.03        6.79      7.47       7.30        7.13     7.12
          1988       7.96        7.60        7.34      8.07       7.89        7.70     7.69

          For a term of agreement of 17-19 years:

          Year in
          Which                    Levelized Energy Prices*, (cent)/kWh
          Energy                   ------------------------------------
          Deliv-               Period A                         Period B              Weighted
          eries     -------------------------------  -------------------------------  Annual
          Begin     On-Peak  Partial-Peak  Off-Peak  on-Peak  Partial-Peak  Off-Peak  Average
          -----     -------  ------------  --------  -------  ------------  --------  -------
          1983       5.90        5.63        5.44      5.98       5.84        5.71     5.70
          1984       6.23        5.95        5.74      6.32       6.18        6.03     6.02
          1985       6.60        6.30        6.08      6.69       6.53        6.38     6.37

          1986       7.06        6.73        6.51      7.16       7.00        6.83     6.82
          1987       7.60        7.25        7.00      7.70       7.53        7.35     7.34
          1988       8.21        7.83        7.57      8.32       8.13        7.94     7.93

          For a term of agreement of 20-30 years:

          Year in
          Which                    Levelized Energy Prices*, (cent)/kWh
          Energy                   ------------------------------------
          Deliv-               Period A                         Period B              Weighted
          eries     -------------------------------  -------------------------------  Annual
          Begin     On-Peak  Partial-Peak  Off-Peak  on-Peak  Partial-Peak  Off-Peak  Average
          -----     -------  ------------  --------  -------  ------------  --------  -------
          1983       6.49        6.20        5.98      6.58       6.43        6.28     6.27
          1984       6.90        6.58        6.35      6.99       6.83        6.67     6.66
          1985       7.34        7.00        6.76      7.44       7.27        7.10     7.09

          1986       7.88        7.51        7.26      7.99       7.81        7.62     7.61
          1987       8.49        8.10        7.82      8.61       8.41        8.21     8.20
          1988       9.16        8.74        8.44      9.29       9.08        8.86     8.85


          -----------------
          * These prices are differentiated by the time periods as defined in
            Table B-4.


                                      B-13


          Energy Payment Option 3    - Incremental Energy Rate


          During the period specified in Article 4, annual adjustments to
     Seller's energy payments shall be made as described below.



          At the end of each calendar year, the Derived Incremental Energy Rate
     (with units expressed in Btu/kWh) will be calculated as follows:



          Derived Incremental Energy Rate (DIER)= B
                                                -----
                                                A x C

          where:



               A    = the total kWh delivered by Seller during the calendar
                    year, excluding any kWh delivered when Seller was asked to
                    curtail deliveries under Curtailment Option A or when Seller
                    was asked to take adjusted prices under Curtailment Option
                    B.

               B    = the total dollars paid for the energy described for A
                    above.

               C    = the weighted average price paid during the calendar year
                    by PGandE's Electric Department for oil and natural gas for
                    PGandE's fossil steam plants, expressed in $/Btu on a gas
                    Btu basis.


                                      B-14


          If the DIER is between the upper and lower Incremental Energy Rate
     Bounds specified for that year in Table B-3 for the curtailment option
     selected by Seller, no additional payment is due either Party.

          If the DIER is below the lower Incremental Energy Rate Bound, PGandE
     shall pay Seller an amount calculated as follows:


                     (Lower Incremental
          PS  =       Energy Rate Bound   - DIER)(A)(C)

          where:

          PS   =      additional payment due Seller.
          DIER =      Derived Incremental Energy Rate.

          PGandE shall add this payment to the first payment made to Seller
     following the calculation.

          If the DIER is above the upper Incremental Energy Rate Bound, Seller
     shall pay PGandE an amount calculated as follows:

          PB   =     (DIER - Upper Incremental) (A)(C)
                      Energy Rate Bound

          where:

          PS   =      amount due PGandE.
          DIER =      Derived Incremental Energy Rate.


                                      B-15


          This amount shall be deducted from the first payment made to Seller
          following the calculation. If there is any remaining amount due
          PGandE, PCandE may, at its option, invoice Seller' with such payment
          due within 30 days or deduct this amount from future payments due
          Seller.


                                      B-16



                                    TABLE B-3

                     Forecasted Incremental Energy Rates and
                         Incremental Energy Rate Bounds


          Curtailment Option A:



                                          Incremental
                     Forecasted              Energy        Upper Incremental        Lower Incremental
                     Incremental           Rate Band             Energy                   Energy
                        Energy            Width from          Rate Bound,              Rate Bound,
                        Rates              Article 4            Btu/kWh                  Btu/kWh
                       Btu/kWh              Btu/kWh           (column (a)             [column (a)]
          Year           (a)                  (b)           plus column (b)]        minus column (b)]
          ----           ---                  ---           ----------------        -----------------
                     
          1984          9,000             -----------         -----------              -----------
          1985          9,050             -----------         -----------              -----------

          1986          8,840             -----------         -----------              -----------
          1987          8,850             -----------         -----------              -----------
          1988          8,960             -----------         -----------              -----------

          1989          8,820             -----------         -----------              -----------
          1990          8,540             -----------         -----------              -----------
          1991          8,540             -----------         -----------              -----------

          1992          8,540             -----------         -----------              -----------
          1993          8,540             -----------         -----------              -----------
          1994          8,540             -----------         -----------              -----------

          1995          8,540             -----------         -----------              -----------
          1996          8,540             -----------         -----------              -----------
          1997          8,540             -----------         -----------              -----------

          1998          8,540             -----------         ------------             -----------



                                      B-17


                              TABLE B-3 (continued)



          Curtailment Option B:

                                           Incremental
                     Forecasted              Energy        Upper Incremental        Lower Incremental
                     Incremental           Rate Band             Energy                   Energy
                        Energy            Width from          Rate Bound,              Rate Bound,
                        Rates              Article 4            Btu/kWh                  Btu/kWh
                       Btu/kWh              Btu/kWh           (column (a)             [column (a)]
          Year           (a)                  (b)           plus column (b)]        minus column (b)]
          ----           ---                  ---           ----------------        -----------------
                     
          1984          9,440             -----------         -----------              -----------
          1985          9,500             -----------         -----------              -----------

          1986          9,280             -----------         -----------              -----------
          1987          9,290             -----------         -----------              -----------
          1988          9,400             -----------         -----------              -----------

          1989          9,270             -----------         -----------              -----------
          1990          8,970             -----------         -----------              -----------
          1991          8,970             -----------         -----------              -----------

          1992          8,970             -----------         -----------              -----------
          1993          8,970             -----------         -----------              -----------
          1994          8,970             -----------         -----------              -----------

          1995          8,970             -----------         -----------              -----------
          1996          8,970             -----------         -----------              -----------
          1997          8,970             -----------         -----------              -----------

          1998          8,970             -----------         ------------             -----------



                                      B-18


                                    TABLE B-4
                                  Time Periods



                                              Monday                       Sundays
                                              through                        and
                                              Friday2      Saturdays2     Holidays
                                              -------      ----------     --------

Seasonal Period A
May 1 through September 30)

                                                                  
          On-Peak                            12:30 p.m.
                                                 to
                                              6:30 p.m.

          Partial-Peak                        8:30 a.m      8:30 a.m.
                                                 to            to
                                             12:30 p.m     10:30 p.m.

                                              6:30 p.m
                                                 to
                                             10:30 p.m

          Off-Peak                           10:30 p.m.    10:30 p.m.      All Day
                                                 to            to
                                              8:30 a.m.     8:30 a.m.


          Seasonal Period B
           (October 1 through April 30)

          On-Peak                             4:30 p.m
                                                 to
                                              8:30 p.m

          Partial -Peak                       8:30 p.m.     8:30 a.m.
                                                 to            to
                                             10:30 p.m.    10:30 p.m.
                                              8:30 a.m.
                                                 to
                                              4:30 p.m.

          Off-Peak                           10:30 p.m.    10:30 p.m.      All Day
                                                 to            to
                                              4:30 p.m.     8:30 a.m.



          -----------------
          1    This table is subject to change to accord with the on-peak,
               partial peak, and off-peak periods as defined in PGandE's own
               rate schedules for the sale of electricity to its large
               industrial customers.

          2    Except the following holidays: New Year's Day, Washington's
               birthday, Memorial Day, Independence Day, Labor Day, Veteran's
               Day. Thanksgiving Day, and Christmas Day, as specified in Public
               Law 90-363 (5 U.S.C.A. Section 6103(a)).


                                      B-19


                                   TABLE B-5

                                  ENERGY PRICES

                   Energy Prices Effective February1I - April 30, 1905

          The energy purchase price calculations which will apply to energy
     deliveries determined from.. meter readings taken during February. March.
     and April 1986, are as follows:



                                         (a)                    (b)                   (c)                         (d)
                                                                               Revenue Requirement          Energy Purchase
                                     Incremental                                    for Cash                     Price4
          Time Period                Energy Rate1        cost of Energy2       Working,Cap1tal3           (d)= [(a) x (b)] + (c)
          ----------                 ------------        ---------------           --------               ---------------------
                                       (Btu/kWh)            ($/102 Btu)             ($/kWh)                       ($/kWh)
                                                                                                     
          February I - April 30
          (Period   B)

          Time of
          Delivery Basis:

            On-Peak                    16,320               5.2394                 0.00053                       0.08604
            Partial-Peak               15,689               5.2394                 0.0005l                       0.06271
            Off-Peak                   11.625               5.2394                 0.00038                       0.06129

          Seasonal Average             13,692               5.2394                 0.00045                       0.07219
           (Period B)




          --------------------

          1    Incremental energy rates (Btu/kWh) for Seasonal Period A and
               Seasonal Period B are derived from the marginal energy costs
               (including variable operating and maintenance expense) adopted by
               the CPUC in Decision No. 83-12-068 (page 339). They are based
               upon natural gas as the incremental fuel and weighted average
               hydroelectric power conditions.

          2    Cost of natural gas under PGandE Gas Schedule No. G-5S effective
               February 1, 1985 per Advice No. 1304-G.

          3    Revenue Requirement for Cash Working Capital as prescribed by the
               CPIIC in Decision No. 83-12-066.

          3    Energy Purchase Price = (Incremental Energy Rate x Cost of
               Energy) Revenue Requirement for Cash Working Capital. The energy
               purchase price excludes the applicable energy line loss
               adjustment factors. however, as ordered by Ordering Paragraph No.
               12(j) of CPUC Decision No. 82-12-120, this figure is currently
               1.0 for transmission and primary distribution loss adjustments
               and is equal to marginal cost line loss adjustment factors for
               the secondary distribution voltage level. These factors may be
               changed by the CPUC in the future. The currently applicable
               energy loss adjustment factors are shown in Table 11-6.


                                      B-20


                                    TABLE B-6



                         Energy Loss Adjustment Factorsl

                                                                      Primary               Secondary
                                              Transmission          Distribution          Distribution
                                              ------------          ------------          ------------

                                                                                   
          Seasonal Period A
           (May 1 through September 30)

            On-Peak                               1.0                   1.0                 1.0148
            Partial-Peak                          1.0                   1.0                 1.0131
            Off-Peak                              1.0                   1.0                 1.0093

          Seasonal Period B
          (October 1 through April 30)

            On-Peak                               1.0                   1.0                 1.0128
            Partial-Peak                          1.0                   1.0                 1.0119
            Off-Peak                              1.0                   1.0                 1.0087




          -------------------

          1    The applicable energy loss adjustment factors may be revised
               pursuant to orders of the CPUC.


                                      B-21


                                   APPENDIX C

                               CURTAILMENT OPTIONS

          Seller has two options regarding curtailment of energy deliveries and
     Seller has made its selection in Article 7. The two options are as follows:



          CURTAILMENT OPTION A - HYDRO SPILL AND
                                 NEGATIVE AVOIDED COST

          (a) In anticipation of a period of hydro spill conditions, as defined
     by the CPUC, PGandE may notify Seller that any purchases of energy from
     Seller during such period shall be at hydro savings prices quoted by
     PGandE. if Seller delivers energy to PGandE during any such period, Seller
     shall be paid hydro savings prices for those deliveries in lieu of prices
     which would otherwise be applicable. The hydro savings prices shall be
     calculated by PGandE using the following formula:

                                     AQF - S
                                     ------- x PP             (> or equal to 0)
                                       AQF


     where:

          AQF   =   Energy, in kWh, projected to be available during hydro spill
                    conditions from all qualifying facilities under agreements
                    containing hydro savings price provisions.


                                       C-1


          S     =   Potential energy, in kWh, from PGandE hydro facilities which
                    will be spilled if all AQF is delivered to PGandE.

          PP    =   Potential energy, in kWh, from PGandE hydro facilities which
                    will be spilled if all AQF is delivered to PGandE. Prices
                    published by PGandE for purchases during other than hydro
                    spill conditions.

          PGandE shall give Seller notice of general periods when hydro spill
     conditions are anticipated, and shall give Seller as much advance notice as
     practical of any specific hydro spill period and the hydro savings price
     which will be applicable during such period.


          (b) PGandE shall not be obligated to accept or pay for and may require
     Seller with a Facility with a nameplate rating of one megawatt or greater
     to interrupt or reduce deliveries of energy during periods when PGandE
     would incur negative avoided costs (as defined by the CPUC) due to
     continued acceptance of energy deliveries under this Agreement. Whenever
     possible, PGandE shall give Seller reasonable notice of the possibility
     that interruption or reduction of deliveries may be required.

          (c) Before interrupting or reducing deliveries under subsection (b),
     above, and before invoking hydro savings prices under subsection (a),
     above, PGandE shall take reasonable steps to make economy sales of the
     surplus energy giving rise to the condition. If such economy sales are
     made, while the surplus energy condition exists seller shall be paid at


                                      C-2


     the economy sales price obtained by PGandE in lieu of the otherwise
     applicable prices.

          (d) If Seller is selling net energy output to PGandE and
     simultaneously purchasing its electrical needs from PGandE and Seller
     elects not to sell energy to PGandE at the hydro savings price pursuant to
     subsection (a) or when PGandE curtails deliveries of energy pursuant to
     subsection (b), Seller shall not use such energy to meet its electrical
     needs but shall continue to purchase all its electrical needs from PGandE.
     If Seller is selling surplus energy output to PGandE, subsections (a) or
     (b) shall only apply to the surplus energy output being delivered to
     PGandE, and Seller can continue to internally use that generation it has
     retained for its own use.



                  CURTAILMENT OPTION B - ADJUSTED PRICE PERIOD

          (a) In each calendar year, the price which PGandE is obligated to pay
     Seller for energy deliveries during 1,000 off-peak hours (as defined in
     Table B-4, Appendix B) may be adjusted to a price equal to, but not in
     excess of, PGandE's available alternative source. This adjusted price shall
     be effective under any of the following conditions:


          (i) when PGandE's energy source at the margin is not a PGandE oil- or
     gas-fueled plant, and PGandE can replace Seller's energy with energy from


                                      C-3


     this source at a cost less than the price paid to Seller;

          (ii) when PGandE would incur negative avoided costs (as defined by the
     CPUC) due to continued acceptance of energy deliveries under this
     Agreement; or

          (iii) when PGandE is experiencing minimum system operations.

          During any of the conditions described above the adjusted price may be
     zero.

          (b) Whenever possible, PGandE shall give Seller reasonable notice of
     any price adjustment for energy deliveries and its probable duration.

          (c) If Seller is selling net energy output to PGandE and
     simultaneously purchasing its electrical needs from PGandE and Seller
     elects not to sell energy to PGandE at the adjusted price, Seller shall not
     use such energy to meet its electrical needs but shall continue to purchase
     all its electrical needs from PGandE.

          (d) After Seller receives notice of the probable duration of the
     period during which the adjusted price will be paid, Seller may elect to
     perform maintenance during such  period and so inform the PGandE employee


                                      C-4


          in charge at the designated PGandE switching center prior to the time
          when the adjusted price period is expected to begin. If Seller makes
          such election, the number of off-peak hours of probable duration
          quoted in PGandE's notice to Seller shall be applied to the 1,000-hour
          calendar year limitation set forth in this section. After an election
          to do maintenance, if Seller makes any deliveries of energy during the
          quoted probable duration period, Seller shall be paid the adjusted
          price quoted in its notice from PGandE without regard to any
          subsequent changes on the PGandE system which may alter the adjusted
          price or shorten the actual duration of the condition.


                                      C-5


                                   APPENDIX D

                              AS-DELIVERED CAPACITY


     D-1 AS-DELIVERED CAPACITY PAYMENT OPTIONS

          Seller has two options for as-delivered capacity payments and Seller
     has made its selection in Article 5. The two options are as follows:



                     AS-DELIVERED CAPACITY PAYMENT OPTION 1

          PGandE shall pay Seller for as-delivered capacity at prices authorized
     from time to time by the CPUC. The as-delivered capacity prices in effect
     on the date of execution are calculated as shown in Exhibit D-l.



                     AS-DELIVERED CAPACITY PAYMENT OPTION 2

          During the fixed price period, the as-delivered capacity prices will
     be calculated in accordance with Exhibit D-1 and the forecasted shortage
     costs in Table D-2.

          For the remaining years of the term of agreement, PGandE shall pay
     Seller for as-delivered capacity at the higher of:


                                      D-1


          (i) prices authorized from time to time by the, CPUC;


          (ii) the as-delivered capacity prices that were paid Seller in the
               last year of the fixed price period; or


          (iii) the as-delivered capacity prices in effect in the first year
               following the end of the fixed price period, provided that the
               annualized shortage cost from which these prices are derived does
               not exceed the annualized value of a gas turbine.



              D-2 AS-DELIVERED CAPACITY IN EXCESS OF FIRM CAPACITY

          The amount of capacity delivered in excess of firm capacity will be
     considered as-delivered capacity. This as-delivered capacity is based on
     the total kilowatt-hours delivered each month during all on-peak,
     partial-peak and off-peak hours excluding any energy associated with
     generation levels equal to or less than the firm capacity.


          Seller has the two options listed in Section D-1 for payment for such
     as-delivered cam. Seller has made its selection in Article 5.


                                      D-2


                                   EXHIBIT D-1


          The as-delivered capacity price (in cents per kW-hr) for power
     delivered by the Facility is the product of three factors:



               (a) The shortage cost in each year the Facility is operating.
          Currently, this shortage cost is $60 per kW-year.

               (b) A capacity loss adjustment factor which provides for the
          effect of the deliveries on PGandE's transmission and distribution
          losses based on the Seller's interconnection voltage level. The
          applicable capacity loss adjustment factors for non-remote' Facilities
          are presented in Table D-1(a). Capacity loss adjustment factors for
          remote Facilities shall be calculated individually.


               (e) An allocation factor which accounts for the different values
          of as-delivered capacity in different time periods and converts
          dollars per kW-year to cents per kWh. The current allocation factors
          are presented in Table D-1(b). The time periods to which they apply
          are shown in Table B-4, Appendix B. The allocation factors are subject
          to change from time to time.


     -----------------

     1    As defined by the CPUC.


                                      D-3


                                  TABLE D-1(a)

                        Capacity Loss Adjustment Factors
                           for Non-Remotes Facilities


          Voltage Level                              Loss Adjustment Factor
          -------------                              ----------------------
          Transmission                                       .989
          Primary Distribution                               .991
          Secondary Distribution                             .991


     If the Facility is remote, the capacity loss adjustment factor is _______2.




                                  TABLE D-1(b)

                               Allocation Factors
                           for As-Delivered Capacity3



                                     On-Peak           Partial-Peak           Off-Peak
                                 ((cent)-yr/$-hr)    ((cent)-yr/$-hr)     ((cent)-yr/$-hr
                                 ----------------    ----------------     ---------------
                                                                     
          Seasonal Period A          .10835             .02055                .00002
          Seasonal Period B          .00896             .00109                .00001



          -----------------
          1    As defined by the CPUC. The capacity loss adjustment factors for
               remote Facilities are determined individually.

          2    Determined individually.

          3    The units for the allocation factor, cent-yr/$-hr, are derived
               from the conversion of $/kW-yr into 9/kWh as follows:

                          (cent)/kWh     (cent)/kW-hr       (cent)-yr
                          ----------   = ------------  =  -------------
                            $/kW-yr        $/kW-yr            $-hr

          The allocation factors were prescribed by the CPUC in Decision No.
          83-12-068 and are subject to change from time to time.


                                      D-4


                                    TABLE D-2

                        Forecasted Shortage Cost Schedule


                                                    Forecast Shortage
                Year                                   Cost,$/kW-Yr
                ----                                   ------------

                1983                                       70.
                1984                                       76
                1985                                       81

                1986                                       88
                1987                                       95
                1988                                      102

                1989                                      110
                1990                                      118
                1991                                      126

                1992                                      135
                1993                                      144
                1994                                      154

                1995                                      164
                1996                                      176
                1997                                      188


                                      D-5


                                   APPENDIX E

                                  FIRM CAPACITY


                                    CONTENTS


          Section                                                        Page
          -------                                                        ----
            E-1        GENERAL                                           E-2

            E-2        PERFORMANCE REQUIREMENTS                          E-2

            E-3        SCHEDULED MAINTENANCEE                            E-4

            E-4        ADJUSTMENTS TO FIRM CAPACITY                      E-5

            E-5        FIRM CAPACITY PAYMENTS                            E-6

            E-6        DETERMINATION OF NATURAL FLOW DATA                E-12

            E-7        THEORETICAL OPERATION STUDY                       E-13

            E-8        DETERMINATION OF AVERAGE DRY                      E-15
                       YEAR CAPACITY RATINGS

            E-9        INFORMATION REQUIREMENTS                          E-15

            E-1O       ILLUSTRATIVE EXAMPLE                              E-16

            E-11       MINIMUM DAMAGES                                   E-19


                                      E-1


                                   APPENDIX E

                                  FIRM CAPACITY



          E-l  GENERAL

               This Appendix E establishes conditions and prices under which
          PGandE shall pay for firm capacity.


               PGandE's obligation to pay for firm capacity shall begin on the
          firm capacity availability date. The firm capacity price shall be
          subject to adjustment as provided for in this Appendix E.


               The firm capacity prices in Table E-2 are applicable for
          deliveries of firm capacity beginning after December 30, 1982.


          E-2  PERFORMANCE REQUIREMENTS

               (a) To receive full capacity payments, the firm Capacity shall be
          delivered for all of the on-peak hours1 in the peak months on the
          PGandE system, which are presently the months of June, July, and
          August, subject to a 20 percent allowance for forced outages in any
          month. Compliance with this provision shall be based on the Facility's
          total on-peak deliveries for each of the peak



          --------------
          1    On-peak, partial-peak, and off-peak hours are defined in Table
               B-4, Appendix B.


                                      E-2


     months and shall exclude any energy associated with generation levels
     greater than the firm capacity.


          (b) If Seller is prevented from meeting the performance requirements
     because of a forced outage on the PGandE system, a PGandE curtailment of
     Seller's deliveries, or a condition set forth in Section A-7, Appendix A,
     PGandE shall continue capacity payments. Firm capacity payments will be
     calculated in the same manner used for scheduled maintenance outages.


          (c) If Seller is prevented from meeting the performance requirements
     because of force majeure, PGandE shall continue capacity payments for
     ninety days from the occurrence of the force majeure. Thereafter, Seller
     shall be deemed to have failed to have met the performance requirements.
     Firm capacity payments will be calculated in the same manner used for
     scheduled maintenance outages.


          (d) If Seller is prevented from meeting the performance requirements
     because of exteme dry year conditions, PGandE shall continue capacity
     payments. Extreme dry year conditions are drier than those used to
     establish firm capacity pursuant to Section E-8. Seller shall warrant to
     PGandE that the Facility is a hydroelectric facility and that such
     conditions are the sole cause of Seller's inability to meet its firm
     capacity obligations.


                                      E-3


          (e) If Seller is prevented from meeting the performance requirements
     for reasons other than those described above in Sections E-2(b), (c), or
     (d):

               (1) Seller shall receive the reduced firm capacity payments as
          provided in Section E-5 for a probationary period not to exceed 15
          months, or as otherwise agreed to by the Parties.

               (2) If, at the end of the probationary period Seller has not
          demonstrated that the Facility can meet the performance requirements,
          PGandE may derate the firm capacity pursuant to Section E-4(b).



     E-3 SCHEDULED MAINTENANCE



               Outage periods for scheduled maintenance shall not exceed 840
          hours (35 days) in any 12-month period. This allowance may be used in
          increments of an hour or longer on a consecutive or nonconsecutive
          basis. Seller may accumulate unused maintenance hours from one
          12-month period to another up to a maximum of 1,080 hours (45 days).
          This accrued time must be used consecutively and only for major
          overhaul's. Seller shall provide PGandE with the following advance
          notices: 24 hours for scheduled outages less than one day, one week
          for a scheduled outage of one day or more (except for major
          overhauls), and six months for a major overhaul. Seller shall not
          schedule major overhauls during the peak months (presently June, July
          and August). Seller shall make reasonable efforts to schedule or
          reschedule routine maintenance outside the peak months, and in no


                                       E-4



          event shall outages for scheduled maintenance exceed 30 peak hours
          during the peak months. Seller shall confirm in writing to. PGandE
          pursuant to Article 9, within 24 hours of the original notice, all
          notices Seller gives personally or by telephone for scheduled
          maintenance.

               If Seller has selected Curtailment Option B, off-peak hours of
          maintenance performed pursuant to Section (d) of Curtailment Option B,
          Appendix C shall not be deducted from Seller's scheduled maintenance
          allowances set forth above.


          E-4     ADJUSTMENTS TO FIRM CAPACITY


               (a) Seller may increase the firm capacity with the approval of
          PGandE and receive payment for the additional capacity thereafter in
          accordance with the applicable capacity purchase price published by
          PGandE at the time the increase is first delivered to PGandE.


               (b) Seller may reduce the firm capacity at any time prior to the
          firm capacity availability date by giving written notice thereof to
          PGandE. PGandE may derate the firm capacity in accordance with Section
          E-2(e) as a result of appropriate data showing Seller has failed to
          meet the performance requirements of Section E-2.


                                      E-5


          E-5  FIRM CAPACITY PAYMENTS


               The method for calculation of firm capacity payments is. shown
          below. As used below in this section, month refers to a calendar
          month.



               The monthly payment for firm capacity will be the product of the
          Period Price Factor (PPF), the Monthly Delivered Capacity (MDC), the
          appropriate capacity loss adjustment factor from Table E-1 based on
          the Facility's interconnection voltage, and the appropriate
          performance bonus factor, if any, from Table E-3, plus any allowable
          payment for outages due to scheduled maintenance. The firm capacity
          price shall be applied to meter readings taken during the separate
          times and periods as illustrated in Table B-4, Appendix B.

               The PPF is determined by multiplying the firm capacity price by
          the following Allocation Factors1:

                                                       Firm
                                                       ----             PPF
                         Allocation Factor   X   Capacity Price  = ($/kW-month)
                                                 --------------

          Seasonal           .18540             --------------     -----------
          Period A

          Seasonal           .01043             --------------     -----------
          Period B


          ---------------

          1    These allocation factors were prescribed by the CPUC in Decision
               No. 83-12-068. All allocation factors are subject to change by
               PGandE based on PGandE's marginal capacity cost allocation, as
               determined in general rate case proceedings before the CPUC.
               Seasonal Periods A end and B are defined in Table B-4, Appendix
               B.


                                      E-6


          The MDC is determined in the following manner:

               (1) Determine the Performance Factor (P), which is defined as the
          lesser of 1.0 or the following quantity:

                          P  =         A
                               -----------------        (< or = 1.0)
                               C x (B-S) x (0.8*)

          Where:

               A =  Total kilowatt-hours delivered during all on-peak and
                    partial-peak hours excluding any energy associated with
                    generation levels greater than the firm capacity.

               C =  Firm capacity in kilowatts.

               B =  Total on-peak and partial-peak hours during the month.

               S =  Total on-peak and partial-peak hours during the month
                    Facility is out of service on scheduled maintenance.

               (2) Determine the Monthly Capacity Factor (MCF), which is
          computed using the following expression:



                          MCF = P x (1.0 - M)
                                          ---
                                           D

          Where:

               M =  The number of hours during the month Facility is out of
                    service on scheduled maintenance.

               D =  The number of hours in the month.


          ---------------

          * 0.8 reflects a 20% allowance for forced outage.


                                      E-7


          (3) Determine the MDC by multiplying the MCF by C;

                          MDC  (kilowatts) = MCF x C

               The monthly payment for firm capacity is then determined by
          multiplying the PPF by the MDC, by the appropriate capacity loss
          adjustment factor presented from Table E-l, and by the appropriate
          performance bonus factor, if any, from Table E-3.

          monthly payment
          for firm capacity = PPF x MDC x   capacity loss   x performance
                                          adjustment factor   bonus factor

               Furthermore, the payment for a month in which there is an outage
          for scheduled maintenance shall also include an amount equal to the
          product of the average hourly firm capacity payment' for the most
          recent month in the same type of Seasonal Period (i.e., Seasonal
          Period A or Seasonal Period B) during which deliveries were made times
          the number of hours of outage for scheduled maintenance in the current
          month. Firm capacity payments will continue during the outage periods
          for scheduled maintenance provided that the provisions of Section E-3
          are met.

               During a probationary period Seller's monthly payment for firm
          capacity shall be determined by substituting for the firm capacity,



         ----------------

          1    Total monthly payment divided by the total number of hours in the
               monthly billing period.


                                      E-8


          the capacity at which Seller would have met the performance
          requirements. In the event that during the probationary period Seller
          does not meet the performance requirements at whatever firm capacity
          was established for the previous month, Seller's monthly payment for
          firm capacity shall be determined by substituting the firm capacity at
          which Seller would have met the performance requirements. The
          performance bonus factor shall not be applied during probationary
          periods.




                                    TABLE E-1

          If the Facility is non-remote1 the firm capacity loss adjustment
          factors are as follows:


          Voltage Level                                Loss Adjustment Factor
          -------------                                ----------------------
          Transmission                                         .989

          Primary Distribution                                 .991

          Secondary Distribution                               .991



          If the' Facility is remote the firm capacity loss adjustment factor is
          _______________2


          ---------------

            1  Is defined by the CPUC.

            2  Determined individually.


                                      E-9


                                    TABLE E-2

                          Firm Capacity Price Schedule
                          ----------------------------
                              (Levelized $/kW-year


             Firm
           Capacity
            Avail-
           ability
             Date               Number of Years of Firm Capacity Delivery
             ----               -----------------------------------------
             ------- -----------------------------------------------------------------------------------------
             (Year)   1    2    3     4    5    6    7    8    9   10   11   12    13   14   15     20   25   30
             -------  -    -    -     -    -    -    -    -    -   --   --   --    --   --   --     --   --   --
                                                       
             1982    65   68    70    72   75   77   79   81   84   86   88   90   91   93    95   103  109  113

             1983    70   73    75    78   80   83   85   88   90   92   94   96   98  100   102   110  117  122

             1984    76   78    81    84   86   89   92   94   97   99  101  103  106  108   110   118  125  130

             1985    81   84    87    90   93   96   99  101  104  106  109  111  113  115   118   127  134  140

             1986    88   91    94    97  100  103  106  109  112  114  117  119  122  124   126   136  144  150

             1987    95   98   101   105  108  111  114  117  120  123  125  128  130  133   135   146  154  160



                                      E-10


                                    TABLE E-3


                            Performance Bonus Factor


               The following shall be the performance bonus factors applicable
          to the calculation of the monthly payments for firm capacity delivered
          by the Facility after it has demonstrated a firm capacity factor in
          excess of 85%.


                            DEMONSTRATED
                        FIRM CAPACITY FACTOR                      PERFORMANCE
                                 (%)                             BONUS FACTOR
                                 ---                             ------------

                                 85                                1.000
                                 90                                1.059
                                 95                                1.118
                                100                                1.176


               After the Facility has delivered power during the span of all of
          the peak months on the PGandE system (presently June, July, and
          August) in any year (span),



               (i) the firm capacity factor for each such month shall be
          calculated in the following manner:


                           FIRM CAPACITY FACTOR (%) =       F
                                                       ---------  x 100
                                                      (N-W) x Q


          Where:


               F  = Total kilowatt-hours delivered by Seller in any peak month
                    during all on-peak hours excluding any energy associated
                    with generation levels greater than the firm capacity.


                                      E-11


               N =  Total on-peak hours during the month.

               W =  Total on-peak hours during the peak month that the Facility
                    is out of service on scheduled, maintenance.

               Q =  Firm capacity in kilowatts.


               (ii) the arithmetic average of the above firm capacity factors
          shall be determined for that span,

               (iii) the average of the above arithmetic average firm capacity
          factors for the most recent span(s), not to exceed 5, shall be
          calculated and shall become the Demonstrated Firm Capacity Factor.

               To calculate the performance bonus factor for a Demonstrated Firm
          Capacity Factor not shown in Table E-3 use the following formula:


          Performance Bonus Factor = Demonstrated Firm Capacity- Factor %
                                     -------------------------------------
                                                     85%


          SECTIONS E-6 THROUGH E-10 SHALL APPLY ONLY TO HYDROELECTRIC PROJECTS
          --------------------------------------------------------------------


          E-6  DETERMINATION OF NATURAL FLOW DATA



               Natural flow data shall be based on a period of record of at
          least 50 years and which includes historic critically dry periods.


                                      E-12


          In the event Seller demonstrates that a natural flow data base of at
          least50 years would be unreasonably burdensome, PGandE shall accept a
          shorter, period of record with a corresponding reduction in the
          averaging basis set forth in section E-8. Seller shall determine the
          natural flow data by month by using one of the following methods:


                                    Method 1

               If stream flow records are available from a recognized gauging
          station on the water course being developed in the general vicinity of
          the project, Seller may use the data from them directly.


                                    Method 2

               If directly applicable flow records are not available, Seller may
          develop theoretical natural flows based on correlation with available
          flow data for the closest adjacent and similar area which has a
          recognized gauging station' using generally accepted hydrologic
          estimating methods.


          E-7  THEORETICAL OPERATION STUDY

               Based on the monthly natural flow data developed under Section
          E-6 a theoretical operation study shall be prepared by seller. Such a


                                      E-13


          study shall identify the monthly capacity rating in kW and the monthly
          energy production in kWh for each month of each year. The study shall
          take into account. all relevant operating constraints, limitations,
          and requirements including but not limited to --

               (1) Release requirements for support of fish life and any other
          operating constraints imposed on the project;

               (2) Operating characteristics of the proposed equipment of the
          Facility such as efficiencies, minimum and maximum operating levels,
          project control procedures, etc.;

               (3) The design characteristics of project facilities such as head
          losses in penstocks, valves, tailwater elevation levels, etc.; and

               (4) Release requirements for purposes other than power generation
          such as irrigation, domestic water supply, etc.

               The theoretical operation study for each month shall assume an
          even distribution of generation throughout the month unless Seller can
          demonstrate that the Facility has water storage characteristics. For
          the study to show monthly capacity ratings, the Facility shall be
          capable of operating during all on-peak hours in the peak months on
          the PGandE system, which are presently the months of June, July, and
          August. If the project does not have this capability throughout each
          such month, the capacity rating in that month of that year shall be
          set at zero for purposes of this theoretical operation study.


                                      E-14


          E-8  DETERMINATION OF AVERAGE DRY YEAR CAPACITY RATINGS

               Based on the results of the theoretical operation study,
          developed under Section E-7, the average dry year capacity rating
          shall be established for each month. The average dry year shall be
          based on the average of the five years of the lowest annual generation
          as shown in the theoretical operation study. once such years of lowest
          annual generation are identified, the monthly capacity rating is
          determined for each month by averaging the capacity ratings from each
          month of those years. The firm capacity shown in Article 5 shall not
          exceed the lowest average dry year monthly capacity ratings for the
          peak months on the PGandE system, which are presently the months of
          June, July, and August.

          E-9  INFORMATION REQUIREMENTS


               Seller shall provide the following information to PGandE for its
          review:

               (1) A summary of the average dry year capacity ratings based on
          the theoretical operation study as provided in Table E-4;

               (2) A topographic project map which shows the location of all
          aspects of the Facility and locations of stream gauging stations used
          to determine natural flow data;

               (3) A discussion of all major factors relevant to project
          operation;


                                      E-15


               (4) A discussion of the methods and procedures used to establish
          the natural flow data. This discussion shall be in sufficient detail
          for PGandE to determine that the, methods are consistent with those
          outlined in Section E-6 and are consistent with generally accepted
          engineering practices; and

               (5) Upon specific written request by PGandE, Seller's theoretical
          operation study.



          E-10 ILLUSTRATIVE EXAMPLE



               (1) Determine natural flows - These flows are developed based on
          historic stream gauging records and are compiled by month, for a
          long-term period (normally at least 50 years or more) which covers dry
          periods which historically occurred in the 1920's and 30's and more
          recently in 1976 and 77. In all but unusual situations this will
          require application of hydrological engineering methods to records
          that are available, primarily from the USGS publication "Water
          Resources Data for California".



               (2) Perform theoretical operation study - Using the natural flow
          data compiled under (1) above a theoretical operation study is
          prepared which determines, for each month of each year, energy
          generation (kWh) and capacity rating (KW). This study is performed
          based on the Facility design, operating capabilities, constraints,
          etc., and should take into account all factors relevant to project


                                      E-16


          operation. Generally such a study is done by computer which routes the
          natural flows through project features, considering additions and
          withdrawals from storage, spill, past the project, releases for
          support of fish life, etc., to determine flow available for
          generation. Then the generation and capacity amounts are computed
          based on equipment performance, efficiencies, etc.


               (3) Determine average dry year capacity ratings - After the
          theoretical project operation study is complete the five years in
          which the annual generation (kWh) would have been the lowest are
          identified. Then for each month, the capacity rating (kW) is averaged
          for the five years to arrive at a monthly average capacity rating. The
          firm capacity is then set by the Seller based on the monthly average
          dry year capacity ratings and the performance requirements of this
          appendix. An example project is shown in the attached completed Table
          E-4.


                                      E-17


                                     EXAMPLE
                                    TABLE E-4


                     Summary of Theoretical Operation Study


          Project:  New Creek 1

          Water Source: West Fork New Creek

          Mode of Operation: Run of the river

          Type of Turbine: Francis Design Flow: 100 cfs Design Head: 150 feet

          Operating Characteristics1:



                                  Flow        Head   (feet)    Output      Efficiency %)
                                  ----        ------------     ------     --------------
                                 (cfs)        Gross    Net      (kW)     Turbine    Generator
                                 -----        -----   ----      ----     -------    ---------

                                                                    
          Normal Operation        100          160     150      1,120       90        98
          Maximum Operation       110          160     148      1,150       85        98
          Minimum Operation        30          160     155        290       75        98



          Average Dry Year Operation - Based on the average of the following
          lowest generation years: 1930, 1932, 1934, 1949, 1977.



                            Energy Generation      Capacity Output         Percent of
           Month                 (kWh)                  (kW)          Total Hours Operated
           -----                 -----                  ----          --------------------
                                                                      
          January               855,000                1,150                   100
          February              753,000                1,120                   100
          March                 818,000                1,100                   100
          April                 727,000                1,010                   100
          May                   699,000                  940                   100
          June                  612,000                  850                   100
          July                  484,000                  650                   100
          august                305,000                  410                   100
          September             245,000                  340                   100
          October               148,800                  200                   100
          November              468,000                  650                   100
          December              595,000                  800                   100


          Maximum firm capacity: 410 kW


          ---------------

          1    If Facility has a variable head, operating curves should be
               provided.


                                      E-18


          E-11 MINIMUM DAMAGES


               (a) In the event the firm Capacity is derated or Seller
          terminates this Agreement, the quantity by which the firm capacity is
          derated or the firm capacity shall be used to calculate the payments
          due PGandE in accordance with Section (d).


               (b) Seller shall be invoiced by PGandE for all amounts due under
          this section. Payment shall be due within 30 days of the date of
          invoice.


               (c) If Seller does not make payments pursuant to Section (b),
          PGandE shall have the right to offset any amounts due it against any
          present or future payments due Seller.


               (d) Seller shall pay to PGandE:

                    (i) an amount equal to the difference between (a) the firm
               capacity payments already paid by PGandE, based on the original
               term of agreement and (b) the total firm capacity payments which
               PGandE would have paid based on the period of Seller's actual
               performance using the adjusted firm capacity price. Additionally,
               Seller shall pay interest, compounded monthly from the date the
               excess capacity payment was made until the date Seller repays


                                      E-19


               PGandE, on all overpayments, at the published Federal Reserve
               Board three months' Prime Commercial Paper rate; plus


                    (ii) a sum equal to the amount by which the firm capacity is
               being terminated or derated times the difference between the
               current firm capacity price on the date of termination or
               deration for a term equal to the balance of the term of agreement
               and the firm capacity price, multiplied by the appropriate factor
               shown in Table E-5 below. In the event that the current firm
               capacity price is less than the firm capacity price, no payment
               under this subsection (ii) shall be due either Party.



                                    TABLE E-5


                       Amount of Firm Capacity
                        Terminated or Derated           Factor
                        ----------------------           ------

               1,000       kW or under                    0.25
                over       1,000 kW through  10,000 kW    0.75
                over      10,000 kW through  25,000 kW    1.00
                over      25,000 kW through  50,000 kW    3.00
                over      50,000 kW through 100,000 kW    4.00
                over     100,000 kW                       5.00


                                      E-20


                                   APPENDIX F

                                 INTERCONNECTION


                                    CONTENTS


          Section                                                      Page
          -------                                                      ----

            F-1        INTERCONNECTION TARIFFS                         F-2

            F-2        POINT OF DELIVERY LOCATION SKETCH               F-3

            F-3        INTERCONNECTION FACILITIES FOR WHICH            F-4
                       SELLER IS RESPONSIBLE


                                      F-1


          F-1    INTERCONNECTION TARIFFS


                 (The applicable tariffs in effect at the time of, execution of
                 this Agreement shall be attached.)


                                      F-2


                                   ASSIGNMENT

          FOR GOOD AND VALUABLE CONSIDERATION, as set forth in the "Development
     Option and Stock Purchase Agreement," effective June 1, 1989, the
     undersigned FAYETTE ENERGY CORPORATION, a Delaware corporation ("FEC"),
     hereby assigns, transfers and conveys to ALTAMONT COGENERATION CORPORATION,
     a California corporation ("ACC"), all of FEC's right, title and interest in
     and to that certain Standard Offer #4, option #1, Power Purchase Agreement
     by and between Fayette Manufacturing Corporation and Pacific Gas and
     Electric Company, date April 15, 1985, for the delivery of 6500 kilowatts
     nameplate rating at 100% avoided costs for a cogeneration plant sited in
     the Altamont Pass in California.


     Fayette Energy Corporation


     By /s/ Jerry Fuchs
        ---------------
        Jerry Fuchs. Vice President        April 10, 1990


                                   ASSUMPTION

          IN CONSIDERATION OF THE FOREGOING ASSIGNMENT, the undersigned ALTAMONT
     COGENERATION CORPORATION hereby assumes all of the rights, duties and
     obligations of the Seller under said Standard Offer 64, Option M1, Power
     Purchase Agreement. In the event that ACC's rights under the Power Purchase
     Agreement herein assigned are terminated or ACC has received notice of
     default from POSE due to any act or failure to act by ACC, FEC may (subject




     to the Power Purchase Agreement) cure such default within 90 days of
     receipt by FEC of written notice from ACC that ACC's rights have been
     terminated or that ACC has received notice of default from PG&E, and FEC
     may (subject to the Power Purchase Agreement) reassume directly all rights
     and obligations of ACC to and under the Power Purchase Agreement. ACC shall
     take all reasonable action necessary to ensure that FEC is promptly
     notified of any notice of default given to Seller under the Power Purchase
     Agreement so as to maximize the time available to FEC to ensure that the
     assigned Power Purchase Agreement is not terminated by PG&E, provided,
     however, that FEC shall not be entitled to effect any cure of such default
     on behalf of ACC if ACC is diligently proceeding to cure such default
     within the time allowed for such cure under the Power Purchase Agreement.
     ACC shall indemnify, hold harmless and defend FEC for any claim made by
     PG&E of liability of FEC for the duties and obligations of the Seller under
     the assigned Power Purchase Agreement arising during such time as ACC is
     the Seller thereunder. The rights of any subsequent assignee to the
     assigned Power Purchase Agreement shall be subject to the conditions set
     forth in this paragraph.


     Altamont Cogeneration Corporation


     By /s/ Jerry Fuchs      April 10, 1990
        ---------------
        Jerry Fuchs, President

EX-10.3

                                                                    Exhibit 10.3
                                 AMENDMENT TO THE

                            POWER PURCHASE AGREEMENT

                                     BETWEEN

                            JRW ASSOCIATES, L.P. AND

                        PACIFIC GAS AND ELECTRIC COMPANY

                              (PG&E LOG NO. 35C045)


     THIS AMENDMENT ("Amendment") is by and between PACIFIC GAS AND ELECTRIC
COMPANY ("PG&E"), a California corporation and JRW Associates, L.P., a
California limited partnership ("Seller"). PG&E and Seller are sometimes
referred to herein individually as "Party" and collectively as the "Parties"


                                    RECITALS

     A. On December 9, 1985, Seller (or Seller's predecessor, as applicable) and
entered into a Power Purchase Agreement, (as amended, "the PPA") pursuant to
which PG&E purchases electric power from Seller and Seller sells electric power
to PG&E.

     B. On April 6, 2001, PG&E filed voluntary petition under chapter 11 of the
United States Bankruptcy Code in the San Francisco Division of the United States
Bankruptcy Court for the Northern District of California (the "Bankruptcy
Court") (In re Pacific Gas and Electric Company, Banks. Case No. 01-03923).

     C. On June 14, 2001, the Commission issued D.01-06-015, which approved as
reasonable certain non-standard PPA price modifications.

     D. Seller and PG&E now desire to enter into the PPA price modification set
forth below. Seller has advised PG&E that Seller is unable to enter into the PPA
price modification unless the Bankruptcy Court has approved this Amendment and
Seller is provided a limited option to terminate this Amendment following
Bankruptcy Court approval if Seller is unable to Arrange for fuel purchases to
accommodate the price modification contemplated under this Amendment.


                                     1 of 3



                                    AMENDMENT

     In consideration of the mutual promises and covenants contained herein,
PG&E and Seller agree to as follows:

     1. INTERIM ENERGY PRICE

     Unless otherwise set fourth in the PPA, for the period commencing with the
date on which this Amendment has been executed by the Parties and ending upon
the commencement of the Fixed Rate Period, as defined in Section 2 below, the
price for energy delivered, if any, to PG&E by Seller shall be determined
pursuant to the PPA, without reference to this Amendment.

     2. FIXED ENERGY PRICE

     Commencing with this date that is the earlier of, August 1, 2001, August
16, 2001 or September 1, 2001 following approval of the Bankruptcy Court as
specified in Section 4 below (hereafter, the "Bankruptcy Court Approval Date")
and ending on July 15, 2006 (this period referred to hereafter as the "Fixed
Rate Period"), Seller elects to replace the energy price term specified in the
PPA (PG&E's "full short-run avoided costs" or "full short-run avoided operating
costs" as the case may be) with the applicable energy prices as specified in
Attachment A. No provision of the PPA other than the energy price term is or
shall be deemed to be modified, amended, waived or otherwise affected by this
Amendment. The parties agree to reasonably cooperate and contest any challenge
in any Commission proceeding that seeks to alter or modify the energy pricing
terms set fourth in Attachment A, including, but not limited to any challenge to
the reasonableness of PG&E having entered into this Amendment.

                                    2 of 3


     3. SELLER'S OPTION PERIOD

     For a fifteen-day period following the Bankruptcy Court Approval Date,
Seller shall have the sole right to terminate this Amendment. Upon termination
of this Amendment pursuant to this section 3, this Amendment shall be deemed a
nullity.

     4. EFFECTIVENESS

     This Amendment shall not become effective unless and until it has been
approved by the Bankruptcy Court. If the Bankruptcy Court has not approved this
Amendment by August 31, 2001, this Amendment shall be deemed a nullity.

     5. SIGNATURES

     IN WITNESS WHEREOF, Seller and PG&E have caused this Amendment to be
executed by their authorized representatives.


PACIFIC GAS AND ELECTRIC COMPANY
a California corporation

By:   /s/ illegible
      -------------------------

Title: Director
      -------------------------

Date: 7/14/01
      -------------------------

JRW ASSOCIATES, L.P.

By:   Martin V. Quinn
      -------------------------

Title: Ex VP & COO
      -------------------------

Date: 7/13/01
      -------------------------


                       3 of 3


Pacific Gas and Electric Company





[LOGO OMITTED]


June 1, 1993

JRW ASSOCIATES, L.P.
ATTN. BOB POLLOCK
   CIO WAUKESHA-PEARCE INDUSTRIES
P.O. BOX 35068
HOUSTON, TX 77235-5068

Dear Sir/Madam:

This is to notify you of a change of address for Article 9, "Notices", of the
Power Purchase Agreement (PPA) between PG&E and JRW Associates. Please direct
all future written notices to:

                Mr. Richard A. Layne
                Director, Power Finance Department, B13D
                Pacific Gas and Electric Company
                77 Beale Street, Room 1311
                P.O. Box 770000
                San Francisco, CA 94177

The address in the PPA relating to insurance matters has also changed. All
insurance certificates, endorsements, cancellations, terminations, alterations,
and material changes of such insurance must be issued and submitted to the
following:

                Pacific Gas and Electric Company
                Power Contracts Department - B23C
                Attn: Insurance Coordinator
                P.O. Box 770000, Room
                2354 San Francisco, CA 94177

CPUC Decision 93-04-001 dated April 7, 1993, adopted the Division of Ratepayer
Advocate's recommendation for modifying the reporting requirements applicable to
the quarterly report of negative avoided cost or hydro spill. The above decision
ordered that: Decision (D) 82-01-103, Ordering Paragraph 17, is modified to read
in full as follows:

     "Each utility shall promptly file a report for any quarter in which a
     negative avoided cost or hydro spill condition occurs."

     Please inform all parties in your organization of the above information. If
     you have any questions please call me a (415) 973-9434.

Sincerely,

/s/ Linda Lea Weber

Linda Lea Weber
Power Systems Engineer
(415)973-9434




                                 FIRST AMENDMENT
                                     TO THE
                            POWER PURCHASE AGREEMENT
                          FOR FIRM CAPACITY AND ENERGY
                              (PG&E LOG NO. 25C045)


     This First Amendment is by and between Pacific Gas and Electric Company, a
California Corporation ("PG&E"), and JRW Associates, L.P., a California Limited
Partnership ("Seller"). It amends the Standard Offer 2 Power Purchase Agreement
signed by PG&E on December 9, 1985 and by Interpro International, Inc.
("Interpro"), Seller's predecessor in interest, on September 3, 1985
("Agreement"), for a 10,750 kW cogeneration project located at J.R. Wood, Inc.,
7916 West Bellevue Road, Atwater, California 95301.


     WHEREAS, on October 9, 1989, PG&E was notified by Interpro of the
assignment of the Agreement from Interpro to National Cogeneration Corporation
("National Cogen"), in connection with the sale of substantially all of
Interpro's assets to National Cogen, which notice was acknowledged by PG&E on
October 27, 1989; and

     WHEREAS, on February 16, 1990, Seller assumed all the rights and
obligations under the agreement in connection with the sale of substantially all
of National Cogen's assets to Seller; and

     WHEREAS, on September 26, 1990, PG&E was notified by National Cogen of the
assignment of the Agreement from National Cogen to Seller; and

     WHEREAS, on December 10, 1990, National Cogen executed a formal written
assignment of the Agreement to Seller, and

     WHEREAS, on December ___, 1990. PG&E consented in writing to the assignment
of the Agreement from National Cogen to Seller, and

     WHEREAS, PG&E and Seller wish to amend the Agreement to change certain%
provisions,

     NOW, THEREFORE, in consideration of the mutual promises and covenants
contained herein, PG&E and Seller agree as follows:

     1. All underlined terms used herein shall have the meanings ascribed to
them in APPENDIX A, Section A-1 DEFINITIONS, of the Agreement.


                                       1




     2. In the space indicated in Article 2, Section (a), page 4, line 5,
insert:

          "115 kV"

     3. Article 2, Section (c), page 4, lines 16-17 shall read:

          The scheduled operation date of the Facility is December 1, 1990.

     4. In the space indicated in Article 2, Section (d), page 5, line 2,
insert:

          "10,750 kW"

5. In the space indicated in Article 2, Section (f), page 5, line 8, insert:

          "December 1, 1990"

6. Article 3, Section (a), page 6, shall read:

          PG&E shall pay Seller for firm capacity at the rate of $201 per
          kW-year under Option 2 set forth in Section C-5 of Appendix C. The
          $201 per kW-year price for firm capacity was negotiated and agreed to
          by PG&E and Seller, and represents a discount from PG&E's full avoided
          costs as approved by the CPUCC. PG&E's obligation to pay for the
          contract capacity shall begin on the actual operation date. The $201
          per kW-year price for firm capacity shall be subject to adjustment as
          provided for in Appendix D.

7. Article 4, pages 6-7, shall read:

          All written notices shall be directed as follows:

          To PG&E:
          Pacific Gas and Electric Company
          Attention: Vice President-Power Generation
          245 Market Street, Room 316
          San Francisco, California 94106

          To Seller.
          7RW Associates, L.P.
          c/o Wellhead  Electric  Company,  Inc.
          1818 11th Street, Suite 4
          Sacramento, California 95814


                                       2



8. Article 7, pages 7-8 shall read:

          This Agreement shall be binding upon execution and remain in effect
          thereafter for 30 years from the actual operation date provided,
          however, that it shall terminate if Seller fails to meet the deadline
          set forth in Paragraph 2 of the Agreement dated______________, or if
          the actual operation date does not occur before April 30, 1991.

9. Article 8 is added to read:

                            ARTICLE 8 - CURTAILMENT

          Each year throughout the term of this Agreement, the Facility will be
          subject to up to 3,000 hours of curtailment during off-peak and
          super-off-peak hours. Off-peak and super-off-peak hours are those time
          periods defined in Appendix B. Table B, as modified or changed from
          time to time by the CPUC. The curtailment specified by this Article
          may be either physical curtailment or economic curtailment or a
          combination of both, as determined by PG&E in the sole exercise of its
          judgement and discretion.

IN WITNESS WHEREOF, the Parties hereto have caused this First Amendment to be
executed by their duly authorized representatives, and it is effective as of the
last date set forth below.


JRW ASSOCIATES, L.P.                            PACIFIC GAS AND ELECTRIC
JRW Cogen, Inc.,                                COMPANY
      General Partner


By:/s/ Harold E. Dittmer                        By: /s/ Robert J. Haywood
   -----------------------                         -----------------------

NAME: Harold E. Dittmer                         NAME: Robert J. Haywood

TITLE: President                                TITLE: Vice President, Power
                                                        Planning & Contracts

DATE: 12-13-90                          DATE: 12-21-90
     -----------------------                  -----------------------




                                       3


                                SECOND AMENDMENT
                                ----------------

THIS SECOND AMENDMENT by and between PACIFIC GAS AND ELECTRIC COMPANY, a
California Corporation ("PG&E") and JRW ASSOCIATES, L.P., a California Limited
Partnership ("TRW") (individually, "Party", and collectively, "Parties"), amends
that cetain Standard Offer 2 Power Purchase Agreement signed by PG&E on December
9, 1985 and by Interpro International, Inc. ("Interpro"). JRW's
predecessor-in-interest, on September 3, 1985 (the "PPA"), for a 10,750 kW
cogeneration project locate A- at J.R. Wood, Inc., 7916 West Bellvue Road,
Atwater, California 953101 (PG&E Log No. 25C045).


                                    RECITALS
                                    --------

A.      The Parties executed that certain Settlement Agreement dated as of
January 14. 1992 (the "Settlement Agreement").

B.      The Settlement Agreement provides, inter alia, that if the Settlement
Agreement is approved by the California Public Utilities Commission (the
"Commission") in accordance with Paragraph 4 of the Settlement Agreement, the
parties shall amend the PPA by executing this Second Amendment

C.      On,May 8.1992, the Settlement Agreement was approved by the Commission
in accordance with Paragraph 4 of the Settlement Agreement.


                                    AGREEMENT
                                    ---------

NOW THEREFORE, in consideration of the above Recitals, and for other good and
valuable consideration, the receipt and adequacy of which are hereby
acknowledged, the Parties hereby agree as follows:




     1.   Defined Terms . Capitalized or underlined terms and conditions used
herein, not otherwise defined herein or in the Settlement Agreement, shall have
the meanings given them in the PPA.

     2.   Amendment of PPA. In accordance with terms and conditions of the
Settlement Agreement, the PPA is hereby amended as follows:

          (a)  Delete Article 3(b) and substitute in its place the following:
               "PG&E shall pay Seller for energy, except for energy delivered
               during periods of economic curtailment, at prices equal to 95
               percent of PG&E's full shortrun avoided operating costs as
               approved by the CPUC."

     3.  General. Except as amended herein and by the First Amendment, and
subject to the provisions of the Settlement Agreement, which remain in full
force and effect, the PPA shall continue in full force and effect.

IN WITNESS WHEREOF, the Parties hereto have caused this Second Amendment to be
executed by their duly authorized representatives, and it is effective as of the
last date set forth below.


JRW ASSOCIATES, L.P.                           PACIFIC GAS AND ELECTRIC
JRW Cogen, Inc.,                               COMPANY
     General Partner


By: /s/ Louis M. Pearce, III                   By: /s/ Robert J. Haywood
    ------------------------                       ---------------------
NAME:  Louis M. Pearce, III                    NAME:  Robert J. Haywood
TITLE: President                               TITLE: Vice President,
                                                      Power Systems


DATE: March 11, 1993                           DATE: March 12, 1993














                            POWER PURCHASE AGREEMENT

                                       FOR

                            FIRM CAPACITY AND ENERGY

                                     BETWEEN

                           INTERPRO INTERNATIONAL INC.

                                       AND

                        PACIFIC GAS AND ELECTRIC COMPANY







                                       1


                            FIRM CAPACITY AND ENERGY

                            POWER PURCHASE AGREEMENT



                                    CONTENTS





   Article                                                              Page
   -------                                                              ----

        1           QUALIFYING STATUS                                    3

        2           PURCHASE OF POWER                                    4

        3           PURCHASE PRICE                                       6

        4           NOTICES                                              6

        5           DESIGNATED SWITCHING CENTER                          7

        6           TERMS AND CONDITIONS                                 7

        7           TERM OF AGREEMENT                                    7



Appendix A:               GENERAL TERMS AND CONDITIONS

Appendix B:               ENERGY PRICES

Appendix C:               FIRM CAPACITY PRICE SCHEDULE

Appendix D:               ADJUSTMENT OF CAPACITY PAYMENTS IN

                          THE EVENT OF TERMINATION OR REDUCTION

Appendix E:               INTERCONNECTION



                                       2


                            FIRM CAPACITY AND ENERGY

                            POWER PURCHASE AGREEMENT

                                     BETWEEN

                           INTERPRO INTERNATIONAL INC.

                                       AND

                        PACIFIC GAS AND ELECTRIC COMPANY




     INTERPRO INTERNATIONAL INC., a Utah corporation ("Seller"), and PACIFIC GAS
AND ELECTRIC COMPANY ("PGandE"), referred to collectively as "Parties" and
individually as "Party", agree as follows:



                           ARTICLE 1 QUALIFYING STATUS

     Seller warrants that, at the date of first power deliveries from Seller's
Facility(1) and during the term of agreement, its Facility shall meet the
qualifying facility requirements established as of the effective date of this
Agreement by the Federal Energy Regulatory Commission's rules (18 Code of
Federal Regulations 292) implementing the Public Utility Regulatory Policies Act
of 1978 (16 U.S.C.A. 796, et seq.).


- ------------------

1    Underlining identifies those terms which are defined in Section A-l of
     Appendix A.

                                       3


                           ARTICLE 2 PURCHASE OF POWER



     (a) Seller shall sell and deliver and PGandE shall purchase and accept
delivery of firm capacity and energy at the voltage level of ________ (1)kV as
indicated below--
               1.   Contract capacity - 8,526 kW; and
               2.   Energy - net energy output (2).

         Seller may convert its energy sale option as provided in section A-3 of
Appendix A.

     (b) Seller shall provide the firm capacity and energy set forth above from
its 10,750 kW Facility located at J. R. Wood Inc., 7916 West Bellvue Road,
Atwater, California 95301.

     (c) The scheduled operation date of the Facility is September 1, 1986. At
the end of each calendar quarter Seller shall give written notice to PGandE of
any change in the scheduled operation date.

     (d) To avoid exceeding the physical limitations of the interconnection
facilities, Seller shall limit the Facility's actual rate of delivery into the
PGandE system to __________ (1)kW.

- ----------

1    The Seller requests, and PGandE consents, that this blank not be filled in
     at the time of executing the Agreement because the Seller, recognizing that
     the information is not yet available to make a definitive determination of
     the number to be inserted in this blank, shall request PGandE to perform an
     interconnection study to be done in its accustomed manner of making such
     studies to determine the number to be inserted.
2    Insert either "net energy oust" or "surplus energy output" to show the
     energy sale option selected by Seller.

                                       4


     (e) The primary energy source for the Facility is natural gas.

     (f) If Seller does not begin construction of its Facility by __________
(2), PGandE may reallocate the [Date] existing capacity on PGandE's transmission
and/or distribution system which would have been used to accommodate Seller's
power deliveries to other uses. In the event of such reallocation, Seller shall
pay PGandE for the cost of any upgrades or additions to PGandE's system
necessary to accommodate the output from the Facility. Such additional
facilities shall be installed, owned, and maintained in accordance with the
applicable PGandE tariff.

     (g) The transformer loss adjustment factor is ________ (3)

- ----------------

1    The appropriate number will be inserted upon completion of an
     interconnection study.

2    Seller shall provide this date in the project development schedule to be
     submitted no later than 30 days after signing the Special Facilities
     Agreement for the Facility.

3    If Seller chooses to have meters placed on Seller's side of the
     transformer, an estimated transformer loss adjustment factor of 2 percent,
     unless the Parties agree otherwise, will be applied. This estimated
     transformer loss figure will be adjusted to a measurement of actual
     transformer losses performed at Seller's request and expense.

                                       5


                            ARTICLE 3 PURCHASE PRICE



     (a) PGandE shall pay Seller for firm capacity at the contract capacity
price under option 2 set forth in Section C-5 of Appendix C. The contract
capacity price is derived from PGandE's full avoided costs as approved by the
CPUC. PGandE's obligation to pay for the contract capacity shall begin on the
actual operation date. Seller elects to have its contract capacity price
determined from the firm capacity price schedule in effect on the date of
execution of this Agreement'. The contract capacity price shall be subject to
adjustment as provided for in Appendix D.

     (b) PGandE shall pay Seller for energy at prices equal to PGandE's full
short run avoided operating costs as approved by the CPUC.

     (c) The contract capacity price is applicable to deliveries of capacity
beginning after December 30,1982.



                                ARTICLE 4 NOTICES



                All written notices shall be directed as follows:

       To PGandE:                Pacific Gas and Electric Company
                                 Attention: Vice President -
                                   Electric Operations
                                 77 Beale Street
                                 San Francisco, CA  94106

- -------------

1    Insert either "the date of execution of this Agreement" or "the actual
     operation date".

                                       6


       To Seller: Interpro International Inc.
                  Attention: Patrick Cassity, President
                  3120 South 1300 East
                  Salt Lake City, Utah  84106
                  (801) 486-4684



                      ARTICLE 5 DESIGNATED SWITCHING CENTER



     The designated PGandE switching center shall be unless changed by PGandE:

                                 Yosemite District Operator
                                 560 West 15th Street, Merced, CA 95341
                                 (209) 723-3841



                         ARTICLE 6 TERMS AND CONDITIONS


     This Agreement includes the following appendices which are attached and
incorporated by reference:

       Appendix A - GENERAL TERMS AND CONDITIONS

       Appendix B - ENERGY PRICES

       Appendix C - FIRM CAPACITY PRICE SCHEDULE

       Appendix D - ADJUSTMENT OF CAPACITY PAYMENTS IN THE

                    EVENT OF TERMINATION OR REDUCTION

       Appendix E - INTERCONNECTION



                           ARTICLE 7 TERM OF AGREEMENT

     This Agreement shall be binding upon execution and remain in effect
thereafter for 30 years from the actual operation date; provided, however, that
it shall terminate if the actual operation date does not occur within five years
of the execution date.

                                       7


     IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be
executed by their duly authorized representatives and effective as of the last
date set forth below.




INTERPRO INTERNATIONAL INC.                 PACIFIC GAS AND ELECTRIC COMPANY



BY: /s/ PATRICK CASSITY                     BY: /s/ HARRY M. HOWE
    -------------------                         -----------------
    PATRICK CASSITY                             HARRY M. HOWE


                                                          Chief -
TITLE: President                            TITLE:   Siting Department



DATE SIGNED: 9-3-85                         DATE SIGNED: 12/9/85



                                       8


                                   APPENDIX A

                          GENERAL TERMS AND CONDITIONS


                                    CONTENTS



Section                                                                   Page
- -------                                                                   ----

A-1       DEFINITIONS                                                     A-2

A-2       CONSTRUCTION                                                    A-6

A-3       ENERGY SALE OPTIONS                                             A-10

A-4       OPERATION                                                       A-12

A-5       PAYMENT                                                         A-16

A-6       ADJUSTMENTS OF PAYMENTS                                         A-17

A-7       ACCESS TO RECORDS AND PGandE DATA                               A-17

A-8       CURTAILMENT OF DELIVERIES AND HYDRO                             A-18
          SPILL CONDITIONS

A-9       FORCE MAJEURE                                                   A-20

A-10      INDEMNITY                                                       A-22

A-ll      LIABILITY; DEDICATION                                           A-23

A-12      SEVERAL OBLIGATIONS                                             A-24

A-13      NON-WAIVER                                                      A-24

A-14      ASSIGNMENT                                                      A-24

A-15      CAPTIONS                                                        A-25

A-16      CHOICE OF LAWS                                                  A-25

A-17      GOVERNMENTAL JURISDICTION AND                                   A-25
          AUTHORIZATION

A-18      NOTICES                                                         A-26

A-19      INSURANCE                                                       A-26

                                      A-1


                                   APPENDIX A

                          GENERAL TERMS AND CONDITIONS



A-1  DEFINITIONS

     Whenever used in this Agreement, appendices, and attachments hereto, the
following terms shall have the following meanings:

     Actual operation date - The day following the day during which all features
and equipment of the Facility are demonstrated to PGandE's satisfaction to be
capable of operating simultaneously to deliver power continuously into PGandE's
system as provided in this Agreement.

     Adjusted capacity price - The $/kW-year purchase price from Table B,
Appendix C for the period of Seller's actual performance.

     Capacity sale reduction - A reduction in the amount of capacity provided or
to be provided under this Agreement, other than a temporary reduction during
probationary periods under Section C-5.

     Contract capacity - That capacity identified in Article 2(a) except as
otherwise changed as provided herein.

                                      A-2


     Contract capacity price - The capacity price applicable for the period from
the actual operation date through the term of agreement from either the firm
capacit price schedule, Table B of Appendix C, or the successor to Table B in
effect on the actual operation date. Seller has indicated its choice of firm
capacity price schedule in Article 3(a).

     Contract termination - The early termination of this Agreement.

     CPUC - The Public Utilities Commission of the State of California.

     Current firm capacity price - The $/kW-year capacity price from the firm
capacity price schedule published by PGandE at the time notice of termination or
reduction of contract capacity is given, for a term equal to the period from the
date of termination or reduction to the end of the term of agreement.

     Designated PGandE switching center - That switching center or other PGandE
installation identified in Article 5.

     Dispatchable - The Facility is operable and can be called upon at any time
to increase its deliveries of capacity to any level up to the contract capacity.

                                      A-3


     Facility - That generation apparatus described in Article 2 and all
associated equipment owned, maintained, and operated by Seller.

     Firm capacity price schedule - The periodically published schedule of the
$/kW-year prices that PGandE offers to pay for capacity. See Table B, Appendix
C.

     Forced outage - Any outage resulting from a design defect, inadequate
construction, operator error or a breakdown of the mechanical or electrical
equipment that fully or partially curtails the electrical output of the
Facility.

     Interconnection facilities - All means required and apparatus installed to
interconnect and deliver power from the Facility to the PGandE system including,
but not limited to, connection, transformation, switching, metering,
communications, and safety equipment, such as equipment required to protect (1)
the PGandE system and its customers from faults occurring at the Facility, and
(2) the Facility from faults occurring on the PGandE system or on the systems of
others to which the PGandE system is directly or indirectly connected.
Interconnection facilities also include any necessary additions and
reinforcements by PGandE to the PGandE system required as a result of the
interconnection of the Facility to the PGandE system.

                                      A-4


     Net energy output - The Facility's gross output in kilowatt-hours less
station use and transformation and transmission losses to the point of delivery
into the PGandE system. Where PGandE agrees that it is impractical to connect
the station use on the generator side of the power purchase meter, PGandE may,
at its option, apply a station load adjustment.

     Prudent electrical practices - Those practices, methods, and equipment, as
changed from time to time, that are commonly used in prudent electrical
engineering and operations to design and operate electric equipment lawfully and
with safety, dependability, efficiency, and economy.

     Scheduled operation date - The day specified in Article 2 (c) when the
Facility is, by Seller's estimate, expected to produce energy and capacity that
will be available for delivery to PGandE.

     Special facilities - Those additions and reinforcements to the PGandE
system which are needed to accommodate the maximum delivery of energy and
capacity from the Facility as provided in this Agreement and those parts of the
interconnection facilities which are owned and maintained by PGandE at Seller's
request, including metering and data processing equipment. All special
facilities shall be owned, operated, and maintained pursuant to PGandE's
electric Rule No. 21, which is attached hereto.

                                      A-5


     Station use - Energy used to operate the Facility's auxiliary equipment.
The auxiliary equipment includes, but is not limited to, forced and induced
draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant
lighting, fuel handling systems, control systems, and sump pumps.

     Surplus energy output - The Facility's gross output, in kilowatt-hours,
less station use, and any other use by Seller, and transformation and
transmission losses to the point of delivery into the PGandE system.

     Term of Agreement - The period of time during which this Agreement will be
in effect as provided in Article 7.

     Voltage level - The voltage at which the Facility interconnects with the
PGandE system, measured at the point of delivery.


A-2  CONSTRUCTION


A-2.1 Land Rights


     Seller hereby grants to PGandE all necessary rights of way and easements,
including adequate and continuing access rights on property of Seller, to

                                      A-6


install, operate, maintain, replace, and remove the special facilities. Seller
agrees to execute such other grants, deeds, or documents as PGandE may require
to enable it to record such rights of way and easements. If any part of PGandE's
equipment is to be installed on property owned by other than Seller, Seller
shall, at its own cost and expense, obtain from the owners thereof all necessary
rights of way and easements, in a form satisfactory to PGandE, for the
construction, operation, maintenance, and replacement of PGandE's equipment upon
such property. If Seller is unable to obtain such rights of way and easements,
Seller shall reimburse PGandE for all costs incurred by PGandE in obtaining
them. PGandE shall at all times have the right of ingress to and egress from the
Facility at all reasonable hours for any purposes reasonably connected with this
Agreement or the exercise of any and all rights secured to PGandE by law or its
tariff schedules.


A-2.2 Design, Construction, ownership, and maintenance


     (a) Seller shall design, construct, install, own, operate, and maintain all
interconnection facilities, except special facilities, to the point of
interconnection with, the PGandE system as required for PGandE to receive firm
capacity and energy from the Facility. The Facility and interconnection
facilities shall meet all requirements of applicable codes and all standards of
prudent electrical  practices and shall be maintained in a safe and prudent

                                      A-7


manner. A description of the interconnection facilities for which Seller is
solely responsible is set forth in Appendix E, or if the interconnection
requirements have not yet been determined at the time of the execution of this
Agreement, the description of such facilities will be appended to this Agreement
at the time such determination is made.

     (b) Seller shall submit to PGandE the design and all specifications for the
interconnection facilities (except special facilities) and, at PGandE's option,
the Facility, for review and written acceptance prior to their release for
construction purposes. PGandE shall notify Seller in writing of the outcome of
PGandE's review of the design and specifications for Seller's interconnection
facilities (and the Facility, if requested) within 30 days of the receipt of the
design and all of the specifications for the interconnection facilities (and the
Facility, if requested). Any flaws perceived by PGandE in the design and
specifications for the interconnection facilities (and the Facility, if
requested) will be described in PGandE's written notification. PGandE's review
and acceptance of the design and specifications shall not be construed as
confirming or endorsing the design and specifications or as warranting their
safety, durability, or reliability. PGandE shall not, by reason of such review
or lack of review, be responsible for strength, details of design, adequacy, or

                                      A-8


capacity of equipment built pursuant to such design and specifications, nor
shall PGandE's acceptance be deemed to be an endorsement of any of such
equipment. Seller shall change the interconnection facilities as may be
reasonably required by PGandE to meet changing requirements of the PGandE
system.

     (c) In the event it is necessary for PGandE to install interconnection
facilities for the purposes of this Agreement, they shall be installed as
special facilities.

     (d) Upon the request of Seller, PGandE shall provide a binding estimate for
the installation of interconnection facilities by PGandE.


A-2.3 Meter Installation


     (a) PGandE shall specify, provide, install, own, operate, and maintain as
special facilities all metering and data processing equipment for the
registration and recording of energy and other related parameters which are
required for the reporting of data to PGandE and for computing the payment due
Seller from PGandE.


     (b) Seller shall provide, construct, install, own, and maintain at Seller's
expense all that is required to accommodate the metering and data processing
equipment, such as, but not limited to, metal-clad switchgear, switchboards,

                                      A-9


cubicles, metering panels, enclosures, conduits, rack structures, and equipment
mounting pads.

     (c) PGandE shall permit meters to be fixed on PGandE's side of the
transformer. If meters are placed on PGandE's side of the transformer, service
will be provided at the available primary voltage and no transformer loss
adjustment will be made. If Seller chooses to have meters placed on Seller's
side of the transformer, an estimated transformer loss adjustment factor of 2
percent, unless the Parties agree otherwise, will be applied.


A-3  ENERGY SALE OPTIONS


A-3.1 General


     Seller has two energy sale options, net energy output or surplus energy
output. Seller has made its initial selection in Article 2(a).


A-3.2 Energy Sale Conversion


     (a) Seller is entitled to convert from one option to the other 12 months
after execution of this Agreement, and thereafter at least 12 months after the
effective date of the most recent conversion, subject to the following
conditions:

                                      A-10


          (1) Seller shall provide PGandE with a written request to convert its
     energy sale option.
          (2) Seller shall comply with all applicable tariffs on file with the
     CPUC and contracts in effect between the Parties at the time of conversion
     covering the existing and proposed (i) facilities used to serve Seller's
     premises and (ii) interconnection facilities.
          (3) Seller shall install and operate equipment required by PGandE to
     prevent PGandE from serving any part of Seller's load which is served by
     the Facility and not under contract for PGandE standby service. At Seller's
     request PGandE shall provide this equipment as special facilities.
          (4) If the energy sale conversion results in a capacity sale
     reduction, the provisions in Appendix D shall apply.

     (b) If, as a result of an energy sales conversion, Seller no longer
requires the use of interconnection facilities installed and/or operated and
maintained by PGandE as special facilities under a special Facilities Agreement,
Seller may reserve these facilities, for its future use, by continuing its
performance under its Special Facilities Agreement. If Seller does not wish to
reserve such facilities, it may terminate its Special Facilities Agreement.

                                      A-11


     If Seller's energy sale conversion results in its discontinuation of its
use of PGandE facilities not covered by Seller's Special Facilities Agreement,
Seller cannot reserve those facilities for future use. Seller's future use of
such facilities shall be contingent upon the availability of such facilities at
the time Seller requests such use. If such facilities are not available, Seller
shall bear the expense necessary to install, own, and maintain the needed
additional facilities in accordance with PGandE's applicable tariff.


     (c) PGandE shall process requests for conversion in the order received. The
effective date of conversion shall depend on the completion of the changes
required to accommodate Seller's energy sale conversion.


A-4  OPERATION


A-4.1 Inspection and Approval


     Seller shall not operate the Facility in parallel with PGandE's system
until an authorized PGandE representative has inspected the interconnection
facilities, and PGandE has given written approval to begin parallel operation.
Seller shall notify PGandE of the Facility's start-up date at least 45 days
prior to such date. PGandE shall inspect the interconnecting facilities within
30 days of the receipt of such notice. If parallel operation is not authorized

                                      A-12


by PGandE, PGandE shall notify Seller in writing within five days after
inspection of the reason authorization for parallel operation was withheld.


A-4.2 Facility Operation and Maintenance

     Seller shall operate and maintain its Facility according to prudent
electrical practices, applicable laws, orders, rules, and tariffs and shall
provide such reactive power support as may be reasonably required by PGandE to
maintain system voltage level and power factor. Seller shall operate the
Facility at the power factors or voltage levels prescribed by PGandE's system
dispatcher or designated representative. If Seller fails to provide reactive
power support, PGandE may do so at Seller's expense.


A-4.3 Point of Delivery


     Seller shall deliver the energy at the point where Seller's electrical
conductors (or those of Seller's agent) contact PGandE's system as it shall
exist whenever the deliveries are being made or at such other point or points as
the Parties may agree in writing. The initial point of delivery of Seller's
power to the PGandE system is set forth in Appendix E.

                                      A-13


A-4.4 Operating Communications


     (a) Seller shall maintain operating communications with the designated
PGandE switching center. The operating communications shall include, but not be
limited to, system paralleling or separation, scheduled and unscheduled
shutdowns, equipment clearances, levels of operating voltage or power factors
and daily capacity and generation reports.

     (b) Seller shall keep a daily operations log for each generating unit which
shall include information on unit availability, maintenance outages, circuit
breaker trip operations requiring a manual reset, and any significant events
related to the operation of the Facility.

     (c) If Seller makes deliveries greater than one megawatt, Seller shall
measure and register on a graphic recording device power in kW and voltage in kV
at a location within the Facility agreed to by both Parties.

     (d) If Seller makes deliveries greater than one and up to and including ten
megawatts, Seller shall report to the designated PGandE switching center, twice
a day at agreed upon times for the current day's operation, the hourly readings
in kW of capacity delivered and the energy in kWh delivered since the last
report.

                                      A-14


     (e) If Seller makes deliveries of greater than ten megawatts, Seller shall
telemeter the delivered capacity and energy information, including real power in
kW, reactive power in kVAR, and energy in kWh to a switching center selected by
PGandE. PGandE may also require Seller to telemeter transmission kW, kVAR, and
kV data depending on the number of generators and transmission configuration.
Seller shall provide and maintain the data circuits required for telemetering.
When telemetering is inoperative, Seller shall report daily the capacity
delivered each hour and the energy delivered each day to the designated PGandE
switching center.

     (f) If Seller provides dispatchable capacity greater than ten megawatts
pursuant to Option 1 in Section C-5 of Appendix C, Seller may be required by
PGandE to provide telemetering and control equipment to allow the Facility to
respond to system load frequency requirements on digital control from PGandE.


A-4.5 Meter Testing and Inspection


     (a) All meters used to provide data for the computation of the payments due
Seller from PGandE shall be sealed, and the seals shall be broken only by PGandE
when the meters are to be inspected, tested, or adjusted.

                                      A-15


     (b) PGandE shall inspect and test all meters upon their installation and
annually thereafter. At Seller's request and expense, PGandE shall inspect or
test a meter more frequently. PGandE shall give reasonable notice to Seller of
the time when any inspection or test shall take place, and Seller may have
representatives present at the test or inspection. If a meter is found to be
inaccurate or defective, PGandE shall adjust, repair, or replace it at its
expense in order to provide accurate metering.


A-4.6 Adjustments to Meter Measurements


     If a meter fails to register, or if the measurement made by a meter during
a test varies by more than two percent from the measurement made by the standard
meter used in the test, an adjustment shall be made correcting all measurements
made by the inaccurate meter for --(1) the actual period during which inaccurate
measurements were made, if the period can be determined, or if not, (2) the
period immediately preceding the test of the meter equal to one-half the time
from the date of the last previous test of the meter, provided that the period
covered by the correction shall not exceed six months.


A-5  PAYMENT


     PGandE shall mail to Seller not later than 30 days after the end of each
monthly billing period (1) a statement showing the capacity and energy delivered

                                      A-16


to PGandE during on-peak, partial-peak, and off-peak periods during the monthly
billing period, (2) PGandE's computation of the amount due Seller, and (3)
PGandE's check in payment of said amount. Except as provided in Section A-6, if
within 30 days of receipt of the statement Seller does not make a report in
writing to PGandE of an error, Seller shall be deemed to have waived any error
in PGandE's statement, computation, and payment, and they shall be considered
correct and complete.


A-6  ADJUSTMENTS OF PAYMENTS


     (a) In the event adjustments to payments are required as a result of
inaccurate meters, PGandE shall use the corrected measurements described in
Section A-4.6 to recompute the amount due from PGandE to Seller for the firm
capacity and energy delivered under this Agreement during the period of
inaccuracy.

     (b) The additional payment to Seller or refund to PGandE shall be made
within 30 days of notification of the owing Party of the amount due.


A-7  ACCESS TO RECORDS AND PGandE DATA


     Each Party, after giving reasonable written notice to the other Party,
shall have the right of access to all  metering and related records including

                                      A-17


operations logs of the Facility. Data filed by PGandE with the CPUC pursuant to
CPUC orders governing the purchase of power from qualifying facilities shall be
provided to Seller upon request; provided that Seller shall reimburse PGandE for
the costs it incurs to respond to such request.


A-8  CURTAILMENT OF DELIVERIES AND HYDRO SPILL CONDITIONS


     (a) PGandE shall not be obligated to accept or pay for and may require
Seller to interrupt or reduce deliveries of energy (1) when necessary in order
to construct, install, maintain, repair, replace, remove, investigate, or
inspect any of its equipment or any part of its system, or (2) if it determines
that interruption or reduction is necessary because of emergencies, forced
outages, force majeure, or compliance with prudent electrical practices.

     (b) In anticipation of a period of hydro spill conditions, as defined by
the CPUC, PGandE may notify Seller that any purchases of energy from Seller
during such period shall be at hydro savings prices quoted by PGandE. If Seller
delivers energy to PGandE during any such period, Seller shall be paid hydro
savings prices for those deliveries in lieu of prices which would otherwise be
applicable. The hydro savings prices shall be calculated by PGandE using the
following formula:

                                      A-18


                                     AQF - S
                                     ------- X PP
                                       AQF

where:



AQF   =   Energy, in kWh, projected to be available during hydro spill
          conditions from all qualifying facilities under agreements containing
          hydro savings price provisions.
S     =   Potential energy, in kWh, from PGandE hydro facilities which will be
          spilled if all AQF is delivered to PGandE.
PP    =   Prices published by PGandE for purchases during other than hydro
          spill conditions.


     (c) PGandE shall not be obligated to accept or pay for and may require
Seller with a Facility with a nameplate rating of one megawatt or greater to
interrupt or reduce deliveries of energy during periods when purchases under
this Agreement would result in costs greater than those which PGandE would incur
if it did not make such purchases but instead generated an equivalent amount of
energy itself.

     (d) Whenever possible, PGandE shall give Seller reasonable notice of the
possibility that interruption or reduction of deliveries under subsections (a)
or (c), above, may be required. PGandE shall give Seller notice of general
periods when hydro spill conditions are anticipated, and shall give Seller as
much advance notice as practical of any specific hydro spill period and the


                                      A-19


hydro savings price which will be applicable during such period. Before
interrupting or reducing deliveries under subsection (c)., above, and before
invoking hydro savings prices under subsection (b), above, PGandE shall take
reasonable steps to make economy sales of the surplus energy giving rise to the
condition. If such economy sales are made, while the surplus energy condition
exists Seller shall be paid at the economy sales price obtained by PGandE in
lieu of the otherwise applicable prices.

     (e) If Seller is selling net energy output to PGandE and simultaneously
purchasing its electrical needs from PGandE, energy curtailed pursuant to
subsections (b) or (c) above shall not be used by Seller to meet its electrical
needs. When Seller elects not to sell energy to PGandE at the hydro savings
price pursuant to subsection (b) or when PGandE curtails deliveries of energy
pursuant to subsection (c), Seller shall continue to purchase all its electrical
needs from PGandE. If Seller is selling surplus energy output to PGandE,
subsections (b) or (c) shall only apply to the surplus energy output being
delivered to PGandE, and Seller can continue to internally use that generation
it has retained for its own use.


A-9  FORCE MAJEURE


     (a) The term force majeure as used herein means unforeseeable causes, other
than forced outages, beyond the reasonable control of and without the fault or

                                      A-20


negligence of the Party claiming force majeure including, but not limited to,
acts of God, labor disputes, sudden actions of the elements, actions by federal,
state, and municipal agencies, and actions of legislative, judicial, or
regulatory agencies which conflict with the terms of this Agreement.

     (b) If either Party because of force majeure is rendered wholly or partly
unable to perform its obligations under this Agreement, that Party shall be
excused from whatever performance is affected by the force majeure to the extent
so affected provided that:


          (1) the non-performing Party, within two weeks after the occurrence of
     the force majeure, gives the other Party written notice describing the
     particulars of the occurrence,
          (2) the suspension of performance is of no greater scope and of no
     longer duration than is required by the force majeure,
          (3) the non-performing Party uses its best efforts to remedy its
     inability to perform (this subsection shall not require the settlement of
     any strike, walkout, lockout or other labor dispute on terms which, in the
     sole judgment of the Party involved in the dispute, are contrary to its
     interest. It is understood and agreed that the settlement of strikes,
     walkouts, lockouts or other labor disputes shall be at the sole discretion
     of the Party having the difficulty),

                                      A-21


          (4) when the non-performing Party is able to resume performance of its
     obligations under this Agreement, that Party shall give the other Party
     written notice to that effect, and
          (5) capacity payments during such periods of force majeure on Seller's
     part shall be governed by Section C-2(c) of Appendix C.


     (c) In the event a Party is unable to perform due to legislative, judicial,
or regulatory agency action, this Agreement shall be renegotiated to comply with
the legal change which caused the non-performance.


A-10 INDEMNITY


     Each Party as indemnitor shall save harmless and indemnify the other Party
and the directors, officers, and employees of such other Party against and from
any and all loss and liability for injuries to persons including employees of
either Party, and property damages including property of either Party resulting
from or arising out of (1) the engineering, design, construction, maintenance,
or operation of, or (2) the making of replacements, additions, or betterments
to, the indemnitor's facilities. This indemnity and save harmless provision
shall apply notwithstanding the active or passive negligence of the indemnitee.

                                      A-22


Neither Party shall be indemnified hereunder for its liability or loss resulting
from its sole negligence or willful misconduct. The indemnitor shall, on the
other Party's request, defend any suit asserting a claim covered by this
indemnity and shall pay all costs, including reasonable attorney fees, that may
be incurred by the other Party in enforcing this indemnity.


     A-11 LIABILITY; DEDICATION


     (a) Nothing in this Agreement shall create any duty to, any standard of
care with reference to, or any liability to any person not a Party to it.
Neither Party shall be liable to the other Party for consequential damages.

     (b) Each Party shall be responsible for protecting its facilities from
possible damage by reason of electrical disturbances or faults caused by the
operation, faulty operation, or nonoperation of the other Party's facilities,
and such other Party shall not be liable for any such damages so caused.

     (c) No undertaking by one Party to the other under any provision of this
Agreement shall constitute the dedication of that Party's system or any portion
thereof to the other Party or to the public or affect the status of PGandE as an
independent public utility corporation or Seller as an independent individual or
entity and not a public utility.

                                      A-23


A-12 SEVERAL OBLIGATIONS

     Except where specifically stated in this Agreement to be otherwise, the
duties, obligations, and liabilities of the Parties are intended to be several
and not joint or collective. Nothing contained in this Agreement shall ever be
construed to create an association, trust, partnership, or joint venture or
impose a trust or partnership duty, obligation, or liability on or with regard
to either Party. Each Party shall be liable individually and severally for its
own obligations under this Agreement.


A-13 NON-WAIVER


     Failure to enforce any right or obligation by either Party with respect to
any matter arising in connection with this Agreement shall not constitute a
waiver as to that matter or any other matter.


A-14 ASSIGNMENT


     Neither Party shall voluntarily assign its rights nor delegate its duties
under this Agreement, or any part of such rights or duties, without the written
consent of the other Party, except in connection with the sale or merger of a

                                      A-24


substantial portion of its properties. Any such assignment or delegation made
without such written consent shall be null and void. Consent for assignment
shall not be withheld unreasonably. Such assignment shall include, unless
otherwise specified therein, all of Seller's rights to any refunds which might
become due under this Agreement.


A-15 CAPTIONS


     All indexes, titles, subject headings, section titles, and similar items
are provided for the purpose of reference and convenience and are not intended
to affect the meaning of the contents or scope of this Agreement.


A-15 CHOICE OF LAWS


     This Agreement shall be interpreted in accordance with the laws of the
State of California, excluding any choice of law rules which may direct the
application of the laws of another jurisdiction.


A-17 GOVERNMENTAL JURISDICTION AND AUTHORIZATION


     Seller shall obtain any governmental authorizations and permits required
for the construction and operation of the Facility. Seller shall reimburse
PGandE for any and all losses, damages, claims, penalties, or liability it

                                      A-25


incurs as a result of Seller's failure to obtain or maintain such authorizations
and permits.


A-18 NOTICES

     Any notice, demand, or request required or permitted to be given by either
Party to the other, and any instrument required or permitted to be tendered or
delivered by either Party to the other, shall be in writing (except as provided
in Section C-3) and so given, tendered, or delivered, as the case may be, by
depositing the same in any United States Post Office with postage prepaid for
transmission by certified mail, return receipt requested, addressed to the
Party, or personally delivered to the Party, at the address in Article 4 of this
Agreement. Changes in such designation may be made by notice similarly given.


A-19 INSURANCE


A-19.1 General Liability Coverage


     (a) Seller shall maintain during the performance hereof, General Liability
Insurance(1) of not less than $1,000,000 if the Facility is over 100 kW,

- -----------------------

1    Governmental agencies which have an established record of self- insurance
     may provide the required coverage through self-insurance.

                                      A-26


$500,000 if the Facility is over 20 kW to 100 kW, and $100,000 if the Facility
is 20 kW or below of combined single limit or equivalent for bodily injury,
personal injury, and property damage as the result of any one occurrence.

     (b) General Liability Insurance shall include coverage for
Premises-Operations, Owners and Contractors Protective, Products/Completed
Operations Hazard, Explosion, Collapse, Underground, Contractual Liability, and
Broad Form Property Damage including Completed Operations.

     (c) Such insurance, by endorsement to the policy(ies), shall include PGandE
as an additional insured if the Facility is over 100 kw insofar as work
performed by Seller for PGandE is concerned, shall contain a severability of
interest clause, shall provide that PGandE shall not by reason of its inclusion
as an additional insured incur liability to the insurance carrier for payment of
premium for such insurance, and shall provide for 30-days' written notice to
PGandE prior to cancellation, termination, alteration, or material change of
such insurance.


A-19.2 Additional Insurance Provisions


     (a) Evidence of coverage described above in Section A-19.1 shall state that
coverage provided is primary and is not excess to or contributing with any
insurance or self-insurance maintained by PGandE.

                                      A-27


     (b) PGandE shall have the right to inspect or obtain a copy of the original
policy(ies) of insurance.

     (c) Seller shall furnish the required certificates(1) and endorsements to
PGandE prior to commencing operation.

     (d) All insurance certificates(1), endorsements, cancellations,
terminations, alterations, and material changes of such insurance shall be
issued and submitted to the following:



        PACIFIC GAS AND ELECTRIC COMPANY
        Attention: Manager - Insurance Department
        77   Beale Street, Room E280
        San Francisco, CA  94106



- ----------------------

1    A governmental agency qualifying to maintain self-insurance should provide
     a statement of self-insurance.

                                      A-28


                                   APPENDIX B

                                  ENERGY PRICES
                                     TABLE A
               Energy Prices Effective August 1 - October 31, 1985

  The energy purchase price calculations which will apply to energy deliveries
   determined from meter readings taken during August, September, and October
                              1985 are as follows:



                                (a)                 (b)                (c)                         (d)
                                                               Revenue Requirement           Energy Purchase
                           Incremental                               for Cash                    Price(4)
     Time Period          Energy Rate(1)     Cost of Energy(2)   Working Capital(3)       (d)=[(a) x (b)] + (c)
     -----------          --------------     -----------------   -----------------       ---------------------
                            (Btu/KWh)          ($/10(6) Btu)         ($/KWh)                   ($/KWh)
                                                                                    
August 1 - September 30
  (Period A)

  Time of
  Delivery Basis:

     On-Peak                  12,168             5.2445               0.00041                   0.06423
     Partial-Peak             11,369             5.2445               0.00038                   0.06000
     Off-Peak                  9,429             5.2445               0.00033                   0.04978

  Seasonal Average            10,515             5.2445               0.00036                   0.05551
     (Period A)

October 1 - October 31
    (Period 8)

  Time of
  Delivery Basis:

    On-Peak                   14,224             5.2445               0.00053                   0.07513
    Partial-Peak              13,552             5.2445               0.00051                   0.07158
    Off-Peak                  10,261             5.2445               0.00038                   0.05419

  Seasonal Average            11,954             5.2445               0.00045                   0 06314
    (Period B)


- --------------------



1    Incremental energy rates (Btu/kwh) for Seasonal Period A and Seasonal
     Period B are derived from the marginal energy costs (including variable
     operating and maintenance expense) adopted by the CPUC in Decision No.
     83-12-068 (page 339). They are based upon natural gas as the incremental
     fuel and weighted average hydroelectric power conditions.

2    Cost of natural gas under PGandE Gas Schedule No. G-55 effective on August
     1, 1985.

3    Revenue Requirement for Cash Working Capital as prescribed by the CPUC in
     Decision No. 83-12-068.

4    Energy Purchase Price = (Incremental Energy Rate x Cost of Energy) +
     Revenue Requirement for Cash Working Capital. The energy purchase price
     excludes the applicable energy line loss adjustment factors. However, as
     ordered by Ordering Paragraph No. 12 (j) of CPUC Decision No. 82-12-120,
     this figure is currently 1.0 for transmission and primary distribution loss
     adjustments and is equal to marginal cost line loss adjustment factors for
     the secondary distribution voltage level. These factors may be changed by
     the CPUC in the future. The currently applicable energy loss adjustment
     factors are shown in Table C.

                                      B-1


                                   TABLE B(1)
                                  Time Periods



                                                     Monday
                                                     through                                  Sundays
                                                    Friday(2)            Saturdays(2)       and Holidays
                                                    ---------            ------------       ------------
                                                                   
      Seasonal Period A
(May 1 through September 30)

           On-Peak                                   12:30    p.m.
                                                           to
                                                      6:30    p.m.

           Partial-Peak                               8:30    a.m.       8:30    a.m.
                                                           to                 to
                                                     12:30    p.m.      10:30    p.m.

                                                      6:30    p.m.
                                                           to
                                                     10:30    p.m.

          Off-Peak                                   10:30    p.m.      10:30    p.m.           All Day
                                                           to                 to
                                                      8:30    a.m.       8:30    a.m.

      Seasonal Period B
(October 1 through April 30)

          On-Peak                                     4:30   p.m.
                                                           to
                                                      8:30   p.m.

          Partial-Peak                                8:30   p.m.        8:30    a.m.
                                                           to                to
                                                     10:30   p.m.       10:30    p.m.

                                                      8:30   a.m.
                                                          to
                                                      4:30   p.m.

          Off-Peak                                   10:30   p.m.       10:30    p.m.           All Day
                                                          to                 to
                                                      8:30   a.m.        8:30    a.m.




1    This table is subject to change to accord with the on-peak, partial-peak,
     and off-peak periods as defined in PGandE's own rate schedules for the sale
     of electricity to its large industrial customers.
2    Except the following holidays: New Year's Day, Washington's Birthday,
     Memorial Day, Independence Day, Labor Day, Veteran's Day, Thanksgiving Day,
     and Christmas Day, as specified in Public Law 90-363 (5 U.S.C.A. Section
     6103 (a)).

                                      B-2


                                     TABLE C

                        Energy Loss Adjustment Factors(l)




                                                           Primary         Secondary
                                        Transmission    Distribution     Distribution
                                        ------------    ------------     ------------
                                                                   
Seasonal Period A
    (May 1 through September 30)

       On-Peak                              1.0             1.0             1.0148
       Partial-Peak                         1.0             1.0             1.0131
       Off-Peak                             1.0             1.0             1.0093

Seasonal Period B
   (October 1 through April 30)

       On-Peak                              1.0             1.0             1.0128
       Partial-Peak                         1.0             1.0             1.0119
       Off-Peak                             1.0             1.0             1.0087




- --------------------------

1    The applicable energy loss adjustment factors may be revised pursuant to
     orders of the CPUC.

                                      B-3


                                   APPENDIX C

                          FIRM CAPACITY PRICE SCHEDULE


                                    CONTENTS


Section                                                              Page
- -------                                                              ----

  C-1      GENERAL                                                    C-2

  C-2      PERFORMANCE REQUIREMENTS                                   C-2

  C-3      SCHEDULED MAINTENANCE                                      C-5

  C-4      ADJUSTMENTS TO CONTRACT CAPACITY                           C-6

  C-5      PAYMENT OPTIONS                                            C-7

  C-6      DETERMINATION OF NATURAL FLOW DATA                         C-15

  C-7      THEORETICAL OPERATION STUDY                                C-16

  C-8      DETERMINATION OF AVERAGE DRY                               C-17
           YEAR CAPACITY RATINGS

  C-9      INFORMATION REQUIREMENTS                                   C-18

  C-10     ILLUSTRATIVE EXAMPLE                                       C-19






                                      C-1


                                   APPENDIX C

                          FIRM CAPACITY PRICE SCHEDULE


C-1  GENERAL


     This Appendix C establishes conditions and prices under which PGandE shall
pay for firm capacity.


C-2  PERFORMANCE REQUIREMENTS


     (a) To receive full capacity payments the Facility must meet the following
requirements:

          (1) The contract capacity shall be available(1) for all of the on-peak
     hours(2) in the peak months on the PGandE system, which are presently the
     months of June, July, and August, subject to a 20 percent allowance for
     forced outages in any month. Compliance with this provision shall be based
     on the Facility's total on-peak availability(1) for each of the peak months
     and shall exclude any energy associated with generation levels greater than
     the contract capacity.

- ----------------

1    For purposes of Option I, "available" means either dispatchable by PGandE
     or actually delivered to PGandE_ For purposes of Option 2, "available"
     means actually delivered to PGandE.

2    On-peak, partial-peak, and off-peak hours are defined in Table B, Appendix
     B.

                                      C-2


          (2) If Seller selects Option 1, the contract capacity shall be
     dispatchable throughout the year, subject to (i) a monthly allowance for
     forced outages of 20% of the hours Seller is called upon to deliver power
     to PGandE and (ii) the allowances for scheduled maintenance outages. Except
     during the peak months on the PGandE system, Seller may accumulate and
     apply the 20 percent allowance for forced outages for any consecutive three
     month period. Seller shall demonstrate that the Facility is fueled by a
     reliable fuel supply and adequate fuel storage is available to deliver
     power as requested by PGandE's system dispatcher. Such demonstration could
     reasonably include documentation of the current availability of the fuel,
     identification of the source, and production of contracts for its purchase
     and supply.

     (b) If Seller is prevented from meeting the performance requirements
because of a forced outage on the PGandE system or a condition set forth in
Section A-8, PGandE shall continue capacity payments. Under Option 2, capacity
payments will be calculated in the same manner used for scheduled maintenance
outages.

     (c) If Seller is prevented from meeting the performance requirements
because of force majeure, PGandE shall continue capacity payments for ninety
days from the occurrence of the force majeure. Thereafter, Seller shall be

                                      C-3


deemed to have failed to have met the performance requirements. Under Option 2,
capacity payments will be calculated in the same manner used for scheduled
maintenance outages.


     (d) If Seller is prevented from meeting the performance requirements
because of exteme dry year conditions, PGandE shall continue capacity payments.
Extreme dry year conditions are drier than those used to' establish contract
capacity pursuant to Section C-8. Seller shall warrant to PGandE that the
Facility is a hydroelectric facility and that such conditions are the sole cause
of Seller's inability to meet its contract capacity obligations. Under Option 1,
starting with the month in which Seller cannot provide its contract capacity,
payments shall .be made under Option 2 for a one-year period, and if at the end
of this one-year period Seller is not able to resume the contract capacity due
solely to continued extreme dry year conditions, Seller shall continue to
receive payments under Option 2 for additional one-year periods as long as such
conditions continue to exist.

     (e) If Seller is prevented from meeting the performance requirements for
reasons other than those described above in Sections C-2(b), (c), or (d):
          (1) Seller shall receive the reduced capacity payments as provided in
     Section C-5 for a probationary period not to exceed15 months, or as
     otherwise agreed to by the Parties.

                                      C-4


          (2) If, at the end of the probationary period Seller has not
     demonstrated that the Facility can meet the performance requirements,
     PGandE may derate the contract capacity pursuant to Section C-4(b).


C-3  SCHEDULED MAINTENANCE


     Outage periods for scheduled maintenance shall not exceed 840 hours (35
days) in any 12-month period. This allowance may be used in increments of an
hour or longer on a consecutive or nonconsecutive basis. Seller may accumulate
unused maintenance hours from one 12-month period to another up to a maximum of
1,080 hours (45 days). This accrued time must be used consecutively and only for
major overhauls. Seller shall provide PGandE with the following advance notices:
24 hours for scheduled outages less than one day, one week for a scheduled
outage of one day or more (except for major overhauls), and six months for a
major overhaul. Seller shall not schedule major overhauls during the peak months
(presently June, July and August). Seller shall make reasonable efforts to
schedule or reschedule routine maintenance outside the peak months, and in no
event shall outages for scheduled maintenance exceed 30 peak hours during the
peak months. Seller shall confirm in writing to PGandE pursuant to Article 4,
within 24 hours of the original notice, all notices Seller gives personally or
by telephone for scheduled maintenance.

                                      C-5


C-4  ADJUSTMENTS TO CONTRACT CAPACITY


     (a) Seller may increase the contract capacity with the approval of PGandE
and receive payment for the additional capacity thereafter in accordance with
the applicable capacity purchase price published by PGandE at the time the
increase is first delivered to PGandE.

     (b) Seller may reduce the contract capacity at any time by giving notice
thereof to PGandE, subject to the provisions of Appendix D if the reduction
occurs after the actual operation date. PGandE may reduce the contract capacity
in accordance with Section C-2(e) as a result of appropriate data showing Seller
has failed to meet the performance requirements of Section C-2. The amount by
which the contract capacity is reduced by PGandE shall be deemed a capacity sale
reduction without notice as provided in Section D-3 of Appendix D.

     (c) Either Party may request, when it reasonably appears that the capacity
of the Facility may have changed for any reason, that a new contract capacity be
determined.

                                      C-6


C-5  PAYMENT OPTIONS

     Seller has two options for calculation of capacity payments and Seller has
made its selection in Article 3(a). As used below in this section, month refers
to a calendar month. The two options are as follows:


                                    Option 1


     When Seller meets the requirements of Section C-2 the monthly payment for
capacity will be one-twelfth of the product of the contract cam price, the
contract capacity, the appropriate capacity loss adjustment factor from Table A
based on the Facility's interconnection voltage, and the appropriate performance
bonus factor, if any, from Table C. Capacity payments will continue during
scheduled maintenance outages provided that the provisions of Section C-3 are
met.

     During a probationary period Seller's monthly payment for capacity shall be
determined by substituting for the contract capacity, the capacity at which
Seller would have met the performance requirements. In any month during the
probationary period that Seller does not meet the performance requirements at
whatever capacity was determined for the previous month, Seller's monthly
payment for capacity shall be determined by substituting the capacity at which
Seller would have met the performance requirements.

                                      C-7


The performance bonus factor shall not be applied during a probationary period.


                                    Option 2


     The monthly payment for capacity will be the product of the Period Price
Factor (PPF), the Monthly Delivered Capacity (MDC), the appropriate capacity
loss adjustment factor from Table A based on the Facility's interconnection
voltage, and the appropriate performance bonus factor, if any, from Table C,
plus any allowable payment for outages due to scheduled maintenance. Firm
capacity prices shall be applied to meter readings taken during the separate
times and periods as illustrated in Table B, Appendix B.

     The PPF is determined by multiplying the contract capacity price by the
following Option 2 Allocation Factors(1):

                              Option 2      x    Contract      =      PPF
                        Allocation Factor     Capacity Price      ($/kW-month)
                                              --------------
Seasonal
Period A                     .18540
                                              --------------      ------------
Seasonal
Period B                     .01043
                                              --------------      ------------


- ---------------

1    These allocation factors were prescribed by the CPUC in Decision No.
     83-12-068. All allocation factors are subject to change by PGandE based on
     PGandE's marginal capacity cost allocation, as determined in general rate
     case proceedings before the CPUC. Seasonal Periods A and B are defined in
     Table B. Appendix B.

                                      C-8


The MDC is determined in the following manner:

     (1) Determine the Performance Factor (P), which is defined as the lesser of
1.0 or the following quantity:

                                     A                  (< or = 1.0)
                        P = --------------------
                            C x  (B-S) x  (0.8*)


Where:

A     =   Total kilowatt-hours delivered during all on-peak and partial-peak
          hours excluding any energy associated with generation levels greater
          than the contract capacity.
C     =   Contract capacity in kilowatts.
B     =   Total on-peak and partial-peak hours during the month.
S     =   Total on-peak and partial-peak hours during the month Facility is
          out of service on scheduled maintenance.


(2)  Determine the Monthly Capacity Factor (MCF which is computed using the
     following expression:

                                     M
                    MCF = P x (1.0 - -)
                                     D

Where:

M     =   The number of hours during the month Facility is out of service on
          scheduled maintenance.
D     =   The number of hours in the month.

- ---------------------

* 0.8 reflects a 20% allowance for forced outage.

                                      C-9


     (3)  Determine the MDC by multiplying the MCF by C:

                    MDC  (kilowatts) = MCF x C

     The monthly payment for capacity is then determined by multiplying the PPF
by the MDC, by the appropriate capacity loss adjustment factor presented from
Table A, and by the appropriate performance bonus factor, if any, from Table C.


monthly payment   =   PPF   x   MDC   x     capacity loss     x  performance
for capacity                              adjustment factor      bonus factor


     Furthermore, the payment for a month in which there is an outage for
scheduled maintenance shall also include an amount equal to the product of the
average hourly capacity payment(1) for the most recent month in the same type of
Seasonal Period (i.e., Seasonal Period A or Seasonal Period B) during which
deliveries were made times the number of hours of outage for scheduled
maintenance in the current month. Capacity payments will continue during the
outage periods for scheduled maintenance provided that the provisions of section
C-3 are met.

     During a probationary period Seller's monthly payment for capacity shall be
determined by substituting for the contract capacity, the capacity at which


- -------------------

1    Total monthly payment divided by the total number of hours in the monthly
     billing period.

                                      C-10


Seller would have met the performance requirements. In the event that during the
probationary period Seller does not meet the performance requirements at
whatever capacity was established for the previous month, Seller's monthly
payment for capacity shall be determined by substituting the capacity at which
Seller would have met the performance requirements. The performance bonus factor
shall not be applied during probationary periods.


                                     TABLE A


If the Facility is non-remote(1) the capacity loss adjustment factors are as
follows:


                                                               Capacity Loss
Interconnection Voltage                                      Adjustment Factor
- -----------------------                                      -----------------

Transmission                                                        .989

Primary Distribution                                                .991

Secondary Distribution                                              .991


If the Facility is remote the capacity loss adjustment
factor is ________________ (2)

- ----------------

1    As defined by the CFUC.

2    The Seller acknowledges that this blank cannot be filled in at the time of
     executing the Agreement because the information is not yet available to
     make a definitive determination of whether the Facility is remote or
     non-remote and, if remote, the number to be inserted in this blank. Seller
     shall request PGandE to perform a capacity loss adjustment factor study to
     be done in its accustomed manner of making such studies to determine
     whether the Facility is remote or non-remote and, if remote, the number to
     be inserted. If the Facility is determined to be non-remote, "N/A" shall be
     inserted.

                                      C-11


                                     TABLE B

                          Firm Capacity Price Schedule
                          ----------------------------

                             (Levelized $/kW-year)



 Actual
Operation
  Date                                                 Term of Agreement
  ----                                                 -----------------

Year          1     2     3     4     5     6     7     8     9    10    11    12    13    14    15    20    25    30
- ----          -     -     -     -     -     -     -     -     -    --    --    --    --    --    --    --    --    --
                                                            
1983         72   111    96    88    84    85    88    91    93    96    98   100   102   104   106   115   122   128
1984        156   111    95    88    89    92    95    98   100   103   105   108   110   112   114   124   131   137

1985         60    58    59    66    73    79    84    88    92    95    99   102   104   107   110   120   129   135
1986         56    58    69    78    85    90    95    99   103   106   110   113   116   118   121   132   141   148

1987         61    77    88    95   10.1  105   109   113   117   120   124   127   130   132   135   147   156   163
1988         96   104   110   114   119   122   126   129   133   136   139   142   145   148   151   163   173   180





                                      C-12


                                     TABLE C


                            Performance Bonus Factor

     The following shall be the performance bonus factors applicable to the
calculation of the monthly payments for capacity delivered by the Facility after
it has demonstrated a capacity factor in excess of 85%.



                     DEMONSTRATED
                    CAPACITY FACTOR               PERFORMANCE
                          (%)                    BONUS FACTOR
                    ------------------------------------------

                           85                        1.000
                           90                        1.059
                           95                        1.118
                          100                        1.176


     After the Facility has delivered power during the span of all of the peak
months on the PGandE system (presently June, July, and August) in any year
(span),

     (1) the capacity factor for each such month shall be calculated in the
following manner:

                                              F
           CAPACITY FACTOR (%)  =  ----------------------- x 100
                                           (N-W) x Q


Where:

                                  For Option 1
                                  ------------



     F =  Total kilowatt-hours delivered by Seller in any peak month
          during all on-peak hours that Seller is asked to deliver power

                                      C-13


          to PGandE excluding any energy associated with generation levels
          greater than the contract capacity.
     N =  Total on-peak hours that Seller is asked to deliver power to PGandE
          during the month.
     W =  Total on-peak hours during the peak month that the Facility is out
          of service on scheduled maintenance during the on-peak hours that
          Seller is asked to deliver power to PGandE.
     Q =  Contract capacity in kilowatts.


                                  For Option 2
                                  ------------



     F =  Total kilowatt-hours delivered by Seller in any peak month during
          all on-peak hours excluding any energy associated with generation
          levels greater than the contract capacity.
     N =  Total on-peak hours during the month.
     W =  Total on-peak hours during the peak month that the Facility is out
          of service on scheduled maintenance.
     Q =  Contract capacity in kilowatts.

     (ii) the arithmetic average of the above capacity factors shall be
determined for that span,

     (iii) the average of the above arithmetic average capacity factors for the
most recent span(s), not to exceed 5, shall be calculated and shall become the
Demonstrated Capacity Factor.

                                      C-14


     To calculate the performance bonus factor for a Demonstrated Capacity
Factor not shown in Table D use the following formula:

Performance Bonus Factor = Demonstrated Capacity Factor (%)
                           --------------------------------
                                         85%


THE FOLLOWING SECTIONS SHALL APPLY ONLY TO HYDROELECTRIC PROJECTS
- -----------------------------------------------------------------


C-6  DETERMINATION OF NATURAL FLOW DATA


     Natural flow data shall be based on a period of record of at least 50 years
and which includes historic critically dry periods. In the event Seller
demonstrates that a natural flow data base of at least 50 years would be
unreasonably burdensome, PGandE shall accept a shorter period of record with a
corresponding reduction in the averaging basis set forth in Section C-8. Seller
shall determine the natural flow data by month by using one of the following
methods:

                                    Method 1

     If stream flow records are available from a recognized gauging station on
the water course being developed in the general vicinity of the project, Seller
may use the data from them directly.

                                      C-15


                                    Method 2

     If directly applicable flow records are not available, Seller may develop
theoretical natural flows based on correlation with available flow data for the
closest adjacent and similar area which has a recognized gauging station using
generally accepted hydrologic estimating methods.


C-7  THEORETICAL OPERATION STUDY


     Based on the monthly natural flow data developed under section C-6 a
theoretical operation study shall be prepared by Seller. Such a study shall
identify the monthly capacity rating in kW and the monthly energy production in
kWh for each month of each year. The study shall take into account all relevant
operating constraints, limitations, and requirements including but not limited
to --
     (1) Release requirements for support of fish life and any other operating
constraints imposed on the project;
     (2) Operating characteristics of the proposed equipment of the Facility
such as efficiencies, minimum and maximum operating levels, project control
procedures, etc.;

                                      C-16


     (3) The design characteristics of project facilities such as head losses in
penstocks, valves, tailwater elevation levels, etc.; and
     (4) Release requirements for purposes other than power generation such as
irrigation, domestic water supply, etc.

     The theoretical operation study for each month shall assume an even
distribution of generation throughout the month unless Seller can demonstrate
that the Facility has water storage characteristics. For the study to show
monthly capacity ratings, the Facility shall be capable of operating during all
on-peak hours in the peak months on the PGandE system, which are presently the
months of June, July, and August. If the project does not have this capability
throughout each such month, the capacity rating in that month of that year shall
be set at zero for purposes of this theoretical operation study.


C-8  DETERMINATION OF AVERAGE DRY YEAR CAPACITY RATINGS


     Based on the results of the theoretical operation study developed under
Section C-7, the average dry year capacity rating shall be established for each
month. The average dry year shall be based on the average of the five years of
the lowest annual generation as shown in the theoretical operation study. Once
such years of lowest annual generation are identified, the monthly capacity
rating is determined for each month by averaging the capacity ratings from each

                                      C-17


month of those years. The contract capacity shown in Article 2(a) shall not
exceed the lowest average dry year monthly capacity ratings for the peak months
on the PGandE system, which are presently the months of June, July, and August.


C-9  INFORMATION REQUIREMENTS


     Seller shall provide the following information to PGandE for its review:
     (1) A summary of the average dry year capacity ratings based on the
theoretical operation study as provided in Table D;
     (2) A topographic project map which shows the location of all aspects of
the Facility and locations of stream gauging stations used to determine natural
flow data;
     (3) A discussion of all major factors relevant to project operation;
     (4) A discussion of the methods and procedures used to. establish the
natural flow data. This discussion shall be in sufficient detail for PGandE to
determine that the methods are consistent with those outlined in Section C-6 and
are consistent with generally accepted engineering practices; and
     (5) Upon specific written request by PGandE, Seller's theoretical operation
study.

                                      C-18


C-10 ILLUSTRATIVE EXAMPLE



     (1) Determine natural flows - These flows are developed based on historic
stream gauging records and are compiled by month, for a long-term period
(normally at least 50 years or more) which covers dry periods which historically
occurred in the 1920's and 30's and more recently in 1976 and 77. In all but
unusual situations this will require application of hydrological engineering
methods to records that are available, primarily from the USGS publication
"Water Resources Data for California".


     (2) Perform theoretical operation study - Using the natural flow data
compiled under (1) above a theoretical operation study is prepared which
determines, for each month of each year, energy generation (kWh) and capacity
rating (kW). This study is performed based on the Facility's design, operating
capabilities, constraints, etc., and should take into account all factors
relevant to project operation. Generally such a study is done by computer which
routes the natural flows through project features, considering additions and
withdrawals from storage, spill past the project, releases for support of fish
life, etc., to determine flow available for generation. Then the generation and
capacity amounts are computed based on equipment performance, efficiencies, etc.

                                      C-19


     (3) Determine average dry year capacity ratings After the theoretical
project operation study is complete the five years in which the annual
generation (kWh) would have been the lowest are identified. Then for each month,
the capacity rating (kW) is averaged for the five years to arrive at a monthly
average capacity rating. The contract capacity is then set by the Seller based
on the monthly average dry year capacity ratings and the performance
requirements of Appendix C. An example project is shown in the attached
completed Table D.










                                      C-20


                                     EXAMPLE
                                     -------


                                     TABLE D

                     Summary of Theoretical Operation Study



Project: New Creek 1                         Dispatchable: Yes ___ No X

Water Source: West Fork New Creek

Mode of Operation: Run of the river

Type of Turbine: Francis        Design Flow:  100 cfs     Design Head: 150 feet

Operating Characteristics(1):


                       Flow       Head (feet)     Output      Efficiency (%)
                      (cfs)      Gross   Net       (kW)     Turbine   Generator
                      -----      -----   ---       ----     -------   ---------

Normal Operation       100        160    150      1,120        90         98
Maximum Operation      110        160    148      1,150        85         98
Minimum Operation       30        160    155        290        75         98


Average Dry Year Operation - Based on the average of the following lowest
generation years: 1930, 1932, 1934, 1949, 1977.


                 Energy Generation    Capacity Output         Percent of
 Month                (kWh)                (kW)          Total Hours Operated(2)
 -----                -----                ----          ----------------------

January              855,000               1,150                  100
February             753,000               1,120                  100
March                818,000               1,100                  100
April                727,000               1,010                  100
May                  699,000                 940                  100
June                 612,000                 850                  100
July                 484,000                 650                  100
August               305,000                 410                  100
September            245,000                 340                  100
October              148,800                 200                  100
November             468,000                 650                  100
December             595,000                 800                  100

Maximum Contract Capacity:   410 kW

- --------------------

1    If Facility has a variable head, operating curves should be provided.

2    For this to be less than 100%, Facility must be dispatchable.

                                      C-21


                                   APPENDIX D

                         ADJUSTMENT OF CAPACITY PAYMENTS
                    IN THE EVENT OF TERMINATION OR REDUCTION


                                    CONTENTS



Section                                                                   Page
- -------                                                                   ----

D-1       GENERAL PROVISIONS                                               D-2

D-2       TERMINATION WITH PRESCRIBED NOTICE                               D-4

D-3       TERMINATION WITHOUT PRESCRIBED NOTICE                            D-5

D-4       TERMINATION EXAMPLES                                             D-6










                                      D-1


                                   APPENDIX D



                         ADJUSTMENT OF CAPACITY PAYMENTS

                    IN THE EVENT OF TERMINATION OR REDUCTION



D-1  GENERAL PROVISIONS



     (a) This Appendix shall be applicable in the event there is a contract
termination or a capacity sale reduction (each sometimes referred to as
"termination" in this Appendix D).

     (b) The Parties agree that the amount which PGandE pays Seller for the
capacity which Seller makes available to PGandE is based on the agreed value to
PGandE of Seller's performance of capacity obligations during the full period of
the term of agreement. The Parties further agree that in the event PGandE does
not receive such full performance by reason of a termination:
          (1) PGandE shall be deemed damaged by reason thereof,
          (2) it would be impracticable or extremely difficult to fix the actual
     damages to PGandE resulting therefrom,
          (3) the refunds and payments as provided in Sections D-2 and D-3, as
     applicable, are in the nature of adjustments in capacity prices and

                                      D-2


     liquidated damages, and not a penalty, and are fair and reasonable, and
          (4) such refunds and payments represent a reasonable endeavor by the
     Parties to estimate a fair compensation for the reasonable losses that
     would result from such termination or reduction.

     (c) In the event of a capacity sale reduction, the quantity by which the
contract capacity is reduced shall be used to calculate the payments due PGandE
in accordance with Sections D-2 and D-3, as applicable.

     (d) Seller shall be invoiced by PGandE for all refunds and payments due
under this Appendix D and the special facilities agreement. From the date of the
notice of termination or the date of termination, whichever is earlier, Seller
shall pay interest, compounded monthly, on all overdue amounts, at the published
Federal Reserve Board three months' Prime Commercial Paper rate.

     (e) If Seller does not make payments pursuant to Section D-1(d), PGandE
shall have the right to offset any amounts due it against any present or future
payments due Seller.

     (f) Notices of termination shall be made in accordance with Section A-l8 of
Appendix A.

                                      D-3


D-2  TERMINATION WITH PRESCRIBED NOTICE


     In the event Seller terminates this entire Agreement, or all or part of the
contract capacity thereof, with the following prescribed written notice:

          Amount of Contract Capacity                        Length of
                 Termiminated                             Notice Required
                 ------------                             ---------------

          1,000 kW or under                                    3  months
          over   1,000 kW through  10,000 kW                   9  months
          over  10,000 kW through  25,000 kW                  12  months
          over  25,000 kW through  50,000 kW                  36  months
          over  50,000 kW through 100,000 kW                  48  months
          over 100,000 kW                                     60  months

Then the following provisions shall apply:
     (1) With respect to the amount by which the contract capacity is reduced,
Seller shall refund to PGandE an amount equal to the difference between (a) the
capacity payments already paid by PGandE, based on the original term of
agreement and (b) the total capacity payments which PGandE would have paid based
on the period of Seller's actual performance using the adjusted capacity price.
Additionally, Seller shall pay interest, compounded monthly, on all
overpayments, at the published Federal Reserve Board three months' Prime
Commercial Paper rate.
     (2) From the date PGandE receives the termination notice to the date of
actual termination, PGandE shall make capacity payments based on the adjusted
capacity price for the amount of contract capacity being terminated.

                                      D-4


     (3) From the date PGandE receives the termination notice, PGandE shall
continue to pay for the amount of contract capacity not being terminated, if
any, at the original contract capacity price.


D-3  TERMINATION WITHOUT PRESCRIBED NOTICE


     (a) If Seller terminates this Agreement, or all or a part of the contract
capacity thereof, without the notice prescribed in Section D-2, the provisions
prescribed in Section D-2 will all apply. Additionally:

     (b) Seller shall pay PGandE a sum equal to the amount by which the contract
capacity is being terminated times the difference between the current firm
capacity price on the date of termination for a term equal to the balance of the
term of agreement and the contract capacity price, pro-rated for the length of
notice given by multiplying by the difference between the prescribed length of
notice and the actual notice given, with the difference divided by 12. In the
event that the current firm capacity price is less than the contract capacity
price, no payment under this Section D-3 shall be due either Party.
     This additional payment shall be computed using the following formula:


                                                 J - H
                            G = CC x (T - CCP) x -----
                                                  12


                                      D-5


Where G >/= 0

and where:

G   =  additional payment.

CC  =  the amount by which the contract capacity is being terminated.

T   =  the current firm capacity price.

CCP =  the contract capacity price.

H   =  the actual number of months notice given.

J   =  the prescribed length of notice.


D-4  TERMINATION EXAMPLES


     These examples demonstrate how to calculate capacity payment adjustments
when capacity sales are terminated.


(a)  Termination with Prescribed Notice
     (1)  Example Based on option 1
          Assumptions:
          i.   Term of agreement is 15 years;
          ii.  Actual operation date is July 1, 1985;
          iii. Prescribed notice is given on July 1, 1.986;

                                      D-6


          iv.  Contract capacity to be reduced by 10,000 kW on July 1, 1987;
               actual performance to be from July 1, 1985 through July 1,
               1987(1);
          v.   The applicable capacity loss adjustment factor is 989; and
          vi.  No performance bonus for capacity has been earned.


          The amount of overpayment (E) made by PGandE to Seller during each
     monthly billing period is calculated as follows:

                                  E = (A - B) x C x L x U

     Where:

     A =  contract capacity price per month for the actual operation date
          (July 1, 1985) and the term of agreement which is 15 years =
          $110/kW-yr / 12mo/yr = $9.17/kW-mo.
     B =  adjusted capacity price per month for the actual operation date
          (July 1, 1984) and a two-year agreement term = $58/kW-yr / 12 mo/yr =
          $4.83/kW-mo.

- ---------------------

1    The capacity payment is adjusted upon receiving notice, so no refund is
     necessary for the last month of the first twelve months of operation and
     all of the second twelve months (June 1, 1986 to July 1, 1987). Seller
     performed for eleven months prior to payment adjustment. (Note that due to
     the 30-day interval between delivery and payment, performance in the
     twelfth month (June 1986) can be paid for at the adjusted capacity price.


                                      D-7


     C =  amount by which the contract capacity- is being reduced = 10,000 kW.
     L =  capacity loss adjustment factor = .989.
     U =  performance bonus factor; when Seller does not qualify for a
          performance bonus factor, as in this example, U is removed from the
          above calculation of E.
     Therefore:
     E =  ($9.17/kW-mo - $4.83/kW-mo) x 10,000 kW x .989 = $42,923 per month.

          Table A shows a step-by-step derivation of the refund Seller owes
     PGandE for the early termination outlined above. The $497,342 that Seller
     owes PGandE appears at the lower right-hand corner of the table. All other
     figures of this table represent intermediate calculation steps.

                                      D-8


                                     TABLE A


  (a)           (b)            (c)           (D)           (E)             (f)                  (g)
  ---           ---            ---           ---           ---             ---                  ---
                                                                        Interest
                             Amount         Accumu-                   Charge(6) on
Monthly                       of            lated                      Accumulated           Balance(7)
Billing      Date of         Over-          Over-       Interest       Overpayment              (g)=
Period(1)    Payment(2)    Payment(3)     Payment(4)     Rate(5)       (f)=(d)x(e)          (c)+(d)+(f)
- ---------    ----------    ----------     ----------     -------       -----------          -----------
                                                                           
                                $             $            %                $                    $
   7/85       8/30/85        42,923             0         1.2                 0               42,923
   8/85       9/30/85        42,923        42,923         1.0               429               86,275
   9/85      10/30/85        42,923        86,275         0.9               776              129,974
  10/85      11/30/85        42,923       129,974         0.8             1,040              173,937
  11/85      12/30/85        42,923       173,937         0.7             1,218              218,078
  12/85       1/30/86        42,923       218,078         0.8             1,745              262,746
   1/86        3/2/86        42,923       262,746         0.9             2,365              308,034
   2/86       3/30/86        42,923       308,034         1.0             3,080              354,037
   3/86       4/30/86        42,923       354,037         1.1             3,894              400,854
   4/86       5/30/86        42,923       400,854         1.2             4,810              448,587
   5/86       6/30/86        42,923       448,587         1.3             5,832              497,342
                                                                                             ========


- -----------------

1    The month in which power deliveries were made. For purposes of
     simplification, the monthly billing period will coincide exactly with each
     calendar month.

2    The date on which payment for the monthly billing period stated in column
     (a) is made.

3    The amount of overpayment made by PGandE to Seller during each monthly
     billing period.

4    The amount of overpayment accumulated up through last month's date of
     payment.

5    The interest rate for the period between the date of payment for the
     previous monthly billing period and the date of payment for this monthly
     billing period. These interest rates are arbitrarily chosen for use in this
     example.

6    the- amount of interest charge accrued between the. date, of) payment for
     the previous monthly billing period and the date of payment for this
     monthly billing period on the accumulated overpayment balance existing as
     of the previous monthly billing period's date of payment.

7    The amount Seller owes PGandE at this stage of the calculation. The balance
     (g) for a given monthly billing period equals the accumulated overpayment
     (d) for the monthly billing period immediately following.

                                      D-9


          (2)  Example Based on Option 2
               Assumptions:
               i.   Term of agreement is 15 years;
               ii.  Actual operation date is April 1, 1985;
               iii. Prescribed notice is given on April 1, 1987;
               iv.  Contract capacity is reduced by 10,000 kW on April 1, 1988;
                    actual performance is from April 1, 1985 through April 1,
                    1988(1);
               v.   Scheduled outage for maintenance: 18 days = 432 hours in
                    both November 1985 and November 1986;
               vi.  The applicable capacity loss adjustment factor is 989; and
               vii. Listed below is Seller's Performance Factor (P), the
                    Demonstrated Capacity Factor (Y) in % (when measured), and
                    where applicable, the performance bonus factor (U) earned
                    for each of the monthly billing periods(2) prior to the time
                    capacity payment is adjusted. Also listed below are the
                    number of hours

- ---------------

1    The capacity payment is adjusted upon receiving notice, so no refund is
     necessary for the last month of the first twenty-four months of operation
     and all of the last twelve months (March 1, 1987 to April 1, 1988). Seller
     performed for twenty-three months prior to payment adjustment. [Note that
     due to the 30-day interval between delivery and payment, performance in the
     twenty-fourth month (March 1987) can be paid for at the adjusted capacity
     price.]

2    For purposes of simplification, the monthly billing period will coincide
     exactly with each calendar month.

                                      D-10


                    the Facility was out of service for scheduled maintenance
                    (M) and the number of hours in the month (D) for each of
                    these months.




Monthly Billing Period                      P             Y          U             M        D
- ----------------------                      -             -          -             -        -
                                                                        
April                     1985             .85            -          -             0      720
May                       1985             .95            -          -             0      744
June                      1985             .90           80          -             0      720
July                      1985            1.00           88          -             0      744
August                    1985             .90           96          -             0      744
September                 1985            1.00            -       1.035*           0      720
October                   1985             .96            -       1.035            0      744
November                  1985             .98            -       1.035          432      720
December                  1985            1.00            -       1.035            0      744
January                   1986            1.00            -       1.035            0      744
February                  1986             .92            -       1.035            0      672
March                     1986             .85            -       1.035            0      744
April                     1986             .78            -       1.035            0      720
May                       1986            1.00            -       1.035            0      744
June                      1986             .94          100       1.035            0      720
July                      1986             .95           95       1.035            0      744
August                    1986            1.00           92       1.035            0      744
September                 1986            1.00            -       1.080**          0      720
October                   1986             .93            -       1.080            0      744
November                  1986             .84            -       1.080          432      720
December                  1986             .88            -       1.080            0      744
January                   1987             .94            -       1.080            0      744
February                  1987            1.00            -       1.080            0      672


- ------------------


*    This performance bonus factor was calculated by averaging the Demonstrated
     Capacity Factors for each of the months of June, July, and August 1985, and
     then dividing that average by 85(%):

                            80 + 88 + 96
                       U =  ------------  / 85  = 1.035
                                 3

**   This performance bonus factor was calculated by averaging the Demonstrated
     Capacity Factors for each. of the months of June, July, and August 1985,
     and June, July, and August 1986, and then dividing that average by 85(%):


                            80 + 88 + 96 + 100 + 95 + 92
                       U =  ----------------------------  / 85 = 1.080
                                           6

                                      D-11


          The amount of overpayment (E) made by PGandE to Seller during each
     monthly billing period is calculated as follows:

                               M                                M
               E  =  [P x (1 - -) x K x L x U x (A - B) x C] + [- x R]
                               D                                D

     Where:
     P =  performance factor.
     M =  number of hours of scheduled maintenance for that monthly billing
          period.
     D =  number of hours in that monthly billing period.
     K =  allocation factor from Section C-5.
     L =  capacity loss adjustment factor = .989.
     U =  performance bonus factor; when Seller does not qualify for a
          performance bonus factor, U is removed from the above calculation of
          E.
     A =  Contract capacity price for the actual operation date (April 1,
          1985) and term of agreement which is 15 years = $110/kW-yr.
     B =  adjusted capacity price for the actual operation date and a
          three-year agreement term = $59/kW-yr.
     C =  amount by which the contract capacity is being reduced = 10,000 kW.

                                      D-12


     R =  amount of overpayment for the most recent monthly billing period in
          the same Seasonal Period (i.e., Seasonal Period A or Seasonal Period
          B).


     The results of the calculations are:

                                                                    Amount of
     Monthly Billing Period                                      Overpayment (E)
     ----------------------                                      ---------------

     April                         1985                          $    4,472
     May                           1985                              88,838
     June                          1985                              84,163
     July                          1985                              93,514
     August                        1985                              84,163
     September                     1985                              96,787
     October                       1985                               5,227
     November                      1985                               5,271
     December                      1985                               5,445
     January                       1986                               5,445
     February                      1986                               5,009
     March                         1986                               4,628
     April                         1986                               4,247
     May                           1986                              96,787
     June                          1986                              90,980
     July                          1986                              91,948
     August                        1986                              96,787
     September                     1986                             100,995
     October                       1986                               5,284
     November                      1986                               5,079
     December                      1986                               5,000
     January                       1987                               5,341
     February                      1987                               5,682


          Table B shows a step-by-step derivation of the refund Seller owes
     PGandE for the early termination outlined above. The $1,136,015 that Seller
     owes PGandE appears at the lower right-hand corner of the table. All other
     figures of this table represent intermediate calculation steps.

                                      D-13




                                     TABLE B

 (a)            (b)            (c)           (d}            (e)             (f)              (g)
 ---            ---            ---           ---            ---             ---              ---
                                                                            Interest
                              Amount        Accumu-                      Charge(6) on
Monthly                         of          lated                         Accumulated     Balance(7)
Billing       Date of          Over-        Over-          Interest       Overpayment        (g)=
Period(1)    Payment(2)     Payment(3)    Payment(4)       Rate(5)        (f)=(d)x(e)    (c)+(d)+(f)
- ---------    ----------     ----------    ----------       -------        -----------    -----------
                                 $             $              %               $               $
                                                                      
 4/85          5/30/85         4,472              0         1.3                 0           4,472
 5/85          6/30/85        88,838          4,472         1.4                63          93,373
 6/85          7/30/85        84,163         93,373         1.3             1,214         178,750
 7/85          8/30/85        93,514        178,750         1.2             2,145         274,409
 8/85          9/30/85        84,163        274,409         1.0             2,744         361,316
 9/85         10/30/85        96,787        361,316         0.9             3,252         461,355
10/85         11/30/85         5,227        461,355         0.8             3,691         470,273
11/85         12/30/85         5,271        470,273         0.7             3,292         478,836
12/85          1/30/86         5,445        478,836         0.8             3,831         488,112
 1/86           3/2/86         5,445        488,112         0.9             4,393         497,950
 2/86          3/30/86         5,009        497,950         1.0             4,980         507,939
 3/86          4/30/86         4,628        507,939         1.1             5,587         518,154
 4/86          5/30/86         4,247        518,154         1.2             6,218         528,619
 5/86          6/30/86        96,787        528,619         1.3             6,872         632,278
 6/86          7/30/86        90,980        632,278         1.4             8,852         732,110
 7/86          8/30/86        91,948        732,110         1.4            10,250         834,308
 8/86          9/30/86        96,787        834,308         1.3            10,846         941,941
 9/86         10/30/86       100,995        941,941         1.2            11,303       1,054,239
10/86         11/30/86         5,284      1,054,239         1.0            10,542       1,070,065
11/86         12/30/86         5,079      1,070,065         1.1            11,771       1,086,915
12/86          1/30/87         5,000      1,086,915         1.1            11,956       1,103,871
 1/87           3/2/87         5,341      1,103,871         1.0            11,039       1,120,251
 2/87          3/30/87         5,682      1,120,251         0.9            10,082       1,136,015
                                                                                        =========


- -------------

1    The month in which power deliveries were made. For purposes of
     simplification, the monthly billing period will coincide exactly with each
     calendar month.
2    The date on which payment for the monthly billing period stated in column
     (a) is made.
3    The amount of overpayment made by PGandE to Seller during each monthly
     billing period.
4    The amount of overpayment accumulated up through last month's date of
     payment.
5    The interest rate for the period between the date of payment for the
     previous monthly billing period and the date of payment for this monthly
     billing period. These interest rates are arbitrarily chosen for use in this
     example.
6    The amount of interest charge accrued between the date of payment for the
     previous monthly billing period and the date of payment for this monthly
     billing period on the accumulated overpayment balance existing as of the
     previous monthly billing period's date of payment.
7    The amount Seller owes PGandE at this stage of the calculation. The balance
     (g) for a given monthly billing period equals the accumulated overpayment
     (d) for the monthly billing period immediately following.

                                      D-14


(b)  Termination without Prescribed Notice
     If Seller terminates without prescribed notice, Seller will owe PGandE a
refund [the calculation of which is described in Sections D-4(a)(1) and
D-4(a)(2) of this example] and payment (G). This example demonstrates how the
payment (G) is calculated. Assumptions:
     i.   Term of agreement is 15 years;
     ii.  Actual operation date is July 1, 1985;
     iii. Notice is given on January 1, 1990; and
     iv.  Contract capacity is to be reduced by 10,000 kW on July 1, 1990;
          actual performance is from July 1, 1985 through July 1, 1990.


     The payment (G) is calculated as follows:

                                  J-H
           G  = CC x (T - CCP) x (---)        G > or = 0
                                   12

     Where:


     CC = The amount of contract capacity being terminated = 10,000 kW.
     T  = the current firm capacity price $140/kW-yr is arbitrarily chosen for
          use in this example for a July 1, 1990 Operation Date and 10-year
          agreement term.
     CCP= the contract capacity price = $110/kW-yr.
     H  = the actual number of months notice given = six months.
     J  = the prescribed notice = twelve months.

                                      D-15


     The sample calculation is.

                            J-H
     G  = CC x (T - CCP) x (---)
                             12


     G  = 10,000 kW x ($140/kW-yr - $110/kW-yr) x

                 22 mos. -  6 mos.
                (-----------------)
                    (12 mos./yr


     G  = $150,000
          ========







                                      D-16


                                   APPENDIX E

                                 INTERCONNECTION


                                    CONTENTS


Section                                                                  Page
- -------                                                                  ----

   E-1               INTERCONNECTION TARIFFS                             E-2

   E-2               POINT OF DELIVERY LOCATION SKETCH                   E-3

   E-3               INTERCONNECTION FACILITIES FOR WHICH                E-4
                     SELLER IS RESPONSIBLE







                                      E-1


E-1  INTERCONNECTION TARIFFS

     The applicable tariff follows on the succeeding pages.
















                                      E-2


Pacific Gas and Electric Company            Revised Cal. P.U.C. Sheet No. 8616-E
   San Francisco. California    Cancelling Original Cal. P.U.C. Sheet No. 7693-E
- --------------------------------------------------------------------------------
               RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION

This describes the minimum operation, metering and interconnection requirements
for any generating source or sources paralleled with the Utility's electric
system. Such source or sources may include, but are not limited to,
hydroelectric generators, wind-turbine generators, steam or gas driven turbine
generators and photovoltaic systems.

A.   GENERAL

     1.   The type of interconnection and voltage available at any location and
          the Utility's specific interconnection requirements shall be
          determined by inquiry at the Utility's local office.

     2.   The Utility's distribution and transmission lines which are an
          integral part of its overall system are distinguished by the voltages
          at which they are operated. Distribution lines are operated at
          voltages below 60 kv and transmission lines are operated at voltages
          60 kv and higher.

     3.   The Power Producer (Producer) shall ascertain and be responsible for
          compliance with the requirements of all governmental authorities
          having jurisdiction.

     4.   The Producer shall sign the Utility's written form of power purchase
          agreement or parallel operation agreement before connecting or
          operating a generating source in parallel with the Utility's system.

     5.   The Producer shall be fully responsible for the costs of designing,
          installing, owning, operating and maintaining all interconnection
          facilities defined in Section B.1.

     6.   The Producer shall submit to the Utility, for the Utility's review and
          written acceptance, equipment specifications and detailed plans for
          the installation of all interconnection facilities to be furnished by
          the Producer prior to their purchase or installation. The Utility's
          review and written acceptance of the Producer's equipment
          specifications and detailed plans shall not be construed as confirming
          or endorsing the Producer's design or as warranting the equipment's
          safety, durability or reliability. The Utility shall not, by reason of
          such review or lack of review, be responsible for strength, details of
          design adequacy, or capacity of equipment built pursuant to such
          specifications, nor shall the Utility acceptance be deemed an
          endorsement of any such equipment.

     7.   No generating source shall be operated in parallel with the Utility's
          system until the interconnection facilities have been inspected by the
          Utility and the Utility has provided written approval to the Producer.

     8.   Only duly authorized employees of the Utility are allowed to connect
          Producer-installed interconnection facilities to, or disconnect the
          same from, the Utility's overhead or underground lines.

B.   INTERCONNECTION FACILITIES

     1.   GENERAL: Interconnection facilities are all means required, and
          apparatus installed, to interconnect the Producer's generation with
          the Utility's system. Where the Producer desires to sell power to the
          Utility, interconnection facilities are also all means required, and
          apparatus installed, to enable the Utility to receive power deliveries
          from the Producer. Interconnection facilities may include, but are not
          limited to:
          a.   connection, transformation, switching, metering, communications,
               control, protective and safety equipment; and
          b.   any necessary additions to and reinforcements of the Utility's
               system by the Utility.

     2.   METERING
          a.   A Producer desiring to sell power to the Utility shall provide,
               install, own and maintain all facilities necessary to accommodate
               metering equipment specified by the Utility. Such metering
               equipment may include meters telemetering (applicable where
               deliveries to the Utility exceed 10 MIW) and other recording and
               communications devices as may be required for the reporting of
               power delivery an to the Utility. Except as provided for in
               Section B.2.b following, the Utility shall provide, install, own
               and maintain all metering equipment as special facilities in
               accordance with Section F.
                                                                     (Continued)
- --------------------------------------------------------------------------------

Advice Letter No.  1025-E                                Date Filed May 21, 1984
Decision No.      83-10-093                              Effective June 20, 1984
                                                         Resolution No.

                                    Issued By
                                 W. M. Gallavan
                                 Vice-President
                          Rates and Economic Analysis

                                     E-2(a)


Pacific Gas and Electric Company            Revised Cal. P.U.C. Sheet No. 8617-E
   San Francisco. California    Cancelling Original Cal. P.U.C. Sheet No. 7694-E
- --------------------------------------------------------------------------------
          RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)

B.   INTERCONNECTION FACILITIES

     2.   METERING

          b.   The Producer may at its option provide, install, own and maintain
               current and potential transformers rated above 600 volts and a
               non-revenue type graphic recorder where applicable. Such metering
               equipment, its installation and maintenance shall all be In
               conformance with the Utility's specifications.

          c.   The Utility's meters shall be equipped with detents to prevent
               reverse registration so that power deliveries to and from the
               Producer's equipment can be separately recorded.

     3.   CONTROL, PROTECTION AND SAFETY EQUIPMENT

          a.   GENERAL: The Utility has established functional requirements
               essential for safe and reliable parallel operation of the
               Producer's generation. These requirements provide for control,
               protective and safety equipment to:
               (1) sense and properly react to failure and malfunction on the
               Utility's system;
               (2) assist the Utility in maintaining its system integrity and
               reliability; and
               (3) protect the safety of the public and the Utility's personnel.

          b.   Listed below are the various devices and features generally
               required by the Utility as a prerequisite to parallel operation
               of the Producer's generation:

         CONTROL. PROTECTION AND SAFETY EQUIPMENT GENERAL REQUIREMENTS(1)
- --------------------------------------------------------------------------------


                                                                                      GENERATOR SIZE
                                                                                      --------------
                                                        10 kw or    11 kw to    41 kw to   101 kW to     401 kw to     Over
                    Device or Feature                     Less       40 kw       100 kw     400 kw       1,000 kw    1,000 kw
                    -----------------                     ----       -----       ------     ------       --------    --------
                                                        
Dedicated Transformer(2)                                    -           X          X           X            X            X
Interconnection Disconnect Device                           X           X          X           X            X            X
Generator Circuit Breaker                                   X           X          X           X            X            X
Over-voltage Protection                                     X           X          X           X            X            X
Under-voltage Protection                                    -           -          X           X            X            X
Under/Over-frequency Protection                             X           X          X           X            X            X
Ground Fault Protection                                     -           -          X           X            X            X
Over-current relay w/Voltage Restraint                      -           -                      -            X            X
Synchronizing(3)                                         Manual     Manual      Manual      Manual       Manual     Automatic
Power Factor or Voltage Regulation                                                 X           X            X            X


          c.   DISCONNECT DEVICE: The producer shall provide, install, own and
               Maintain the interconnection disconnect device required by
               Section 8.3.b at a location readily accessible to the Utility.
               Such device shall normally be located near the Utility's meter or
               meters for sole operation by the Utility. The interconnection
               disconnect device and its precise location shall be specified by
               the Utility. At the Producer's option and request, the Utility
               will provide, Install, own and maintain the disconnect device on
               the Utility's system as special facilities in accordance with
               Section F.


- ------------------

1    Detailed requirements are specified in the Utility's current operating,
     metering and equipment protection publications, as revised from time to
     time by the Utility and available to the Producer upon request. For a
     particular generator application, the Utility will furnish its specific
     control, protective and safety requirements to the Producer after the exact
     location of the generator has been agreed upon and the interconnection
     voltage level has been established.

2    This is a transformer interconnected with no other Producers and serving no
     other Utility customers. Although the dedicated transformer is not a
     requirement for generators rated 10 kw or less, its installation is
     recommended by the Utility.

3    This Is a requirement for synchronous and other types of generators with
     stand-alone capability. For all such generators, the Utility will also
     require the installation of "reclose blocking" features on its system to
     block certain operations of the Utility's automatic line restoration
     equipment.
                                                                     (Continued)
- --------------------------------------------------------------------------------

Advice Letter No.  1025-E                                Date Filed May 21, 1984
Decision No.      83-10-093                              Effective June 20, 1984
                                                         Resolution No.

                                    Issued By
                                 W. M. Gallavan
                                 Vice-President
                          Rates and Economic Analysis

                                    E-2 (b)


Pacific Gas and Electric Company           Original Cal. P.U.C. Sheet No. 8618-E
   San Francisco. California    Cancelling ________ Cal. P.U.C. Sheet No. ______
- --------------------------------------------------------------------------------
          RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)

B.   INTERCONNECTION FACILITIES (continued)

     4.   UTILITY SYSTEM ADDITIONS AND REINFORCEMENTS

          a.   Except as provided for in Section B.5. all additions to and
               reinforcements of the Utility's system necessary to interconnect
               with and receive power deliveries from the Producer's generation
               will be provided, installed, owned and maintained by the Utility
               as special facilities in accordance with Section F. Such
               additions and reinforcements may include the installation of a
               Utility distribution or transmission line extension or the
               increase of capacity in the Utility's existing distribution or
               transmission lines. The Utility shall determine whether any such
               additions or reinforcements shall include an increment of
               additional capacity for the Utility's use in furnishing service
               to its customers. If so, then the costs of providing, installing,
               owning and maintaining such additional capacity shall be Lorne by
               the Utility and/or its customers in accordance with the Utility's
               applicable tariffs on file with and authorized by the California
               Public Utilities Commission (Commission).

          b.   The Producer shall advance to the Utility its estimated costs of
               performing a preliminary or detailed engineering study as may be
               reasonably required to identify any Producer related Utility
               system additions and reinforcements. Where such. preliminary or
               detailed engineering study involves analysis of the Utility's
               transmission lines-(66 kv and higher), the Utility shall complete
               its study within twelve calendar months of receiving all
               necessary plans and specifications from the Producer.

     5.   PRODUCER-INSTALLED UTILITY-OWNED LINE EXTENSIONS: The Producer may at
          its option provide and install an extension of the Utility's
          distribution or transmission lines where required to complete the
          Producer's interconnection with the Utility. Such extension shall be
          installed by contractors approved by the Utility and in accordance
          with its design and specifications. The Producer shall pay the Utility
          its estimated costs of design, administration and inspection as may be
          reasonably required to assure such extension is installed in
          compliance with the Utility's requirements. Upon final inspection and
          acceptance by the Utility, the Producer shall transfer ownership of
          the line extension to the Utility where thereafter it shall be owned
          and maintained as special facilities in accordance with Section F.
          This provision does not preclude the Producer from installing, owning
          and maintaining a distribution or transmission line extension as part
          of its other Producer-owned interconnection facilities.

     6.   COSTS OF FUTURE UTILITY SYSTEM ALTERATIONS; The Producer shall be
          responsible for the costs of only those future Utility system
          alterations which are directly related to the Producer's. presence or
          necessary to maintain the Producer's interconnection in accordance
          with the Utility's applicable operating, metering and equipment
          publication in effect when the Producer and the Utility entered into a
          written form of power purchase agreement. Alterations made at the
          Producer's expense shall specifically exclude increases of existing
          line capacity necessary to accommodate the other Producers or Utility,
          customers. Such alterations may, however, include relocation or
          undergrounding of the Utility's distribution or transmission lines as
          may be ordered by a governmental authority having jurisdiction.

     7.   ALLOCATION OF THE UTILITY'S EXISTING LINE CAPACITY: For two or more
          Producers seeking to use an existing line, a first come, first served
          approach shall be used. The first Producer to request an
          interconnection shall have the right to use the existing line and
          shall incur no obligation for costs associated with future line
          upgrades needed to accommodate other Producers or customers. The
          Utility's power purchase agreement shall specify the date by which the
          Producer must begin construction. If that date passes and construction
          has not commenced, the Producer shall be given 30 days to correct the
          deficiency after receiving a reminder from the Utility that the
          construction start-up date has passed. If construction has not
          commenced after the 30-day corrective period, the Utility shall have
          the right to withdraw its commitment to the first Producer and offer
          the right to interconnect on the existing line to the next Producer in
          order. If two Producers establish the right of first-in-time
          simultaneously, the two Producers shall share the costs of any
          additional line upgrade necessary to facilitate their cumulative
          capacity requirements. Costs shall be shared based on the relative
          proportion of capacity each Producer will add to the line.

                                                                     (Continued)
- --------------------------------------------------------------------------------
Advice Letter No.  1025-E                                Date Filed May 21, 1984
Decision No.      83-10-093                              Effective June 20, 1984
                                                         Resolution No.

                                    Issued By
                                 W. M. Gallavan
                                 Vice-President
                          Rates and Economic Analysis



Pacific Gas and Electric Company            Revised Cal. P.U.C. Sheet No. 8619-E
   San Francisco. California    Cancelling Original Cal. P.U.C. Sheet No. 7695-E
- --------------------------------------------------------------------------------
          RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)

C.   ELECTRIC SERVICE FROM THE UTILITY: If the Producer requires regular,
     supplemental, interruptible or standby service from the Utility, the
     Producer shall enter Into separate contractual arrangements with the
     Utility in accordance with the Utility's applicable electric tariffs on
     file with and authorized by the Commission.

D.   OPERATION

     1.   PREPARALLEL INSPECTION: In accordance with Section A.7, the Utility
          will inspect the Producer's interconnection facilities prior to
          providing it with written authorization to commence parallel
          operation. Such inspection shall determine whether or not the Producer
          has installed certain control, protective and safety equipment to the
          Utility's specifications, Where the Producer's generation has a rated
          output in excess of 100 kw, the Producer shall pay the Utility its
          estimated costs of performing the inspection.

     2.   JURISDICTION OF THE UTILITY'S SYSTEM DISPATCHER: The Producer's
          generation while operating in parallel with the Utility's system is at
          all times under the jurisdiction of the Utility's system dispatcher.
          The system dispatcher shall normally delegate such control to the
          Utility's designated switching center.

     3.   COMMUNICATIONS: The Producer shall maintain telephone service from the
          local telephone company to the location of the Producer's generation.
          In the event such location is remote or unattended, telephone service
          shall be provided to the nearest building normally occupied by the
          Producer's generator operator. The Utility and the Producer shall
          maintain operating communications through the Utility's designated
          switching center.

     4.   GENERATOR LOG: The Producer shall at all times keep and maintain a
          detailed generator operations log. Such log shall include, but not be
          limited to, information on unit availability, maintenance outages,
          circuit breaker trip operations requiring manual reset and unusual
          events. The Utility shall have the right to review the Producer's log.

     5.   REPORTING ABNORMAL CONDITIONS: The Utility shall advise the Producer
          of abnormal conditions which the Utility has reason to believe could
          affect the Utility's operating conditions or procedures. The Producer
          shall keep the Utility similarly informed.

     6.   POWER FACTOR: The Producer shall furnish reactive power as way be
          reasonably required by the Utility.

          a.   The Utility reserves the right to specify that generators with
               power factor control capability, Including synchronous
               generators, be capable of operating continuously at any power
               factor between 95 percent leading (absorbing vars) and 90 percent
               tagging (producing vars) at any voltage level within + or - 5.0
               percent of rated voltage. For other types of generators with no
               inherent power factor control capability, the Utility reserves
               the right to specify the installation of capacitors by the
               Producer to correct generator output to near 95 percent leading
               power factor. The Utility may also require the installation of
               switched capacitors on its system to produce reactive support
               equivalent to that provided by operating a synchronous generator
               of the some size between 95 percent leading and 90 percent
               lagging power factor.
          b.   Where either the Producer or the Utility determines that it Is
               not practical for the Producer to furnish the Utility's required
               level of reactive power or when the Utility specifies switched
               capacitors in its system pursuant to Section D.6.a, the Utility
               will provide, install, own and maintain the necessary devices on
               its system in accordance with Section F.

E.   INTERFERENCE WITH SERVICE AND COMMUNICATION FACILITIES

     1.   CEMERAL: The Utility reserves the right to refuse to connect to any
          new equipment or to remain connected to any existing equipment of a
          size or character that may be detrimental to the Utility's operations
          or service to its customers.

                                                                     (Continued)
- --------------------------------------------------------------------------------
Advice Letter No.  1025-E                                Date Filed May 21, 1984
Decision No.      83-10-093                              Effective June 20, 1984
                                                         Resolution No.

                                    Issued By
                                 W. M. Gallavan
                                 Vice-President
                          Rates and Economic Analysis



Pacific Gas and Electric Company            Revised Cal. P.U.C. Sheet No. 8620-E
   San Francisco. California    Cancelling Original Cal. P.U.C. Sheet No. 7696-E
- --------------------------------------------------------------------------------
          RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)

E.   INTERFERENCE WITH SERVICE AND COMMUNICATION FACILITIES (continued)

     2.   The Producer shall not operate equipment that superimposes upon the
          Utility's system a voltage or current which causes interference with
          the Utility's operations, service to the Utility's customers or
          interference to communication facilities. If the Producer causes
          service interference to others, the Producer must diligently pursue
          and take corrective action at the Producer's expense after being given
          notice and reasonable time to do so by the Utility. If the Producer
          does not take timely corrective action, or continues to operate the
          equipment causing the interference without restriction or limit, the
          Utility may, without liability, disconnect the Producer's equipment
          from the Utility's system until a suitable permanent solution provided
          by the Producer is operational at the Producer's expense.

F.   SPECIAL FACILITIES

     1.   Where the Producer requests the Utility to furnish interconnection
          facilities or where it is necessary to make additions to or
          reinforcements of the Utility's system and the Utility agrees to do
          so, such facilities shall be deemed to be special facilities and the
          costs thereof' shall be borne by the Producer, including such
          continuing ownership costs as may be applicable.

     2.   Special facilities are (a) those facilities installed. at the
          Producer's request which the Utility does not normally furnish under
          its tariff schedules, or (b) a prorate portion of existing facilities
          requested by the Producer, allocated for the sole use of such
          Producer, which would not normally be allocated for such sole use.
          Unless otherwise provided by the Utility's filed tariff schedules,
          special facilities will be installed, owned and maintained or
          allocated by the Utility as an accommodation to the Producer only if
          acceptable for operation by the Utility and the reliability of service
          to the Utility's customers is not impaired.

     3.   Special facilities will be furnished under the terms and conditions of
          the Utility's "Agreement for installation or Allocation of Special
          Facilities for Parallel Operation of Nonutility-owned Generation
          and/or Electrical Standby Service" (Form 79-280, effective June 1984)
          and its Appendix A, "Detail of Special Facilities Charges" (Form
          79-702, effective June 1984). Prior to the Producer signing such an
          agreement, the Utility shall provide the Producer with a breakdown of
          special facilities costs in a form having detail sufficient for the
          information to be reasonably understood by the Producer. The special
          facilities agreement will include, but is not limited to, a binding
          quotation of charges to the Producer and the following general terms
          and conditions:

          a.   Where facilities are installed by the Utility for the Producer's
               use as special facilities, the Producer shall advance to the
               Utility its estimated installed cost of the special facilities.
               The amount advanced is subject to the monthly ownership charge
               applicable to customer-financed special facilities as set forth
               in Section I of the Utility's Rule No. 2.

          b.   At the Producer's option, and where such Producer's generation is
               a qualifying facility and the Producer has established credit
               worthiness to the Utility's satisfaction, the Utility shall
               finance those special facilities it deems to be removable and
               reusable equipment. Such equipment shall include, but not be
               limited to, transformation, disconnection and metering equipment.

          c.   Existing facilities allocated for the Producer's use as special
               facilities and removable and reusable equipment financed by the
               Utility in accordance with Section F.3.b are subject to the
               monthly ownership charge applicable to Utility-financed special
               facilities as set forth in Section 1 of Rule 2.

- --------------------

4    A qualifying facility is one which meets the requirements established by
     the Federal Energy Regulatory Commission's rules (18 Code of Federal
     Regulations 292) implementing the Public Utility Regulatory Policies Act of
     1978 (16 U.S.C.A. 796, et seq.).
- --------------------------------------------------------------------------------
Advice Letter No.  1025-E                                Date Filed May 21, 1984
Decision No.      83-10-093                              Effective June 20, 1984
                                                         Resolution No.

                                    Issued By
                                 W. M. Gallavan
                                 Vice-President
                          Rates and Economic Analysis


Pacific Gas and Electric Company           Original Cal. P.U.C. Sheet No. 8621-E
   San Francisco. California    Cancelling ________ Cal. P.U.C. Sheet No. ______
- --------------------------------------------------------------------------------
          RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)

F.   SPECIAL FACILITIES (continued)

          d.   Where the Producer elects to install and deed to the Utility an
               extension of the Utility's distribution or transmission lines for
               use as special facilities in accordance with Section 8.5, the
               Utility's estimate of the installed cost of such extension shall
               be subject to the monthly ownership charge applicable to
               customer-financed special facilities as set forth in Section I of
               the Rule No. 2.

     4.   Where payment or collection of continuing monthly ownership charges is
          not practicable, the Producer shall be required to make an equivalent
          one-time payment in lieu of such monthly charges.

     5.   Costs of special facilities borne by the Producer may be subject to
          downward adjustment when such special facilities are used to furnish
          permanent service to a customer of the Utility. This adjustment will
          be based upon the extension allowance or other such customer allowance
          which the Utility would have utilized under its then applicable
          tariffs if the special facilities did not otherwise exist. In no event
          shall such adjustment exceed the original installed cost of that
          portion of the special facilities used to serve a now customer. An
          adjustment, where applicable, will consist of a refund applied to the
          Producer's initial payment. for special facilities and/or a
          corresponding reduction of the ownership charge.

G.   EXCEPTIONAL CASES: Where the application of this rule appears impractical
     or unjust, the Producer may refer the matter to the Commission for special
     ruling or for the approval of special conditions.

H.   INCORPORATION INTO POWER PURCHASE AGREEMENTS: Pursuant to Decision No.
     83-10-093, if in accordance with Section A.4 the Producer enters into a
     written form of power purchase agreement with Utility, a copy of the Rule
     No. 21 in effect on the date of execution will be appended to, and
     Incorporated by reference into such power purchase agreement. The Rule
     appended to such power purchase agreement shall then be applicable for the
     term of the Producer's power purchase agreement with the Utility.
     Subsequent revisions to this rule shall not be Incorporated into the rule
     appended to such power purchase agreement.


- --------------------------------------------------------------------------------
Advice Letter No.  1025-E                                Date Filed May 21, 1984
Decision No.      83-10-093                              Effective June 20, 1984
                                                         Resolution No.

                                    Issued By
                                 W. M. Gallavan
                                 Vice-President
                          Rates and Economic Analysis

                                      E-2(f)


E-2  POINT OF DELIVERY LOCATION SKETCH

     The Seller requests, and PGandE consents, that the location sketch not be
made at the time of executing the Agreement, because the Seller, recognizing
that the information is not yet available to make a definitive determination of
the sketch to be inserted here, shall request PGandE to perform an
interconnection study to be done in its accustomed manner of making such studies
to determine the sketch to be inserted.







                                      E-3


E-3  INTERCONNECTION FACILITIES FOR WHICH SELLER IS RESPONSIBLE

     The Seller requests, and PGandE consents, that this listing of facilities
not be filled in at the time of executing the Agreement, because the Seller,
recognizing that the information is not yet available to make a definitive
determination of the listing of facilities to be inserted here, shall request
PGandE to perform an interconnection study to be done in its accustomed manner
of making such studies to determine the listing of facilities to be inserted.









                                      E-4

EX-10.4

Exhibit 10.4

AGREEMENT dated as of November 6, 1987 by and between Northeast Landfill Power Co., a Massachusetts corporation (“Seller”), and New England Power Company, (“NEP”), a Massachusetts corporation.

ARTICLE I.       BASIC UNDERSTANDINGS

Seller intends to construct, operate and maintain three landfill gas-fired electric generation projects at landfills located in Worcester, MA, and Johnston, Rhode Island (RI) (collectively, the “Facilities” and singularly the “Facility”).  The total projected capacity of the Facilities is approximately twelve thousand kilowatts (12,000 KW).

Subject to the following terms and conditions, Seller agrees to sell and deliver, and NEP agrees to purchase and receive, the entire NEP Entitlement, as defined below, in each of the Facilities.

ARTICLE II.       DEFINITIONS

Whenever used in this Agreement, the following terms shall have the following meanings:

“Affiliate of NEP” shall mean any company that is a subsidiary of the New England Electric System.

“Commencement Date of Operation” shall mean 12:01 a.m. on the first day of the month following the date Seller designates, in writing, as the initial date of commercial operation of the Facilities, which shall not precede the latter to occur of (i) completion of successful acceptance testing of the Johnston Facility for purposes of financing and project operation or (ii) the initial date on which Seller generates at least five megawatts (5 MW) of electricity at the Johnston Facility continuously for a period of eight (8) consecutive hours.

“Good Utility Practice(s)” shall mean the practices, methods and acts (including but not limited to the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry) that, at a particular time, in the exercise of reasonable judgment in light of the facts known or that should have been known at the time a decision was made, would have been expected to accomplish the desired result in a manner consistent with law, regulation, reliability, safety, environmental protection, economy and expedition. With respect to each of the Facilities, Good Utility Practice(s) include but are not limited to taking reasonable steps to ensure that:

(l) adequate materials, resources and supplies, including landfill gas, are available to meet the Facility’s needs;

(2) sufficient operating personnel are available and are adequately experienced and trained and licensed as necessary to operate the Facility properly and efficiently and are capable of responding to emergency conditions relating to the operation of the Facility whether caused by events on or off the site of the Facility;

1

(3) preventative, routine and non-routine maintenance and repairs are performed on a basis that ensures reliable long-term and safe operation of the Facility, and are performed by knowledgeable, trained and experienced personnel utilizing proper equipment and tools;

(4) appropriate monitoring and testing is done to ensure equipment at the Facility is functioning as designed and to provide assurance that equipment will function properly under both normal and emergency conditions; and

(5) equipment is not operated at the Facility in a reckless manner, or in a manner unsafe to workers, the general public or the environment or without regard to defined limitations such as rate of refuse decomposition and gas production, air intrusion, safety inspection requirements, operating voltage, current, frequency, rotational speed, polarity, synchronization, and control system limits.

“NEP Entitlement” shall mean one hundred percent (100%) of the Net Capability and Net Electric Output of each of the Facilities unless Seller exercises its option to contract with another utility for the sale of a percentage of the Net Capability and the Net Electric Output of the Facilities under Article IV, below. If Seller exercises such option “NEP Entitlement” shall mean the percentage of the Facilities’ Net Capability and Net Electric Output not contracted for sale to another utility.

“NEP’s System” shall mean the electrical system of NEP and/or the electrical system of any Affiliate of NEP.

“NEPEX” shall mean the New England Power Exchange.

“NEPOOL” shall mean the New England Power Pool.

“NEPOOL Agreement” shall mean the New England Power Pool Agreement dated as of September 1, 1971, as amended.

“Net Capability” shall mean, with respect to each of the Facilities, the maximum dependable load-carrying ability of the Facility, exclusive of capacity required for the Facility’s use, expressed in kilowatts, as determined by tests conducted in accordance with the NEPOOL Agreement, including appropriate NEPOOL Criteria, Rules and Standards and Operating Procedures.

“Net Electric Output” shall mean, with respect to each of the Facilities, the total amount of electricity generated by the Facility less kilowatthours consumed for the Facility’s use.

“Off-Peak Periods” shall mean all hours not falling within On-Peak Periods.

“On-Peak Periods” shall mean all hours from 7:00 a.m. to 11:00 p.m. Monday through Friday, excluding legal holidays designated in writing by NEP. At Seller’s request, NEP shall provide to Seller a list of designated legal holidays prior to the beginning of each calendar year.

2

“Prime Rate” shall mean the prime (or comparable) rate announced from time to time as its prime rate by the Bank of Boston, which rate may differ from the rate offered to its most substantial and creditworthy customers.

“Rate X” shall mean NEP’s short term avoided energy cost calculated by NEP in accordance with the methodology described in Appendix A, attached hereto and incorporated herein by reference, such calculation to be provided to Seller on a timely basis for review.

ARTICLE III.       TERM

It shall be a condition precedent to the effectiveness of this Agreement that (i) the requirements of 220 C.M.R. 8.01 et. seq., for the effectiveness of the Agreement have been fulfilled without a finding by the Massachusetts Department of Public Utilities (“DPU”) that this Agreement, or any one or more of its provisions is contrary to the public interest, or (ii) a court or governmental authority of requisite jurisdiction has determined that the DPU lacks jurisdiction over NEP’s purchase of the NEP Entitlement.

The term of this Agreement shall extend for a period ending thirty (30) years after the Commencement Date of Operation; provided, however, that this Agreement shall terminate on the twentieth (20th) anniversary of the Commencement Date of Operation if NEP gives Seller not less than one-hundred and eighty (180) days prior written notice of such termination unless Seller agrees prior to such twentieth (20th) anniversary to amend article VI B, below, to provide that the price to be paid by NEP subsequent to such twentieth (20th) anniversary for monthly quantities of electricity delivered hereunder shall be a price per kilowatthour equal to Rate X.

Notwithstanding the preceding paragraph, if (a) Seller has not secured exclusive rights, for a term at least equal to the term of this Agreement, to purchase the landfill gas produced at each of the currently permitted landfill sites on which the Facilities will be located within ninety (90) days of the effective date of this Agreement, (b) construction of the initial gas collection system for the Johnston Facility has not been substantially completed within one (1) year of the effective date of this Agreement, or (c) the Commencement Date of Operation has not occurred prior to December 31, 1989, NEP may thereafter terminate this Agreement by providing Seller thirty (30) days’ written notice within 60 days of (a), (b), or (c), above, as appropriate.

NEP shall have the option to purchase the Net Capability and the Net Electric Output of each or any of the Facilities following expiration or termination of this Agreement, other than for breach by NEP, upon substantially the same terms and purchase price as that offered by Seller to any third party, which option shall be held open for forty-five (45) days after Seller’s presentation of the terms of such offer to NEP.  NEP’s option to purchase such Net Capability and Net Electric Output of each or any of the Facilities shall survive expiration or termination of this Agreement and shall terminate only upon agreement by a third party to purchase such Net Capability and Net Electric Output upon substantially the same terms and purchase price most recently offered to NEP, but not accepted by NEP, within forty-five (45) days of Seller’s presentation of such offer to NEP. For purposes of this paragraph, a purchase price that is substantially the same as that offered to any third party shall equal the purchase price offered to any such third party reduced by all costs that would be incurred by Seller and/or such third party in connection with the transmission of the particular Facility’s Net Electric Output from the Facility to such third party.

3

ARTICLE IV.       OPTIONAL CONTRACT SALE

Seller shall have the option, exercisable on or before January 1, 1988, to contract with another utility for the sale of up to fifty percent (50%) of the Net Capability and the Net Electric Output of the Facilities for a term commencing with the Commencement Date of operation and extending for an uninterrupted period not to exceed twenty (20) years, provided that the percentage of the Net Capability and Net Electric Output so sold (the “Contract Percentage”) is fixed throughout such term (any such contract shall be hereinafter referred to as the “Optional Contract.”)

If Seller exercises such option, then NEP shall have the right, exercisable by written notice given to Seller not less than ninety (90) days prior to the expiration of the term of the Optional Contract, to elect to purchase the Contract Percentage from Seller under the terms and conditions of this Agreement from the Optional Contract’s expiration date through the expiration date of this Agreement but at a price per kilowatthour delivered equal to the average of (i) the price calculated in accordance with Article VI B (the “Contract Price”) and (ii) Rate X as determined from time to time.

If NEP does not so elect, then Seller shall have the right, exercisable by written notice given to NEP not less than sixty (60) days prior to the expiration of the term of the Optional Contract, to elect to sell the Contract Percentage to NEP (and if Seller so elects, NEP shall purchase and receive the Contract percentage) under the terms and conditions of this Agreement from the Optional Contract’s expiration date through the expiration date of this Agreement but at a price per kilowatthour delivered equal to the lesser of Rate X or the Contract Price, both as determined from time to time. If Seller does not so elect, Seller shall have the right to sell the Contract Percentage to another electric utility.

ARTICLE V.       TERMS OF SALE

Seller agrees that the Facilities shall be designed, constructed, operated and maintained such that they reasonably may be expected (i) to have a monthly average Net Electric Output not exceeding twelve thousand kilowatts (12,000 KW) per hour and (ii) to produce collectively a constant Net Electric Output for a period of not less than thirty (30) years. During the design and construction of the Facilities, Seller shall provide NEP with such information as NEP may request to determine whether the Facilities are being so designed and constructed.

Seller shall choose an architect/engineer firm (“AE Firm”) for the design, or for the review of the design if such design is provided by Sellers vendor(s), of each of the Facilities, which selection shall be subject to approval by NEP.  NEP hereby approves the selection of Hayden-Wegman as the AE Firm, and NEP shall not unreasonably withhold approval of any other AE Firm selected by seller. If NEP fails to approve or disapprove Seller AE Firm selection within thirty (30) days of a presentation by the proposed AE Firm to NEP of its design capabilities, NEP shall be deemed to have approved the selection for all purposes of this Agreement. NEP and Seller shall mutually choose a qualified independent engineering firm (“I.E. Firm”) to evaluate the design of each of the Facilities at Seller’s expense. The scope of the I.E. Firm’s design evaluation shall be subject to Seller’s review and NEP’s review and approval. The I.E. Firm’s design evaluation of each Facility shall be provided to NEP in writing prior to commencement of the construction of the Facility. Unless NEP and Seller agree otherwise in writing, Seller shall cause the AE Firm to make all changes in the Facility’s design that the I.E. Firm determines are necessary to meet the requirements of the preceding paragraph and Good Utility Practice. Seller shall cause each of the Facilities to be constructed in accordance with the resulting design. Seller shall insure that all equipment used in each of the Facilities shall be new and unused, good quality utility grade, suitable for the intended service and shall meet the requirements of applicable codes and standards.

4

Prior to the later to occur of the Commencement Date of Operation or January 1, 1989, Seller shall sell and deliver and NEP shall purchase and receive the NEP Entitlement in each of the Facilities when and if available at the price specified in ARTICLE VI A, below. Thereafter, Seller shall sell and deliver, and NEP shall purchase and receive, the NEP Entitlement in each of the Facilities at the price specified in ARTICLE VI B, below. NEP agrees to accept delivery of the NEP Entitlement in each of the Facilities. NEP shall not, however, be liable for any damages arising from its inability to accept delivery of any electricity that each or any of the Facilities are otherwise capable of generating if NEP uses all reasonable efforts to promptly restore such ability. Seller shall install and maintain in a safe manner, and in accordance with Good Utility Practice and applicable regulations, all of its equipment and facilities connected to NEP’s System. If at any time the operation of each or any of the Facilities endanger the safety of NEP’s personnel, or interferes with the safe and reliable operation of NEP’s System, NEP may discontinue purchases from Seller and disconnect from such Facility until such condition has been corrected. Unless an emergency exists, or the risk of one is imminent, NEP shall give Seller reasonable notice of its intention to disconnect from each or any of the Facilities and to discontinue purchases from Seller, and where practical, allow suitable time for Seller to remove the interfering condition. NEP shall reasonably cooperate with Seller in Seller’s efforts to remove such interfering condition. Any costs incurred by NEP in so cooperating shall be at Seller’s expense. NEP’s judgments with regard to discontinuance of purchases or disconnection of each or any of the Facilities under this paragraph shall be made in accordance with Good Utility Practice.

Seller shall cause, at Seller’s expense, the AE Firm, equipment vendor or such other party as may be chosen by Seller and approved by NEP which approval will not be unreasonably withheld, to prepare a plan and schedule for annual ongoing maintenance and spare parts inventory as well as a plan for less frequent major overhaul work on each of the Facilities’ generators, gas collection systems, and auxiliary equipment. Such plan shall be subject to NEP’s approval, which shall not be unreasonably withheld and shall conform to the recommendations of the equipment vendors and the AE Firm. Seller shall provide such plan to NEP prior to the Commencement Date of Operation. Subject to the following paragraph, Seller shall perform maintenance of each of the Facilities in accordance with such plan.

Seller shall cause, at Seller’s expense, an independent engineering firm (“I.E. O&M”) selected by Seller and approved by NEP (which approval shall not be unreasonably withheld) to conduct a review of each of the Facilities’ operation and maintenance practices after the second and before the third anniversary of the Commencement Date of Operation, and, unless the parties otherwise agree, every five years thereafter.  In addition, such a review shall be conducted at NEP’s written request in any year following a two calendar year period in which, for each of the two calendar years, the Net Electric Output of the Johnston Facility is less than ninety percent (90%) of the Johnston “KWHr Production (1000 KWH)” set forth in Appendix B, attached hereto and incorporated herein by reference. Seller shall cause the I. E. O&M to issue a written report describing the extent to which the maintenance plan and schedule described in the preceding paragraph is being followed, a description of and a statement of the reasons for any justified departure from such schedule or plan, a description of any deficiencies in the Facility’s operation and maintenance practices, and its recommendations, if any, for improving future operation and maintenance practices. Seller shall implement any recommendations made by the I.E. O&M that the I.E. O&M determines are necessary to meet Good Utility Practice unless Seller and NEP mutually agree otherwise. Seller shall keep and make available adequate maintenance logs for use by the I. E. O&M and/or NEP for the purpose of this review.

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Seller agrees to operate the Facilities in parallel with NEP System and to deliver the NEP Entitlement in each of the Facilities to NEP at the delivery points and voltage levels specified in ARTICLE VIII, below. Unless otherwise requested by NEP, Seller shall operate each of the Facilities at a unity power factor or in an over excited condition at the point of delivery to NEP, subject to the response tine of control equipment to transient conditions on NEP System. If Seller fails to operate each or any of the Facilities at a unity power factor or in an over excited condition, NEP may install, at Seller’s expense, capacitors or other electric equipment necessary to ensure that such Facility can be so operated. NEP shall have the right on a short—term emergency basis to request that Seller operate each or any of the Facilities at any excitation level within the range of the particular Facility’s capability as determined from the equipment manufacturer’s recommendations. Seller agrees to use all reasonable efforts to comply with any such request from NEP.

At NEP’s sole option, NEP shall have the right to claim credit for (i) all or a portion of each or any emission to the air from each or any of the Facilities and the associated equivalent Btu heat input or (ii) the equivalent Btu heat input to each or any of the Facilities, that can be associated, per statutes, laws, regulations, ordinances, government standards and/or government regulations, with generation at the particular Facility. If NEP exercises such option, NEP shall reimburse Seller for all incremental expenses incurred by Seller and associated with such credits, beyond those required for the particular Facility to meet applicable environmental regulations. In no case shall NEP claim a credit at any time if it would cause the Facility to be in violation of the Facility’s applicable all quality emissions limit or any other applicable laws or regulations and NEP shall have no liability in the event the Facility fails to meet applicable environmental regulations.

If the Federal Energy Regulatory Commission (FERC) determines that each or any of the Facilities is not a Qualifying Facility pursuant to 18 C.F.R. Part 292, or each or any of the Facilities otherwise becomes subject to Section 205 of the Federal Power Act or any similar federal requirement, Seller shall file, within sixty (60) days of such event, a rate with FERC requiring payments for electricity generated by such Facility(ies) and sold by Seller to NEP to be based on Seller’s reasonable costs of generating electricity but in no event at a rate higher than the applicable rates specified in Article VI hereof, effective as of the date of such event.

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During the term of this Agreement, Seller agrees that Seller shall not permit landfill gas purchased by it at each or any of the landfills on which the Facilities are located, or waste heat and/or steam generated by each or any of the Facilities, to be sold or used for any purpose other than generating electricity, unless required by regulatory f authorities, without NEP prior written approval which approval shall be granted if Seller demonstrates to NEP’s satisfaction that such sale or use would not adversely affect the present or future level of electricity production at the particular Facility over the remaining tern of this Agreement.

Seller agrees that during the term -of this Agreement it will not sell or otherwise dispose of its interest in each or any of the Facilities without first obtaining NEP’s written consent, which consent shall not be unreasonably withheld.

Commencing as of the Commencement Date of Operation, Seller shall:

(1)           Operate the electric generating unit(s) at each of the Facilities to the maximum extent feasible consistent with Good Utility Practice; Sell shall provide NEP with such information at NEP may reasonably request to determine whether each of the Facilities is being so operated and maintained.

(2)           Operate and maintain each of the Facilities in accordance with Good Utility Practice; Seller shall provide NEP with such information as NEP may reasonably request to determine whether the Facilities are being so operated and maintained.

(3)           Provide NEP prior to the first day of January of each year, or at NEP’s reasonable request, an estimate of the amount of electricity to be generated at each of the Facilities for each of the following twelve (12) months beginning January 1, or the first day of the month following NEP’s request;

(4)           Provide NEP, or its designee, prior to the first day of each month, a schedule of the anticipated generation of electricity at each of the Facilities for such month;

(5)           At NEP’s request, provide NEP, or its designee, prior to 9:00 a.m. of each day, a schedule of the anticipated generation of electricity at each of the Facilities for the next day;

(6)           Use all reasonable efforts to maximize delivery of electricity from each of the Facilities during On-Peak Periods;

(7)           Conduct scheduled maintenance of each of the Facilities during reasonable periods designated by NEP.  NEP shall designate such periods for each calendar year in writing during the preceding December, but not less than ninety (90) days prior to the beginning of a period so designated;

(8)           Cooperate with NEP in the arrangement and conduct of any tests required under the NEPOOL Agreement to determine the Net Capability of each of the Facilities and in operating each of the Facilities in conformity with any applicable requirements of NEPEX and/or its satellite dispatching center, including providing such operating and/or design information to NEP or its designee as NEP may request; and

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(9)           Provide NEP such supporting information related to billing as NEP may reasonably request.

The estimates and schedules provided by Seller under Clauses (3), (4) and (5), above, shall be prepared in good faith, based on landfill gas availability and other conditions anticipated at the time such estimates and schedules are made, but shall not be binding on Seller.  Seller shall, however, promptly inform NEP whenever it appears that actual generation at each or any of the facilities will vary more than ten percent (10%) from the most recent estimates or schedules provided under Clause (3), (4), or (5), above.

The parties recognize that emergencies, accidents, other unusual conditions and events of force majeure as defined in Article XIV, may necessitate a departure from scheduled generation. Seller, however, agrees to use all reasonable efforts to promptly resume scheduled generation.

ARTICLE VI.       PRICE AND BILLING

A.           Prior to July 1, 1988, NEP shall pay Seller monthly for quantities of electricity delivered for sale to NEP hereunder, as determined in accordance with ARTICLE VIII, a price in cents per kilowatthour equal to ninety percent (90%) of Rate X. Commencing on July 1, 1988, and extending until the later to occur of January 1, 1989 or the Commencement Date of Operation, NEP shall pay Seller monthly for quantities of such electricity, a price in cents per kilowatthour equal to four and eight-tenths cents ($.048) per kilowatthour delivered during On-Peak Periods and two and eight-tenth cents ($.028) per kilowatthour delivered during Off-Peak Periods.

B.           Commencing on the later to occur of January 1, 1989 or the Commencement Date of Operation, NEP shall pay Seller monthly for quantities of electricity delivered for sale to NEP hereunder, as determined in accordance with ARTICLE VIII, a price in cents per kilowatthour calculated in accordance with the following formula:

P =  [Q + (R x S)] x U

              T

Where “P” is the total price in cents per kilowatthour;

“Q” is three and one-half cents (3.5¢) per kilowatthour for electricity delivered during On-Peak Periods and one and one-half cents (1.5¢) per kilowatthour for electricity delivered during Off-Peak Periods, respectively.  NEP may, at its option, upon thirty (30) days written notice to Seller, increase or decrease “Q” for On-Peak Periods and increase or decrease “Q” for Off-Peak Periods; provided, however, that the average value of “Q” for On-Peak Periods and Off—Peak Periods, weighted by the number of hours in the On-Peak and Oft-Peak Periods, shall equal the average value of “Q” for On-Peak Periods and Off-Peak Periods, weighted by the number of hours in the On-Peak and Off-Peak Periods, prior to such revision;

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“R is three cents (3¢) per kilowatthour;

“S” is 1.00 through December 31, 1989 and in each calendar year thereafter “S” is the Consumer Price Index for Urban Wage Earners and Clerical Workers, unadjusted for seasonal variations, all items indexed for Boston, Massachusetts, as published in the Bureau of Labor Statistics’ CPI Detailed Report (the “CPI Index”) for November of the preceding Calendar Year; provided, however, that if a CPI Index is not published for November, “S” shall be the CPI Index for the first preceding month for which a CPI Index is published;

“T” is 1.00 through December 31, 1989 and in each calendar year thereafter “T” is the CPI Index for November of 1988; provided, however, that if a CPI Index is not published for November of 1988 “T” shall be the CPI Index for the first preceding month for which a CPI Index is published; and

“U” is 1.00 through December 31 of the first full calendar year in which the amount paid by NEP under this ARTICLE VI B for the monthly quantities of electricity delivered hereunder during the calendar year is less than the total amount that would have been paid by NEP for the monthly quantities of electricity delivered hereunder during the calendar year had the price established under this ARTICLE VI B been equal to Rate X as in effect during the calendar year (the “Crossover Year”); and in each month thereafter “U” shall be the lesser of 1.00 or an amount calculated in accordance with the following formula:

U = .5 + (.5 x K)

                     L

Where “K” is the quantity of electricity in kilowatthours delivered during the preceding calendar year; and

“L” is:

(i) Until December 31 of the year in which the “Aggregate Differential” as defined in Article VII B, below, is reduced to zero (0), the average quantity of electricity delivered during the Crossover Year and the prior four full calendar years. If fewer than four full calendar years have elapsed from the Commencement Date of Operation to the beginning of the Crossover Year, “L” shall be determined using the average quantity of electricity delivered for all full calendar years from the Commencement date of Operation to the end of the Crossover Year; and

(ii) Thereafter, the “Total Kwhr Production” for the preceding calendar year specified in Appendix B hereto multiplied by the highest Net Capability of the Facilities determined in any year following the Commencement Date of Operation divided by twelve thousand kilowatts (12,000 kw).

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If a CP Index referred to in “S” above has not been published at the time that such information is required for billing, the value of “P” shall remain unchanged until such publication, at which time a retroactive billing adjustment shall be made.

In the event of any future modification of the basis upon which the CPI Index is calculated, “T” shall be adjusted to be on a consistent basis with “S”.

If publication of the CPI Index is discontinued during the term of this Agreement, the parties agree to meet and mutually agree upon an alternative, but substantially equivalent, method of adjusting the value of “R”, above, in determining the price to be paid by NEP under this Paragraph B.

If the CPI Index employed in calculating the price to be paid by NEP during any month is subsequently revised, then such price shall be recalculated using the revised information and the bills and payments for such month shall be retroactively adjusted to reflect such recalculated price.

Notwithstanding the preceding provisions of this ARTICLE VI B, if Seller delivers a quantity of electricity during the On-Peak Period or Off-Peak Period in any month that exceeds an amount equal to the product of (i) one (1) minus the Contract Percentage (if any) (expressed as a decimal) times (ii) twelve thousand kilowatts (12,000 KW) multiplied by the number of On-Peak hours or Off-Peak hours during the month, respectively (the “Maximum Participation Level”), then NEP shall not be required to pay Seller for any quantity of electricity delivered to NEP in excess of the Maximum Participation Level in the respective On-Peak or Off-Peak Period.

C.           Bills for all amounts due under this ARTICLE VI shall be tendered to NEP monthly. A separate bill shall be rendered for electricity delivered to NEP from each of the Facilities. At NEP’s request, each bill shall contain a breakdown of the amount billed expressed in terms of the fuel-related and non-fuel-related cost to NEP of electricity purchased hereunder.. The breakdown shall be presented on both a cents per kilowatthour basis and a total bill basis. The fuel-related cost to NEP shall be deemed to be equal to a percentage of NEP’s avoided fuel cost per kilowatthour to be specified by NEP and the non-fuel-related cost to NEP shall be deemed to equal the balance. In no event shall any such breakdown of the amount billed result in any increase or reduction in the price payable by NEP to Seller under this ARTICLE VI.  If NEP requests such a breakdown, NEP shall provide Seller with its avoided fuel cost calculation for each month on or before the fifth business day of the following month. No such breakdown shall be construed as indicative, of the cost of fuel or any other expenses incurred by Seller in generating electricity for sale to NEP.

Seller may in writing direct that NEP make payment of bills rendered by Seller hereunder to a third party such as a trust agent for disbursement. If all or any part of any bill shall remain unpaid for more than thirty (3) days after NEP’s receipt of such bill, interest at a rate per annum equal to the Prime Rate shall thereafter accrue and be payable to Seller either (i) on such unpaid amount, or (ii) in the event the amount of the bill is disputed, on the unpaid amount finally determined to be due and payable. NEP may dispute all or any part of any bill by mailing to Seller written notice thereof, stating the reason for such dispute, within thirty (30) days of receipt of such bill and by paying to Seller any amount not in dispute. Both parties shall exercise good faith in resolving any such dispute in a timely manner.

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ARTICLE VII.       DEFAULT/TERMINATION/SECURITY/COMPLETION SECURITY AND MILESTONES

A.           Events of Default.  The occurrence of any one or more of the following shall constitute an “Event of Default” hereunder:

(1)           If, except to the extent permitted under ARTICLE VI C, above, with regard to amounts in dispute, NEP shall fail to make any payment required pursuant to ARTICLE VI, above, and such failure continues for a period of forty-five (45) days after written notice thereof from Seller;

(2)           If (i) Seller shall fail in any material respect to comply with, observe, perform or shall default in any material respect upon any covenant, warranty or obligation under this Agreement and such failure materially adversely affects the NEP Entitlement in the Facilities, Seller’s ability to furnish to NEP the NEP Entitlement in the Facilities or NEP’s ability to take and receive such NEP Entitlement during the term of this Agreement, and (ii) after written notice thereof from NEP, such failure shall continue for a period of forty-five (45) days, or, if such failure cannot reasonably be cured within such forty-five (45) day period, such further period as shall reasonably be required to effect such cure, provided that Seller commences within such forty-five (45) day period to effect such cure and at all times thereafter proceeds diligently to complete such cure as quickly as reasonably possible;

(3)           If (i) there shall be filed by or against Seller a petition initiating proceedings under the Bankruptcy Code and such proceedings shall not be dismissed within forty-five (45) days or (ii) if Seller shall be in default under the terms of any obligation or agreement secured by any lien(s) and/or security interest(s) on or in Seller’s properties and assets at the Facilities (including, without limitation, any leasehold interest in or possessory interest in the Facilities and any licenses or other rights to use, manage and/or occupy the Facilities, as applicable) and the holder of such lien(s) and/or security interest(s) shall give notice of intention to accelerate and thereafter to commence action to foreclose or otherwise realize on the properties and assets of Seller securing such obligation and/or agreement (hereinafter “Default Notice”) and Seller does not cure such default on or before the expiration of any grace period or waiver applicable to such obligation or agreement; provided, however, that any occurrence set forth in this clause (3) shall not constitute an Event of Default if within forty-five (45) days of the initiation of such proceedings or the giving of such Default Notice Seller instructs NEP in writing to reduce each monthly payment otherwise due Seller from NEP under Article VI, above, during the period that such proceedings remain outstanding or such default remains uncured by an amount equal to the amount by which the Aggregate Differential, as defined in ARTICLE VII B, below, would otherwise have increased over the amount determined for the preceding month. If Seller so instructs NEP, and if such proceedings are subsequently terminated or such default is subsequently cured and Seller reaffirms its intention to perform its obligations hereunder and provides adequate assurance of its ability to perform such obligations, then, within thirty (30) days of NEP receipt of written notice from Seller of the termination of such proceedings or the cure of such default, NEP agrees to pay Seller any aggregate amount by which each of NEP monthly payments have been reduced in accordance with this clause (3) plus interest accrued on each such monthly reduction commencing as of the date of such reduction at a rate per annum equal to the Prime Rate in effect on the first business day of each month;

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(4)           If Seller fails to make a required monthly deposit into the Escrow Account as provided in ARTICLE VII C, below, or if Seller fails to deposit with NEP the Irrevocable Letter of Credit as provided in ARTICLE VII D, below;

(5)           If Seller grants a security interest in the Escrow Account established in accordance with ARTICLE VII C, below, to any party other than NEP; and

(6)           If, prior to December 31, 1996, the currently permitted landfill site on which the Johnston Facility is located does not receive for disposal municipal and commercial solid waste at an average rate of either (i) at least five hundred (500) tons per day over any consecutive two (2) month period, or (ii) at least one thousand (1000) tons per day over any consecutive twelve (12) month period; provided, however, that any occurrence set forth in this clause (6) shall not constitute an Event of Default if within forty-five (45) days of such occurrence Seller instructs NEP in writing to reduce each monthly payment otherwise due Seller from NEP under ARTICLE VI, above, during the period such default remains uncured by an amount equal to the amount by which the Aggregate Differential, as defined in ARTICLE VII B, below, would otherwise have increased over the amount determined for the preceding month. If Seller so instructs NEP. and such default is subsequently cured or if Seller demonstrates to NEP reasonable satisfaction that the Facilities can be expected to generate a Net Electric Output during the balance of this Agreement at a level equal to the projected “Total kWhr Production” specified in Appendix B hereto over the balance of this Agreement times the highest Net Capability of the Facilities determined in any year following the Commencement Date of Operation divided by twelve thousand kilowatts (12,000 kW), then, within thirty (30) days NEP agrees to pay Seller any aggregate amount by which each of NEP’s monthly payments have been reduced in accordance with this clause (6) plus interest accrued on each such monthly reduction commencing as of the date of such reduction at a rate per annum equal to the Prime Rate in effect on the first business day of each month.

Seller shall notify NEP immediately upon the occurrence of an event described in Clause (3)(i), Clause (3)(ii), Clause (5), or Clause (6), above.

The enumeration of Events of Default hereunder shall not be construed to limit or exclude the right of the parties hereto to seek remedies at law or in equity or damages for the breach of any other term, condition, covenant, warranty or obligation hereunder.

B.           Termination.  If an Event of Default shall occur and be continuing, the non—defaulting party may, by notice in writing, terminate this Agreement as of the date of such notice.

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In the event of the termination of this Agreement by NEP pursuant to this ARTICLE VII B, Seller acknowledges and agrees that NEP will suffer direct damages as a result of such termination and that such direct damages are not susceptible of easy determination, but shall in all events be at least equal to the Aggregate Differential, as hereinafter defined, and Seller agrees to pay NEP (as liquidated damages, and not as a penalty) an amount equal to the Aggregate Differential, if any, as of the date of such termination, plus interest thereafter accrued at a rate per annum equal to the Prime Rate.

Notwithstanding any other provision of this Agreement to the contrary, neither the determination of the Aggregate Differential nor seller’s agreement to pay the Aggregate Differential to NEP as liquidated damages shall be construed to limit or affect NEP’s right to assert and prove further direct damages in the event of Seller’s breach of or NEP’s termination of this Agreement, but not direct damages relating to past or future power supply unless Seller breaches ARTICLE V of this Agreement by voluntarily selling or otherwise disposing of its interest in each or any of the Facilities.

For purposes of this Agreement, the term “Aggregate Differential” shall mean an amount determined each month following July 1, 1988 in accordance with the following formula:

A = (B + [[(W x U) — V] x C]] x (1 + F)

Where “A” is the Aggregate Differential for the month;

“B” is the prior month’s Aggregate Differential;

“C is the quantity of electricity delivered hereunder, as determined in accordance with ARTICLE VIII, for the month, expressed in kilowatthours;

“W” is equal to the following amounts per kilowatthour delivered:

1988             $.0380                 1998               $.0677                 2008                 $.0882

1989               .0550                 1999                 .0694                 2009                   .0907

1990               .0562                 2000                 .0712                 2010                   .0934

1991               .0574                 2001                 .0730                 2011                   .0961

1992               .0587                 2002                 .0750                 2012                   .0989

1993               .0601                 2003                 .0770                 2013                   .1019

1994               .0615                 2004                 .0790                 2014                   .1050

1995               .0630                 2005                 .0812                 2015                   .1082

1996               .0645                 2006                 .0834                 2016                   .1115

1997               .0661                 2007                 .0858                 2017                   .1150

“U” is as calculated in Article VI B.

“V” is equal to the following amounts per kilowatthour delivered:

1988             $.0342                 1998               $.0945                 2008                 $.1332

1989               .0371                 1999                 .0972                 2009                   .1389

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1990               .0390                 2000                 .1001                 2010                   .1450

1991               .0464                 2001                 .1037                 2011                   .1515

1992               .0512                 2002                 .1075                 2012                   .1585

1993               .0555                 2003                 .1109                 2013                   .1659.

1994               .0598                 2004                 .1147                 2014                   .1738

1995               .0844                 2005                 .1189                 2015                   .1823

1996               .0891                 2006                 .1233                 2016                   .1915

1997               .0917                 2007                 .1279                 2017                   .2015

; and

“F” is .0075

C.           Security.

To secure the payment by Seller to NEP of the Aggregate  Differential, as provided in ARTICLE VII B above, Seller shall establish, on or prior to July 1, 1988, an interest bearing escrow account (the “Escrow Account”) with a banking institution acceptable to NEP (the “Escrow Agent”). The Escrow Account shall be established for the benefit of NEP. Seller hereby grants to NEP a security interest in the Escrow Account to secure such payment.

Subject only to Seller’s approved financing, fuel, operation and maintenance obligations as detailed in Appendix C, attached hereto and incorporated herein by reference, each month following July 1, 1988 Seller shall deposit into the Escrow Account an amount equal to five percent (5%) of the total amount paid by NEP to Seller for electricity delivered to NEP under ARTICLE VI of this Agreement during the preceding month; provided, however, that if Seller exercises its option to enter into an Optional Contract under ARTICLE IV, above, the amount to be so deposited during the term of the Optional Contract shall be increased to seven percent (7%) of the total amount paid by NEP to Seller for electricity delivered to NEP under ARTICLE VI of this Agreement during the preceding month. If Seller has insufficient funds in any month to make such deposit due to Seller’s approved financing, fuel, operation and maintenance obligations, then Seller shall provide NEP with written notice of the basis for Seller’s inability to make its required deposits and Seller shall make up the shortfall, together with interest accrued at a rate per annum equal to the Prime Rate, in the first month(s) in which Seller has sufficient funds to both make its required monthly deposit into the Escrow Account and to make up or to reduce such shortfall. Seller’s obligation to make deposits under this ARTICLE VII C shall continue and interest shall accrue until the Aggregate Differential is less than the amount in the Escrow Account, at which time Seller shall have the right to discontinue making such deposits and Seller may withdraw from, and NEP consents to the withdrawal from, the Escrow Account any amount by which the balance in the Escrow Account exceeds the Aggregate Differential from time to time. Such withdrawals may be made at any time but not more often than monthly. Withdrawals shall be made only by a direction to the Escrow Agent made in writing jointly by Seller and NEP. If a balance exists in the Escrow Account at the expiration or termination of this Agreement, such balance shall be paid to NEP. Notwithstanding the foregoing, Seller may at any time and from time to time withdraw any part or all of the balance of the Escrow Account after providing NEP with one or more irrevocable letters of credit issued by a banking or other financial institution reasonably acceptable to NEP (the “Issuer”), and otherwise in accordance with this paragraph. Such irrevocable letter(s) of credit shall be in a total amount equal to the amount to be withdrawn from the Escrow Account by Seller, plus compound interest on the principal amount to be withdrawn, at the then effective rate of interest on the Escrow Account balance, for the initial term of the letter(s) of credit. The letter(s) shall be payable to, and for deposit in, the Escrow Account on the twentieth banking day before the expiration of such letter(s). An irrevocable letter of credit as described herein shall be presented to NEP for its approval as to form at least ten (10) days prior to the effective date thereof, such approval not to be unreasonably withheld, and shall be made effective prior to the corresponding withdrawal of funds by Seller pursuant to this paragraph.

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Any fees charged by the Escrow Agent to maintain the Escrow Account shall be paid directly by Seller and shall not be deducted from the Escrow Account.

D.           Completion Milestones and Security.  NEP is relying on the future availability of the NEP Entitlement in the Facilities to meet the needs of its customers. Seller shall within ten days of the effective date of this Agreement provide NEP with a written development plan that outlines preoperational milestones. The plan shall include, at a minimum, milestone dates for financial closing, permitting (including, without limitation, zoning, air quality, water quality, waste handling), construction start date, and Commencement Date of Operation. Seller shall provide NEP with a quarterly status report on its progress in meeting each of the milestones in its development plan until the Commencement Date of Operation. In addition, Seller shall provide-NEP with immediate written notice of any occurrences of which it is aware that are likely to substantially delay construction start date or the Commencement Date of Operation of the Facilities. Seller shall immediately notify NEP in writing if, and at such time that, it decides to discontinue its efforts to construct the Facilities. If its reason for such decision is the denial of a site or environmental permit required by law for the construction of the Facilities, Seller shall identify for NEP the permit that has been denied and provide NEP with documentation of such denial.

Seller shall, within ten days of the effective date of this Agreement, deposit with NEP an Irrevocable Letter of Credit in the initial amount of $12,000, which amount shall be increased to $120,000 on the earlier to occur of (i) the date on which Seller closes on its financing or lease for the electric generating equipment at the Johnston Facility or (ii) the first anniversary date of the effective date of this Agreement, drawn on a bank or other financial institution reasonably acceptable to NEP (the “Issuer”).  Such Irrevocable Letter of credit shall designate NEP as beneficiary with authority to draw drafts on the Issuer as follows:

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Upon Presentation by NEP of a

Signed Statement Over a

Signature Described as

Amount Payable to NEP “Authorized” that:

(i) $12,000 “On or prior to twelve months after the effective date of its power purchase agreement with New England Power Company, Northeast Landfill Power Company notified New England Power Company in writing of its decision to discontinue its efforts to construct the Johnston Facility contemplated in such power purchase agreement.”

Or, alternatively,

“Subsequent to twelve months after the effective date of its power purchase agreement with New England Power Company, Northeast Landfill Power Company notified New England Power Company in writing of its decision to discontinue its efforts to construct the Johnston Facility contemplated in such power purchase agreement due to the denial of a site or environmental permit required by law for construction of such Facility.”

(ii) $120,000 “Subsequent to twelve months following the effective date of its power purchase agreement with New England Power Company, Northeast Lanfill Power Company notified New England Power Company in writing of its decision to discontinue its efforts to construct the Johnston Facility contemplated by such power purchase agreement for reasons other than the denial of a site or environmental permit required by law for construction of such Facilities.”

(iii) $120,000 “As of December 31, 1989, the ‘Commencement Date of Operation’ of the Facilities, as defined in the power purchase agreement between Northeast Landfill Power Company and New England Power Company, has not occurred.”

Seller and NEP agree that the Irrevocable Letter of Credit shall not be exercised except as specified above. If Seller issues a notice in writing to NEP as provided in clause (i) or (ii), above, or following the date specified in clause (iii), above, NEP shall have ninety (90) days within which to draw drafts on the Irrevocable Letter of Credit. IF NEP fails to draw such drafts, it shall be deemed to have waived all rights that are provided it under this ARTICLE VII D.

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As soon as reasonably practicable following (i) NEP’s receipt of the payment specified in Clauses (i), (ii), or (iii), above or (ii) the Commencement Date of Operation, the Irrevocable Letter of Credit shall expire, and NEP shall return it to Seller.

Seller acknowledges and agrees that NEP will suffer direct damages as the result of any decision by Seller to discontinue the construction of the Johnston Facility, or the delay beyond December 31, 1989 of the Commencement Date of Operation of the Facilities and that such direct damages shall in all events be at least equal to the amounts specified above as payable to NEP under the Irrevocable Letter of Credit in connection with such event, and Seller agrees that such amounts shall be payable to NEP as provided above as liquidated damages, and not as a penalty.

ARTICLE VIII.   DELIVERY AND MEASUREMENT OF ELECTRICITY

The Net Electric Output generated by each of the Facilities shall be delivered to NEP at points of interconnection between NEP’s System and Seller’s systems in the form of three-phase sixty-hertz alternating current at a voltage determined by mutual agreement of the parties. Momentary voltage fluctuations shall be permitted, provided that they neither disturb service provided by NEP or any affiliate of NEP to its customers nor hinder NEP or any affiliate of NEP in maintaining proper voltage conditions. The location of the interconnection points for each Facility shall be determined prior to the commencement of the Facility’s construction by mutual agreement of the parties.

NEP shall, at Seller’s expense, provide, own, and maintain metering, telemetering and communication equipment at each of the Facilities for measuring and reporting electricity delivered to NEP and the status of switching equipment. Seller shall provide suitable space at each of the Facilities for installation of the metering, telemetering and communication equipment at no cost to NEP The metering equipment shall comply with Good Utility Practice and shall be capable of recording var flow and of segregating electricity delivered during On-Peak Periods arid Off-Peak Periods.

NEP agrees to cause its interconnection and transmission facilities to be operated and maintained in accordance with Good Utility Practice so as to permit the delivery to NEP’s System of each of the Facilities’ Net Electric Output.

Meters shall be read by Seller on the first business day of each month. The quantity of electricity delivered for sale to NEP during the preceding month shall be determined by multiplying such readings by the NEP Entitlement (expressed as a decimal). Daily meter readings and log sheets shall be recorded. If NEP so requests, one (1) copy shall be mailed to NEP each day from each of the Facilities.

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All metering equipment associated with the Facilities shall be routinely tested in accordance with Good Utility Practice, at Seller’s expense. Such routine tests shall be conducted not more often than annually. Either party may at any time require an additional test of the metering equipment, provided that the requesting party shall pay the cost of such test. If, at any time, any metering equipment is found to be inaccurate by more than two percent (2%), NEP shall cause such metering equipment to be made accurate or replaced if necessary at Seller’s expense, and meter readings for the period of inaccuracy shall be adjusted so far as the same can be reasonably ascertained, but no adjustment prior to the beginning of the preceding month shall be made by agreement of the parties. The test shall be made in such manner as may be mutually and reasonably agreed upon by the parties. Each party shall comply with any reasonable request of the other concerning the sealing of meters, the presence of a representative of the other party when the seals are broken and the tests are made, and other matters affecting the accuracy of the measurement of electricity delivered from the Facilities. Copies of the test reports shall be made available to both parties. If either party believes that there has been a meter failure or stoppage, it shall immediately notify the other.

ARTICLE IX.   CONSTRUCTION OF INTERCONNECTION FACILITIES

The interconnection facilities associated with each of the Facilities shall be constructed at Seller’s expense. NEP reserves to itself and its affiliates the construction and ownership of all necessary modifications to its system attributable to the interconnection of each of the Facilities. Seller agrees to pay NEP in advance for all costs that NEP reasonably estimates will be incurred in connection with such activities. NEP shall prepare its estimate in good faith and in accordance with Good Utility Practice. Upon completion of construction, NEP shall prepare a breakdown of all costs incurred in connection with such activities and the parties agree to make a final adjustment to correct for any overpayment or underpayment. NEP represents that in making the interconnections, it will use standard equipment customarily employed by NEP for its own system, all in accordance with Good Utility Practice.

Seller shall be responsible for construction of all other interconnection facilities associated with each of the Facilities. As soon as reasonably practicable, Seller shall furnish, for review and approval by NEP, specifications for such facilities, which approval shall not be unreasonably withheld. Responsibility for making the final interconnection between the systems is reserved exclusively to NEP or its affiliates. Prior to making such interconnections with each of the Facilities, NEP shall have the right to require Seller to provide satisfactory documentation that the Facility and the interconnection facilities constructed by Seller comply with all applicable safety and electrical codes. NEP agrees to exercise good faith in undertaking such interconnections in a timely manner.

ARTICLE X.   ACCESS TO FACILITIES

Properly accredited representatives of NEP or an Affiliate of NEP shall at all reasonable times have access to each of the Facilities to make inspections and obtain information required in connection with this Agreement. While at a Facility, such representatives shall observe such reasonable safety precautions as may be required by Seller and shall conduct themselves in a manner that will not interfere with the operation of the Facility.

ARTICLE XI.   NOTICES: REPRESENTATIVES OF THE PARTIES

Any notice, demand or request required or authorized by this Agreement to be given by one party to the other party shall be in writing. It shall either be personally delivered or mailed, by registered or certified mail, postage prepaid, to the representative of the other party designated in this ARTICLE. Any such notice, demand or request so delivered or mailed shall be deemed to be given when so delivered or mailed.

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Notices and other communications by Seller to NEP shall be addressed to:

Manager, Alternate Energy Projects

New England Power Service Company

25 Research Drive

Westborough, MA  01582

Notices, payments and other communications by NEP to Seller shall be addressed to:

Northeast Landfill Power Company

672 Jerusalem Road

Cohasset, Massachusetts 02025

Attn:      Gordon L. Deane

President

Either party may change its representative by written notice to the other.

The parties’ representatives designated above shall have full authority to act for their respective principals in all technical matters relating to the performance of this Agreement. However, they shall not have authority to amend, modify, or waive any provision of this Agreement.

ARTICLE XII.   INSURANCE, LIABILITY, INDEMNIFICATION, AND RELATIONSHIP OF PARTIES

A.           Seller shall, at its own expense, acquire and maintain. or cause Seller’s agent to acquire and maintain, throughout the term of this Agreement the following minimum insurance coverages as adjusted for inflation, as long as such coverages or reasonably similar coverages are available on reasonable commercial terms:

(i) Statutory coverage for Worker’s Compensation, and Basic Employers’ Liability Coverage with a limit no less than $500,000;

(ii) Comprehensive General Liability Coverage including Operations, Contractual Liability and Broad Form Property Damage Liability, written with limits no less than;

Bodily Injury — $3 million per occurrence

Property Damage — $1 million per occurrence

or $3 million

Combined Single Limit;

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(iii)          Comprehensive Automobile Liability Coverage, including all owned, non—owned, and hired vehicles, written with limits no less than:

Bodily Injury -                      $1 million per person/

$2 million per accident

Property Damage -               $500,000 per occurrence;

(iv) All Risk Property Coverage and Boiler and Machinery Coverage against damage to each of the Facilities in an amount not less than the full replacement cost of the Facility (to restore the Facility to its condition prior to the casualty loss) and subject to a reasonable deductible.

Such policies shall be endorsed to require that:

(1) complete copies of each inspection or other report required by or performed for the insurer shall be provided to NEP within thirty (30) days of its completion,

(2) the coverage afforded shall not be canceled or reduced without at least ninety (90) days prior written notice to NEP, and

(3) the insurance proceeds shall be applied to repair of the Facility unless Seller and NEP agree otherwise; and

(v) Business Interruption Insurance as is reasonably available under reasonable commercial terms providing funds to cover all of Seller’s costs to the extent that they would not be eliminated or reduced by the failure of each or any of the Facilities to operate (including but not limited to rent or mortgage payments, interest and principal payments on loans or bonds and salaries and wages) or a period of at least twelve (12) months after a reasonable deductible period.

Minimum insurance coverages required by this Article XII A shall be increased every five years to the nearest $100,000 based on experienced inflation.

The insurance policies specified in Clause (ii) and (iii), above, shall be endorsed naming NEP, its employees, agents, and affiliates as additional insureds with respect to any and all third party bodily injury and/or property damage claims arising from Sellers performance of this Agreement and shall require sixty (60) days written notice to be given to NEP of cancellation and/or material change in any of the policies.

Evidence of insurance for the coverages specified herein shall be provided to NEP prior to the Commencement Date of Operation. During the term of this Agreement, Seller, upon NEP’s reasonable request, shall furnish NEP with certified copies of the insurance policies described in this Article XII A.

The insurance coverages described in Clause (i) through (iii), above, shall be primary to any other coverage available to NEP or to NEP’s affiliates and shall not be deemed to limit Seller’s liability under this Agreement, except to the extent any amounts are paid by such insurance.

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B.           Notwithstanding any other provision of this Agreement to the contrary, neither NEP nor Seller, nor their respective officers, directors, shareholders, partners, agents, employees, patent or affiliates, or their respective officers, directors, shareholders, partners, agents or employees shall be liable to the other party or its parent, subsidiaries, affiliates, officers, directors, shareholders, partners, agents, employees, successors or assigns, for claims for incidental, indirect or consequential damages connected with or resulting from performance or non-performance of this Agreement, including, without limitation, claims in the nature of lost revenues, income or profits irrespective of whether such claims are based upon warranty, negligence, strict liability, contract, operation of law or otherwise. Neither shall the parent or affiliates of NEP or Seller, nor their respective officers, directors, shareholders, partners, agents or employees, be liable for claims for direct damages connected with or resulting from performance or non-performance of this Agreement.

C.           Seller agrees to defend, indemnify and save NEP, its officers, directors, shareholders, partners, employees, agents and affiliates and their officers, directors, shareholders. partners, employees and agents harmless from and against any and all claims, suits, actions or causes of action for damage by reason of bodily injury, death or damage to property caused by Seller, its officers, directors, shareholder, partners, employees, agents or affiliates or caused by or sustained on its facilities, except to the extent caused by an act of negligence or willful misconduct by an officer, director, shareholder, partner, agent, employee or affiliate of NEP, its successors or assigns.

D.           NEP agrees to defend, indemnify and save Seller, its officers, directors, shareholders, partners, employees, agents and affiliates and their officers, directors, shareholders, partners, employees and agents harmless from and against any and all claims, suits, actions, or causes of action for damage by reason of bodily injury, death or damage to property caused by NEP, its officers, directors, shareholder, partners, employees, agents or affiliates or caused by or sustained on its facilities, except to the extent caused by an act of negligence or willful misconduct by an officer, director, shareholder, partner, agent, employee or affiliate of Seller, its successors or assigns.

E.           Nothing in this Agreement shall be construed as creating any relationship between the parties other than that of independent contractors for the sale and purchase of electricity generated by the Facilities.

ARTICLE XIII.   ASSIGNMENT

Neither party shall assign, pledge or otherwise transfer this Agreement or any right or obligation under this Agreement without first obtaining the other party’s written consent, which shall not be unreasonably withheld; except that Seller may assign its interests in this Agreement, in whole or in part, to a financial institution in connection with the construction and/or long term financing of the Facilities or modification thereof without NEP’s consent and NEP may assign its rights and obligations to any Affiliate of NEP within the New England Electric System without Seller’s consent.

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ARTICLE XIV.   FORCE MAJEURE

A.           The parties shall be excused from performing their respective obligations hereunder and shall not be liable in damages or otherwise, if and only to the extent that they are unable to so perform or are prevented from performing by an event of force majeure, including, without limitation, storm, flood, lightning, draught, earthquake, fire, explosion, equipment failure, civil disturbance, labor dispute, act of God or the public enemy, action of a court or public authority, or any other cause beyond their control, including, without limitation, shutdown of, or limited operation of, facilities due to breakdown or unscheduled repair or maintenance.

No event caused by or resulting from (i) Seller’s or NEP’s failure to operate and maintain their respective facilities in accordance with Good Utility Practice or (ii) the reduction of the landfill gas supply to the Facilities shall be deemed to be an event of force majeure under this ARTICLE XIV.

B.           If either party shall rely on the occurrence of an event or condition described in ARTICLE XIV A. above, as a basis for being excused from performance of its obligations under this Agreement, then the party relying on the event or condition shall (i) provide prompt notice to the other party of the occurrence of the event or condition giving an estimation of its expected duration and the probable impact on the performance of its obligations hereunder, (ii) exercise all reasonable efforts to continue to perform its obligations hereunder, (iii) expeditiously take action to correct or cure the event or condition excusing performance, (iv) exercise all reasonable efforts to mitigate or limit damages to the other party to the extent such action will not adversely affect its own interests, and (v) provide prompt notice to the other party of the cessation of the event or condition giving rise to its excuse from performance.

ARTICLE XV.   WAIVERS

The failure of either party to insist in any one or more instance(s) upon strict performance of any of the provisions of this Agreement or to take advantage of any of its rights under this Agreement shall not be construed as a general waiver of any such provision or the relinquishment of any such right, but the same shall continue and remain in full force and effect, except with respect to the particular instance or instances.

ARTICLE XVI.   REGULATION

This Agreement and all rights, obligations, and performances of the parties hereunder, are subject to all applicable state and Federal laws, and to all duly promulgated orders and other duly authorized action of any governmental authority having jurisdiction.

ARTICLE XVII.   INTERPRETATION,  DISPUTE  RESOLUTION

The interpretation and performance of this Agreement shall be in accordance with and controlled by the law of The Commonwealth of Massachusetts, the State or Federal Courts in which shall have exclusive original jurisdiction over cases and controversies arising hereunder.

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ARTICLE XVIII.   PRIOR AGREEMENT SUPERSEDED

This Agreement constitutes the entire agreement between the parties hereto relating to the subject matter hereof and supersedes all previous agreements, discussions, communications and correspondence with respect to the subject matter hereof.

ARTICLE XIX.   USE OF LANDFILLS

Seller represents and warrants that it will secure exclusive rights to purchase the landfill gas produced at each of the currently permitted landfill sites on which the Facilities will be located prior to the Commencement Date of Operation. Except as provided in Article IV and Article V above, neither Seller, nor its officers, directors, shareholders, partners, agents, employees, parent or affiliate, or their respective officers, directors, shareholders, partners, agents or employees, shall directly or indirectly, sell such landfill gas to others, assign to others or waive its rights to such landfill gas, or use such landfill gas to generate electricity for sale.

ARTICLE XX.   SEVERABILITY

If any provision or provisions of this Agreement shall be held invalid, illegal, or unenforceable, the validity, legality, and enforceability of the remaining provisions shall in no way be affected or impaired thereby.

ARTICLE XXI.   MODIFICATIONS

No modification to this Agreement shall be binding on either party unless it shall be in writing and signed by both  parties.

ARTICLE XXII.   COUNTERPARTS

This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written.

NEW ENGLAND POWER COMPANY

By

Title:

NORTHEAST LANDFILL POWER COMPANY

By

Title:

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Page 1 of 2

APPENDIX A

NEP uses a computerized power cost estimation program to establish a relationship between its average and incremental fuel costs. The program computes the probable fuel costs annually, on a forward looking basis. Monthly load duration curves, fuel costs, scheduled unit outages, forced unit outage rates, and unit heat rates are considered in a hypothetical unit dispatch to meet NEP’s annual load on a month-by-month basis. From these data, a relationship between NEP's average and incremental fuel cost is established.

By way of example, a summary of the calculation of NEP’s 1986 annual factors is attached. Three computer runs were made. The first run used NEP’s 1986 estimated load duration curve. The second run was made adding a 100 MW increment of load to all on-peak and off-peak hours. The third run was made subtracting a 100 MW decrement of load from all on-peak and off-peak hours.

The first run provided NEP’s 1986 total fuel cost, which was divided by NEP 1986 energy output to yield its 1986 estimated average fuel cost per MWH. The on-peak incremental fuel cost was determined by dividing the cost of fuel for the sum of the 100 MW increment and the 100 MW decrement of load during the on-peak periods by the energy produced during said periods, to yield NEP’s on-peak incremental fuel cost.  This, in turn, yielded the 1986 on-peak factor. The same procedure, using off-peak components, was used to establish NEP’s 1956 off-peak factor.

Each month the 1986 factors are multiplied by NEP average fuel cost -- as filed with the Federal Energy Regulatory Commission -- to determine NEP’s on-peak and off-peak incremental fuel costs.

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Page 2 of 2

APPENDIX A

METHODOLOGY FOR CALCULATING

NEP’s 1986 ANNUAL FACTORS

DOLLARS

Estimate NEP 1986 total fuel cost with . . . .

(1)           …           no additional energy (“T”).

(2) … 100 MW of load added to all on-peak hours (“T_on + ”) and with 100 MW of load added to all off-peak hours (“T_off + ”).

(3) … 100 MW of load subtracted from all on-peak hours (“T_on - ”), and with 100 MW of load subtracted from all off-peak hours (“T_off - ”).

ENERGY

Estimate NEP’s 1986 energy production (“E”).

Energy added for on-peak increment/decrement (“E_on”).

Energy added for off-peak increment/decrement (“E_off”).

$/MWH

1986 Estimated Average Fuel Cost = T = $413,198 x 10³ = $21.20/MWH

     E        19,490    GWH

1986 Estimated On-Peak Incremental Cost =

T_on+ - T_on-   = $431,218 – 396,370 = $43.04/MWH

2 E_on                           2 x 404.8

1986 Estimated Off-Peak Incremental Cost =

T_off+ - T_off-   = $428,321 – 398.9 = $31.17/MWH

2 E_off                             2 x 471.2

On-Peak Factor =                 43.04      =           2.03

21 .20

Off-Peak Factor =                 31.17     =           1.47

21.20

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APPENDIX B

EXHIBIT 1:            PROJECTED OPERATING CAPACITY AND PRODUCTION

Worcester, MA, Johnston, RI and Billerica, MA  Landfill Gas-to-Energy Projects

Cash Flow Year Calendar Year	1 1987	2 1988	3 1989	4 1999	5 1991	6 1992	7 1993	8 1994	9 1995	10 1996	11 1997	12 1998	13 1999	14 2000	15 2001
WORCESTER
Operating Capacity (in kW)	3,810	3,576	3,357	3,152	2,940	2,700	2,499	2,235	1,960	1,755	1,537	900	900	950	790
kWhr Production (1000 kWhrs)	14,105	20,195	26,469	24,051	23,179	21,916	19,701	17,622	15,453	13,057	12,116	7,726	7,726	7,553	6,271
BILLERICA
Operating Capacity (in kW)	2,940	2,852	2,659	2,497	2,344	1,960	1,960	1,770	1,574	900	900	900	902	759	0
kWhr Production (1000 kWhrs)	7,297	22,331	20,963	19,602	10,482	15,453	15,453	13,957	12,411	7,726	7,726	7,726	7,113	5,902	0
JOHNSTON
Operating Capacity (in kW)	2,800	5,600	5,600	5,600	6,580	7,560	7,560	7,560	8,540	9,520	9,519	10,032	10,174	10,415	10,863
kWhr Production (1000 kWhrs)	5,212	44,150	44,150	44,150	51,077	59,603	59,603	59,603	67,329	75,056	75,051	79,070	80,211	82,114	85,651
TOTALS
Total Operating Capacity	9,550	12,009	11,616	11,249	11,064	12,300	12,019	11,565	12,074	12,255	12,036	11,972	12,056	12,132	11,661
Total kWhr Production (1000 kWhrs)	26,694	94,676	91,582	88,604	95,538	96,972	94,757	91,102	95,195	96,619	94,896	94,543	95,050	95,650	91,932

Cash Flow Year Calendar Year	16 2002	17 2003	18 2004	19 2005	20 2006	21 2007	22 2008	23 2009	24 2010	25 2011	26 2012	27 2013	28 2014	29 2015	30 2016
WORCESTER
Operating Capacity (in kW)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
kWhr Production (1000 kWhrs)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
BILLERICA
Operating Capacity (in kW)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
kWhr Production (1000 kWhrs)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
Johnston
Operating Capacity (in kW)	11,107	11,366	11,400	11,400	11,400	11,366	11,107	10,054	10,607	10,367	9,941	9,733	9,491	9,274	9,063
kWhr Production (1000 kWhrs)	87,564	89,610	90,508	90,500	90,500	89,610	87,364	85,571	83,629	81,735	78,375	76,577	74,824	75,116	71,452
TOTALS
Total Operating Capacity	11,107	11,366	11,400	11,400	11,400	11,366	11,107	10,054	10,607	10,367	9,941	9,733	9,491	9,274	9,063
Total kWhr Production (1000 kWhrs)	87,564	89,610	90,508	90,500	90,500	89,610	87,364	85,571	83,629	81,735	78,375	76,577	74,824	75,116	71,452

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Page 1 of 2

APPENDIX C

APPROVED FINANCING, FUEL. & OPERATING EXPENSES

SENIOR TO ESCROW ACCOUNT

The following monthly expenses of Northeast Landfill Power Company shall be senior to the funding of the Escrow Account required under the provisions of Article VII (C).

1.           Financing Costs -- As provided in the loan agreement(s) and/or lease agreement(s) between Seller and project lender(s) and/or lessor(s) and summarized as follows:

(to be completed by Seller and approved by NEP, which approval shall not be unreasonably withheld, prior to Commencement Date of Operation)

2.           Contract Operation & Maintenance Expenses -- As provided in the operation and maintenance agreement(s) between Seller and its contract operator(s) and summarized below:

(to be completed by Seller and approved by NEP, which approval shall not be unreasonably withheld, prior to Commencement Date of Operation)

3.           Fuel Cost/Royalty -- The minimum gas purchase price as provided in the gas sales agreements between Seller and the Northeast Landfill Gas Company plus any rents or royalties due the landfill owner by Seller but not in excess of a monthly limit determined in accordance with the following formula:

ML            = ($10,000  x   S)  +  A  +  B  +  C

   T

Where “ML” is the monthly limit:

“S” is as defined in ARTICLE VI B of this Agreement;

“T” is as defined in ARTICLE VI B of this Agreement;

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Page 2

“A” is 12.5% of Seller’s revenues under this Agreement derived from electricity produced at the Billerica Facility;

“B” is 17.5% of Seller’s revenues under this Agreement derived from electricity produced at the Worcester Facility; and

“C” is 15% of Seller’s revenues under this Agreement derived from electricity produced at the Johnston Facility.

4.           Insurance & Local Taxes -- The actual cost of insuring the project as required by Project Lenders(s), lessor(s), or this Agreement plus the cost of local excise, property, or other taxes assessed against the project, but not federal income taxes.

In addition, if, under the provisions of ARTICLE VII A (3) or (6), Seller instructs NEP to reduce the monthly payments otherwise due Seller from NEP under ARTICLE VI in order to avoid the occurrence of an Event of Default, then all reasonable expenses incurred by Seller in efforts to cure the circumstances underlying the potential Event of Default or to otherwise provide assurance to NEP of Seller’s ability to perform its obligations under this Agreement shall be senior to the funding of the Escrow Account required under the provisions of ARTICLE VII C.

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Amendment to Power Purchase Agreement

This Amendment (‘Amendment”), dated as of December 1, 1989, amends the Agreement dated as of November 6, 1987, between New England Power Company (“NEP”) and Northeast Landfill Power Company (“NLP”), as assigned by NEP to Massachusetts Electric Company (“MEC”) by assignment dated November 18, 1987, as reassigned by MEC to NEP by reassignment dated February 12, 1988, and as assigned by NLP to Northeast Landfill Power Joint Venture, an Illinois partnership (“Seller”) by assignment dated as of March 31, 1989 (the “Power Purchase Agreement”).

Basic Understandings

Seller is about to obtain its financing for construction of the Facility pursuant to a certain Loan Agreement (“Loan Agreement”), dated as of August 2, 1989 by and between State Street Bank and Trust Company (the “Bank”) and Seller. Before financing can be obtained from the Bank, the Power Purchase Agreement needs to be amended to address certain issues that need clarification.

Accordingly, the parties agree to amend the Power Purchase Agreement as follows:

Section 1.              Rights of the Bank Upon Seller’s Default

(a)           The Bank has the right (but not the obligation) to cure any default on behalf of Seller and exercise, to the extent expressly permitted by the Borrower’s Collateral Assignment and Security Agreement (as such terms are defined in the Loan Agreement), any rights of Seller under the Power Purchase Agreement within the cure periods specified in the Power Purchase Agreement.

(b)           NEP will send copies of any default notices under the Power Purchase Agreement to the Bank, at the following address:

State Street Bank and Trust Company

225 Franklin Street

Boston, MA. 02101

Attention: Project Finance Department

(c)           NEP shall incur no liability for inadvertent failure to send default notices to the Bank, but any time limit specified in the Power Purchase Agreement for curing an Event of Default shall not begin to run for the Bank until the Bank receives a copy of the notice.

(d)           NEP will not exercise any of its rights and remedies with respect to default before the expiration of the Bank’s cure period (as specified above).

Section 2                Assignments by the Bank

If there is an Event of Default under the Loan Agreement, the Bank may (i) exercise Seller’s rights under the Power Purchase Agreement, or (ii) assign or sublease any or all of Seller’s rights, title and interest in, to and under the Power Purchase Agreement to any third party (or parties), as long as such third party:

(a) assumes all of the obligations of Seller under the Power Purchase Agreement (including any accrued liability in respect of the Aggregate Differential); and

(b) is at least as experienced and capable of owning and operating (or causing the operation of) the Facility as Seller.

- 2 -

Section 3. Definition of “Facility”

As of the Commencement Date of Operation, the landfill gas electric generation project at the landfill located in Johnston, Rhode Island will be the only project which will be initially providing electricity to NEP under the Power Purchase Agreement.  Therefore, the Power Purchase Agreement is amended so that the terms “Facilities” and “Facility” shall each mean the landfill gas-fired electric generation project at the landfill located in Johnston, Rhode Island; provided, however, that if and when the proposed landfill gas-fired electric generation project at the landfill located in Worcester, Massachusetts becomes operational, then the term “Facilities” shall mean both the landfill gas-fired electric generation projects located at landfills in Johnston, Rhode Island and Worcester, Massachusetts and the term “Faci1ity” shall mean either of such projects.

Section 4.               Waiver of Termination Right

NEP waives any right it may otherwise have and agrees not to terminate the Power Purchase Agreement pursuant to the third paragraph of Article III; provided that the “Commencement Date of Operation” occurs before July 1, 1990.

Section 5.               Substitution of the word “Account”

The first word in the last line of the first paragraph of Article VII C is amended by deleting the word “Agreement” and substituting the word “Account”.

Section 6.               Changing the “Commencement Date of Operation”

The definition of “Commencement Date of Operation” is amended by deleting the third paragraph of Article II of the Power Purchase Agreement and by substituting therefor the following sentence: “Commencement Date of Operation” shall mean the later to occur of (i) substantial completion of Phase 1 at the Johnston Facility as per Seller’s construction contract for the Johnston Facility, or (ii) the initial date on which Seller generates at least five megawatts (5MW) of electricity at the Johnston Facility continuously for a period of eight (8) consecutive hours.

- 3 -

Section 7.               Substitution of Appendix C

Appendix C to the Power Purchase Agreement is deleted and a new Appendix C (attached to this Amendment as Exhibit A) is substituted in its place.

Section 8.               Insurance Proceeds

Pursuant to Article XII A (iv) (3) of the Power Purchase Agreement, the insurance proceeds shall be applied during the term of the Loan Agreement between Seller and the Bank in accordance with Sections 5.9(a)(iii) and 5.9(d) of the Loan Agreement.

Section 9.               Interconnection Facilities

If NEP does not complete construction of the interconnection facilities associated with Seller’s Facility on or before December 15, 1989, the December 31, 1989 deadline specified for the Commencement Date of Operation in Article VII D., paragraph (iii) on page 20, will be extended by the number of days beyond December 15, 1989 that the interconnection was completed.

The parties have caused their authorized representatives to execute this Amendment on the date(s) set forth below, which Amendment may be signed in counterparts so that each party may retain a signed original. All counterparts will constitute one agreement binding on each of the parties.

- 4 -

NEW ENGLAND POWER COMPANY

By:_________________________________

Title: _______________________________

Date: _______________________________

NORTHEAST LANDFILL POWER JOINT VENTURE

By: Northeast Landfill Power Company, a general partner

By:_______________________________

Gordon L. Deane

Title: President

Date: ______________________

- 5 -

EXHIBIT A

APPENDIX C

PART I                  Cash Flow Priorities

The Borrower will use its Cash Flow, and will only make payments and distributions to any Person, in accordance with the priority of payments set forth below on a monthly basis:

(a)           first, principal, interest, fees and expenses due to the Bank pursuant to the terms of the Loan Agreement or any of the Collateral Documents (as such term is defined in the Loan Agreement);

(b)           second, senior operating expenses incurred in the ordinary course of business (other than item (c) below) which are due to RISWMC under the Landfill Gas Lease Agreement, the Town under the Taxes Agreement, payments for insurance, legal and accounting fees incurred in the ordinary course of Borrower’s business, and base gas payments due to GASCO under the Sublease Agreement, all in the preceding order;

(c)           third, senior operating expenses incurred in the ordinary course of business which are due to WPI under the Operating Agreement (other than bonus and penalty payments and other subordinated payments);

(d)           fourth, payments required to be made to the Escrow Account under the Power Purchase Agreement (this Escrow Account will be funded separately);

(e)           fifth, payments to Borrower’s debt reserve account and thereafter to Borrower’s maintenance reserve account at the Bank pursuant to Section 5.12 of the Loan Agreement to the extent the debt reserve account has been drawn upon to make the payments described in item (a) or the maintenance reserve account has been drawn upon to make the payments described in items (b) and (c) above;

(f)           sixth, payments for management fees due to NLP and HW Landfill under the Management Agreements;

(g)           seventh, payments for the initial funding of the Borrower’s debt reserve account and thereafter for the initial funding of the Borrower’s maintenance reserve account, with the Bank, each in accordance with Section 5.12 of the Loan Agreement.

(h)           eighth, additional and excess gas payments due to Gasco under the Sublease Agreement;

(i)           ninth, bonus payments or previously subordinated payments due to WPI under the Operating Agreement;

The balance of Cash Flow after payments described in subparagraphs (a) through (i) above is referred to as “Cash Flow Available for Distribution” which shall be used in accordance with Section 5.27 of the Loan Agreement.

- 6 -

PART II                 Special Withdrawals From the Escrow Account

As agreed to by the parties, the Escrow Account will be separately funded by direct payments by NEP of 5% of monthly revenues due to Seller. If, however, after a monthly payment of 5% has been made, it is determined that there were not enough revenues from the remaining 95% of the revenues due to Seller to cover the items described in (a), (b), and (c) of Part I above, NEP and Seller agree to the following:

(i) Seller shall send a written notice to NEP, stating that there were insufficient revenues to cover the items to be funded in subparagraph (a), (b) and (c) of Part I of this Appendix C (“Shortfall”).

(ii) With the notice, Seller shall include documentation of how much in additional funds is needed to cover the Shortfall for the month.

(iii) If Seller’s documentation is accurate, NEP and Seller will send a joint notice to the Escrow Agent, requesting a withdrawal from the Escrow Account equal to (i) the amount needed to cover the Shortfall for the month, or (ii) the total of the month’s 5% payment, whichever amount is less. The Escrow Agent will be directed to make payment of the withdrawal into an account designated by Seller.

The special withdrawals described above only may be made to cover the Shortfall for a particular month. Shortfalls may not be accumulated from month to month in cases where the total of the month’s 5% payment to the Escrow Account does not cover the entire month’s Shortfall.

Part III                   Definitions

For the purpose of this Appendix C, the following terms shall have the following meanings:

“Cash Flow” means for a particular fiscal period of the Borrower, revenues received by the Borrower in the ordinary course of business from its operation of the electrical generation facility at the Johnston landfill and from Gasco pursuant to the terms of the Sublease Agreement (but excluding extraordinary payments contemplated by Section 2.9(a)(i) and (a)(ii) of the Loan Agreement).

“Gasco” means Central Gas Limited Partnership, an Illinois limited partnership, and its successors.

“H-W” means Hayden-Wegman, Inc., a New York corporation, and its successors.

“HW Landfill” means HW Landfill Gas, Inc., a Delaware corporation and its successors.

“Landfill Gas Lease Agreement” means the Landfill Gas Lease Agreement dated May 1, 1987 between RISWMC and H-W, as supplemented by the Supplemental Agreement, dated May 1, 1987, between RISWMC and H-W, as amended by the Amendment to Supplement, dated July 28, 1988, between RISWMC and H-W, as assigned by H-W to the Borrower by Assignment, dated as of March 31, 1989, and as amended by the Amendment dated as of March 31, 1989 between RISWMC and H-W and consented to by RISWMC as of March 31, 1989.

-7 -

“Management Agreements” means the Management Agreement between the Borrower and NLP and the Management Agreement between the Borrower and H-W Landfill, each to be entered into prior to the initial construction borrowing under the Loan Agreement in the form approved in writing by the Bank, providing for the management of the Borrower.

“Operating Agreement” has the meaning set forth in Section 3.2(1) of the Loan Agreement, or any substitution thereof if approved in writing by the Bank pursuant hereto.

“Person” means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including with limitation a government or political subdivision or an agency or instrumentality thereof.

“RISWMC” means Rhode Island Solid Waste Management corporation, a corporation created by the State of Rhode Island.

“Sublease Agreement” means the Landfill Gas Contract and Sublease Agreement dated as of March 31, 1989 between the Borrower and Gasco pertaining to the Johnston facility.

“Taxes Agreement” means the Agreement dated May 1, 1987 by and among the Town, RISWMC and H-W for Payment in Lieu of Taxes for the landfill gas collection and processing project, as will be assigned to the Borrower by assignment prior to the initial construction borrowing under the Loan Agreement.

“Town” means the Town of Johnston, Rhode Island, a political subdivision of the State of Rhode Island.

“WPI” means Waukesha Pearce Industries, Inc., a Texaco corporation, and its successors.

- 8 -

SECOND AMENDMENT TO POWER PURCHASE AGREEMENT

This Amendment (“Amendment”), dated as of October 31, 1991 amends the Agreement dated as of November 6, 1987, between New England Power Company (“NEP”) and Northeast Landfill Power Company (“NLP”), as assigned by NEP to Massachusetts Electric Company (“MEC”) by assignment dated November 18, 1987, as reassigned by MEC to NEP by reassignment dated February 12, 1988, as assigned by NLP to Northeast Landfill Power Joint Venture, an Illinois partnership (“Seller”), by assignment dated as of March 31, 1989 and as amended by an Amendment to Power Purchase Agreement dated December 1, 1989 (the “Power Purchase Agreement”).

Basic Understandings

Seller is about to obtain its term financing for the Facility pursuant to a certain Note Purchase Agreement (“Note Purchase Agreement”), dated as of October 1, 1991 by and among Northwestern National Life Insurance Company, Northern Life Insurance Company and The North Atlantic Life Insurance Company of America (the “Purchasers”) and Seller. Before financing can be obtained from the Purchasers, the Power Purchase Agreement needs to be amended to address certain issues that need clarification.

Accordingly, the parties agree to amend the Power Purchase Agreement as follows:

Section 1.               Rights of the Purchasers Upon Seller’s Default

(a)           The Purchasers have the right (but not the obligation) to cure any default on behalf of Seller and exercise, to the extent expressly permitted by the Project Agreements Assignment and the Security Agreement (as such terms are defined in the Note Purchase Agreement), any rights of Seller under the Power Purchase Agreement within the cure periods specified in the Power Purchase Agreement.

(b)           NEP will send copies of any default notices under the Power Purchase Agreement to the Purchasers, at the following address:

c/o Washington Square Capital, Inc.

Northstar West, Suite 1500

625 Marquette Avenue South

Minneapolis, Minnesota 55402

Attention: James V. Wittich

(c)           NEP shall incur no liability for inadvertent failure to send default notices to the Purchasers, but any time limit specified in the Power Purchase Agreement for curing an Event of Default shall not begin to run for the Purchasers until the Purchasers receive a copy of the notice.

(d)           NEP will not exercise any of its rights and remedies with respect to default before the expiration of the Purchaser’s cure period (as specified above).

Section 2.               Assignments by the Purchasers

If there is an Event of Default under the Note Purchase Agreement, the Purchasers may (i) exercise Sellers rights under the Power Purchase Agreement, or (ii) assign or sublease any or all of Seller’s rights, title and interest in, to and under the Power Purchase Agreement and the Facilities to any third party (or parties), as long as such third party:

(a) assumes all of the obligations of Seller under the Power Purchase Agreement (including any accrued liability in respect of the Aggregate Differential); and

(b) is at least as experienced and capable of owning and operating (or causing the operation of) the Facility as Seller.

Section 3.               Substitution of Appendix C

Appendix C to the Power Purchase Agreement is deleted and a new Appendix C (attached to this Amendment as Exhibit A) is substituted in its place.

Section 4.               Insurance Proceeds

Pursuant to Article XII A (iv)(3) of the Power Purchase Agreement, the parties agree that the insurance proceeds shall be applied during the term of the Note Purchase Agreement between Seller and the Purchasers in accordance with paragraph 9 of the Note Purchase Agreement.

Section 5.               Effect on Prior Amendment

This Amendment supersedes the provisions of Sections 1, 2, 7 and 8 of the Amendment to Power Purchase Agreement dated as of December 1, 1989 (the “Prior Amendment”), which Sections shall be of no further force or effect.  All other provisions of the Prior Amendment shall remain in full force and effect with no other modifications or waiver.

The parties have caused their authorized representatives to execute this Amendment on the date(s) set forth below, which Amendment may be signed in counterparts so that each party may retain a signed original. All counterparts will constitute one agreement binding on each of the parties.

2

NEW ENGLAND POWER COMPANY
By:
Title:
Date:
NORTHEAST LANDFILL POWER JOINT
	VENTURE, an Illinois general
	partnership
By:	Northeast Landfill Power
	Company, a Massachusetts
	corporation and general
	partner
By:
Title:
Date:
And by:		Johnston Natural Power
		Corporation, a Delaware
		Corporation and general
		Partner
By:
Title:
Date:

3

EXHIBIT A TO SECOND

AMENDMENT TO POWER

PURCHASE AGREEMENT

APPENDIX C

PART I                   Cash Flow Priorities

The Seller will use its Cash Flow, and will only make payments and distributions to any Person, in accordance with the priority of payments set forth below on a monthly basis:

(a)           first, principal, interest, fees and expenses due to the Purchasers pursuant to the terms of the Note Purchase Agreement or any of the Note Documents (as such term is defined in the Note Purchase Agreement);

(b)           second, senior operating expenses incurred in the ordinary course of business (other than item (c) below) which are due to RISWMC under the Landfill Gas Lease Agreement, the Town under the Taxes Agreement, payments for insurance, legal and accounting fees incurred in the ordinary course of Seller’s business, and base gas payments due to GASCO under the Sublease Agreement, all in the preceding order;

(c)           third, senior operating expenses incurred in the ordinary course of business which are due to WPI under the O&M Agreement (other than bonus and penalty payments and other subordinated payments);

(d)           fourth, payments requited to be made to the Escrow Account under the Power Purchase Agreement (this Escrow Account will be funded separately); and

(e)           fifth, the balance of Cash Flow after payments described in subparagraphs (a) through (d) above shall be applied in compliance with the Note Purchase Agreement.

PART II                Special Withdrawals From the Escrow Account

As agreed to by the parties, the Escrow Account will be separately funded by direct payments by NEP of 5% of monthly revenues due to Seller. If, however, after a monthly payment of 5% has been made, it is determined that there were not enough revenues from the remaining 95% of the revenues due to Seller to cover the items described in (a), (b), and (c) of Part I above, NEP and Seller agree to the following:

(i) Seller shall send a written notice to NEP, stating that there were insufficient revenues to cover the items to be funded in subparagraph (a), (b) and (c) of Part I of this Appendix C (“Shortfall”).

(ii) With the notice, Seller shall include documentation of how much in additional funds is need to cover the Shortfall for the month.

(iii) If Seller’s documentation is accurate, NEP and Seller will send a joint notice to the Escrow Agent, requesting a withdrawal from the Escrow Account equal to (i) the amount needed to cover the Shortfall for the month, or (ii) the total of the months 5% payment, whichever amount is less. The Escrow Agent will be directed to make payment of the withdrawal into an account designated by Seller.

4

The special withdrawals described above only may be made to cover the Shortfall for a particular month. Shortfalls may not be accumulated from month to month in cases where the total of the month’s 5% payment to the Escrow Account does not cover the entire month’s Shortfall.

Part III                 Definitions

For the purpose of this Appendix C, the following terms shall have the following meanings:

“Cash Flow” means for a particular fiscal period of the Seller, revenues received by the Seller in the ordinary course of business from its operation of the electrical generation facility at the Johnston landfill and from Gasco pursuant to the terms of the Sublease Agreement.

“Gasco” means Central Gas Limited Partnership, an Illinois limited partnership, and its successors.

“H-W” means Hayden-Wegman, Inc., a New York corporation, and its successors.

“JNPC” means Johnston Natural Power Corporation, a Delaware corporation (f/n/a HW Landfill Gas, Inc.), and its successors.

“Landfill Gas Lease Agreement” means the Landfill Gas Lease Agreement dated May 1, 1987 between RISWMC and H-W, as supplemented by the Supplemental Agreement, dated May 1, 1987, between RISWMC and H-W, as amended by the Amendment to Supplement, dated July 28, 1988, between RISWMC and H-W, as assigned by H-W to the Seller by Assignment, dated as of March 31, 1989, as amended by the Amendment dated as of March 31, 1989 between RISWMC and H-WS and consented to by RISWMC as of March 31, 1989, and as amended by the Amendment dated as of October 31, 1991 between RISWMC and Seller.

“Management Agreements” means the Management Agreement between the Seller and NLPC dated October 31, 1989, and the Management Agreement between the Seller and JNPC dated October 31, 1989, providing for the management of the Borrower.

“NLPC” means Northeast Landfill Power Company, a Massachusetts corporation, and its successors.

“O&M Agreement” has the meaning set forth in the Note Purchase Agreement.

“Person” means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including with limitation a government or political subdivision or an agency or instrumentality thereof.

5

“RISWMC” means Rhode Island Solid Waste Management corporation, a corporation created by the State of Rhode Island.

“Sublease Agreement” means the Landfill Gas Contract and Sublease Agreement dated as of March 31, 1989 between the Seller and Gasco pertaining to the Johnston facility.

“Taxes Agreement” means the Agreement dated May 1, 1987 by and among the Town, RISWMC and H-W for Payment in Lieu of Taxes for the landfill gas collection and processing project, as assigned to the Seller by assignment dated _______________.

“Town” means the Town of Johnston, Rhode Island, a political subdivision of the State of Rhode Island.

“WPI” means Waukesha-Pearce Industries, Inc., a Texas corporation, and its successors.

429 9R

6

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

Subsidiary	Jurisdiction of Organization
JRW Associates, L.P.	California
RW Central Valley, Inc.	California
Byron Power Partners, L.P.	California
RW Byron, Inc.	California
Ridgewood Providence Power Partners, L.P.	Delaware

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Randall D. Holmes, certify that:

1. I have reviewed this annual report on Form 10-K of Ridgewood Electric Power Trust III;

2. Based on my knowledge, this 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 report;

3. Based on my knowledge, the financial statements, and other financial information included in this 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 report;

4. The registrant’s other certifying officer(s) 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 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 this report is being prepared;

(b)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c)   Disclosed in this 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(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(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.

/s/ Randall D. Holmes
Name:	Randall D. Holmes
Title:	Chief Executive Officer
	(Principal Executive Officer)
Dated:	December 13, 2007

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Jeffrey H. Strasberg, certify that:

1. I have reviewed this annual report on Form 10-K of Ridgewood Electric Power Trust III;

2. Based on my knowledge, this 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 report;

3. Based on my knowledge, the financial statements, and other financial information included in this 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 report;

4. The registrant’s other certifying officer(s) 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 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 this report is being prepared;

(b)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c)   Disclosed in this 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(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(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.

/s/ Jeffrey H. Strasberg
Name:	Jeffrey H. Strasberg
Title:	Executive Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)
Dated:	December 13, 2007

EX-32

Exhibit 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Annual Report on Form 10-K of Ridgewood Electric Power Trust III (the “Trust”) for the fiscal year ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned officers of the Trust hereby certifies, pursuant to 18 U.S.C. (section) 1350, as adopted pursuant to (section) 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

/s/ Randall D. Holmes
Name:	Randall D. Holmes
Title:	Chief Executive Officer (Principal Executive Officer)
Dated:	December 13, 2007
/s/ Jeffrey H. Strasberg
Name:	Jeffrey H. Strasberg
Title:	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
Dated:	December 13, 2007

EX-99.1

Exhibit 99.1

FINANCIAL STATEMENTS AND

REPORT OF INDEPENDENT CERTIFIED

PUBLIC ACCOUNTANTS

RIDGEWOOD PROVIDENCE POWER

PARTNERS, L.P.

December 31, 2005, 2004 and 2003

(As restated)

C O N T E N T S

	Page
Report of Independent Certified Public Accountants	3
Financial Statements
Balance Sheets	4
Statements of Operations	5
Statement of Changes in Partners’ Equity	6
Statements of Cash Flows	7
Notes to Financial Statements	8 - 19

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

The Partners

Ridgewood Providence Power Partners, L.P.

We have audited the accompanying balance sheets of Ridgewood Providence Power Partners, L.P. (a Delaware limited partnership) as of December 31, 2005, 2004 and 2003, and the related statements of operations, changes in partners’ equity and cash flows for the years then ended.  These financial statements are the responsibility of the Partnership’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America as established by the American Institute of Certified Public Accountants.  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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also 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, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Ridgewood Providence Power Partners, L.P. as of December 31, 2005, 2004 and 2003, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements as of and for the year ended December 31, 2003 have been restated as discussed in Note B to the financial statements.

/s/ GRANT THRONTON LLP

Edison, New Jersey

September 25, 2007

- 3 -

Ridgewood Providence Power Partners, L.P.

BALANCE SHEETS

December 31,

(in thousands)

ASSETS	2005		2004		2003
					(Restated)
Current assets
Cash and cash equivalents	$	607	$	699	$	706
Restricted cash		-		-		757
Trade receivables		1,956		1,356		937
Due from affiliates		20		-		206
Other current assets		92		96		66
Total current assets		2,675		2,151		2,672
Plant and equipment, net		9,349		10,232		11,027
Electric power sales contract, net		2,460		3,064		3,667
Security deposit		405		300		-
Total assets	$	14,889	$	15,747	$	17,366
LIABILITIES AND PARTNERS’ EQUITY
Liabilities
Accounts payable and accrued expenses	$	270	$	140	$	142
Accrued royalties		409		357		222
Due to affiliates		1,233		1,049		760
Notes payable		-		-		867
Total liabilities		1,912		1,546		1,991
Commitments and contingencies
Partners’ equity		12,977		14,201		15,375
Total liabilities and partners’ equity	$	14,889	$	15,747	$	17,366

The accompanying notes are an integral part of these statements.

- 4 -

Ridgewood Providence Power Partners, L.P.

STATEMENTS OF OPERATIONS

Year ended December 31,

(in thousands)

	2005			2004			2003
							(Restated)
Power generation revenue	$	7,331		$	7,457		$	7,227
Renewable attribute revenue		4,014			4,177			804
Sublease revenue		571			571			554
Total revenues		11,916			12,205			8,585
Cost of revenues		8,934			8,949			6,936
Gross profit		2,982			3,256			1,649
Operating expenses (income)
General and administrative expenses		116			23			83
Other operating income		-			-			(163	)
Total operating expenses (income), net		116			23			(80	)
Income from operations		2,866			3,233			1,729
Other income (expense)
Interest income		8			1			9
Interest expense		(13	)		(14	)		(130	)
Total other expense, net		(5	)		(13	)		(121	)
Net income	$	2,861		$	3,220		$	1,608

The accompanying notes are an integral part of these statements.

- 5 -

Ridgewood Providence Power Partners, L.P.

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2003, 2004 and 2005

(in thousands)

	Total
	partners’ equity
Partners’ equity, January 1, 2003, as restated	$	15,662
Cash distributions		(1,895	)
Net income for the year, as restated		1,608
Partners’ equity, December 31, 2003, as restated		15,375
Cash distributions		(4,394	)
Net income for the year		3,220
Partners’ equity, December 31, 2004		14,201
Cash distributions		(4,085	)
Net income for the year		2,861
Partners’ equity, December 31, 2005	$	12,977

The accompanying notes are an integral part of this statement.

- 6 -

Ridgewood Providence Power Partners, L.P.

STATEMENTS OF CASH FLOWS

Year ended December 31,

(in thousands)

	2005			2004			2003
							(Restated)
Cash flows from operating activities
Net income	$	2,861		$	3,220		$	1,608
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		1,390			1,407			1,406
Reduction in rotable spare parts		97			27			(99	)
Changes in assets and liabilities
Trade receivables		(600	)		(419	)		283
Other current assets		4			(30	)		273
Security deposit		(105	)		(300	)		-
Accounts payable and accrued expenses		130			(2	)		(71	)
Accrued royalties		52			135			130
Due to/from affiliates, net		164			495			36
Total adjustments		1,132			1,313			1,958
Net cash provided by operating activities		3,993			4,533			3,566
Cash flows from investing activities
Capital expenditures		-			(36	)		(5	)
Cash flows from financing activities
Restricted cash		-			757			(7	)
Cash distributions to partners		(4,085	)		(4,394	)		(1,895	)
Repayments of notes payable		-			(867	)		(955	)
Net cash used in financing activities		(4,085	)		(4,504	)		(2,857	)
Net (decrease) increase in cash and cash
equivalents		(92	)		(7	)		704
Cash and cash equivalents, beginning of year		699			706			2
Cash and cash equivalents, end of year	$	607		$	699		$	706
Supplemental disclosure of cash flow information:
Cash paid during the year for interest	$	13		$	14		$	130

The accompanying notes are an integral part of these statements.

- 7 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE A - DESCRIPTION OF BUSINESS

In February 1996, Ridgewood Providence Power Partners, L.P. was formed as a Delaware limited partnership (the “Partnership”).  Ridgewood Providence Power Corporation, a Delaware corporation, is the sole general partner of the Partnership and is owned by Ridgewood Electric Power Trust III (“Trust III”) and Ridgewood Electric Power Trust IV (“Trust IV”), both Delaware business trusts (collectively, the “Trusts”).  The Trusts are also the limited partners in the Partnership and have a common Managing Shareholder, Ridgewood Renewable Power, LLC (“RRP”).  The Partnership shall continue to exist until April 1, 2036, unless terminated sooner by certain provisions of the Partnership Agreement.

In April 1996, the Partnership purchased substantially all of the net assets of Northeastern Landfill Power Joint Venture.  The assets acquired include a 13.8 megawatt capacity electrical generating station, located at the Central Landfill in Johnston, Rhode Island (the “Providence Project”).  The Providence Project includes nine reciprocating engine generator sets which are fueled by methane gas produced by and collected from the Central Landfill.  The electricity produced by the Providence Project is sold to New England Power Service Company (“NEP”) under a long-term electric power sales contract.

The cash distributions and profits and losses of the Partnership are allocated 1% to the general partner and 99% to the limited partners in accordance with their capital contribution (63.7% to Trust IV and 35.3% to Trust III).

NOTE B - RESTATEMENT OF FINANCIAL STATEMENTS

The Partnership has identified a series of adjustments, including proper recognition of renewable attribute revenue, amortization of the electric power sales contract, recognition of royalty expense and accounting for professional services, which have resulted in restatement of the previously issued financial statements for the year ended December 31, 2003.

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Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE B (continued)

The following table represents the effects of the restatement adjustments upon the Partnership’s previously reported balance sheet and statement of operations as of and for the year ended December 31, 2003.

Balance Sheet

	December 31, 2003
				Adjustments
Assets	Previously reported			Reclass			Other adjustments				Restated
Current assets	$	2,634		$	5		$	33		(A)	$	2,672
Noncurrent assets		15,084			-			(390	)	(B)		14,694
Total assets	$	17,718		$	5		$	(357	)		$	17,366
Liabilities and partners’ equity
Current liabilities	$	1,837		$	5		$	149		(C)(D)(E)	$	1,991
Partners’ equity		15,881			-			(506	)	(B)(D)		15,375
Total liabilities and partners’ equity	$	17,718		$	5		$	(357	)		$	17,366
Statement of Operations
Revenues	$	8,553		$	-		$	32		(A)	$	8,585
Cost of revenues		6,024			713			199		(B)(C)(E)		6,936
Gross profit		2,529			(713	)		(167	)			1,649
Operating expenses (income)		647			(713	)		(14	)	(D)		(80	)
Income from operations		1,882			-			(153	)			1,729
Other income (expense), net		(121	)		-			-				(121	)
Net income	$	1,761		$	-		$	(153	)		$	1,608

(A) The Partnership did not recognize renewable attribute revenue properly in 2003.  As a result, the Partnership increased trade receivables and renewable attribute revenue by $33 and $32,  respectively.

(B) Amortization of the electric power sales contract was not recognized over the proper useful life.  The Partnership recorded an adjustment by increasing amortization expense and accumulated amortization by $47 and $390, respectively, and decreasing beginning partners’ equity by $343.

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Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE B (continued)

(C) The Partnership did not recognize royalty expense properly in 2003.  As a result, the Partnership increased royalty expense and accrued royalties by $127, respectively.

(D) The Partnership overaccrued $14 and underaccrued $9 of accounting fees for the years ended December 31, 2003 and 2002, respectively.  The 2003 overaccrual was recorded as an adjustment to accrued expenses and general and administrative expenses.  The 2002 underaccrual increased accrued expenses and decreased beginning partners’ equity by $9.

(E) The Partnership underaccrued operating expenses of $25 for the year ended December 31, 2003.  The underaccrual was recorded as an increase to cost of revenues and an increase to accrued expenses.   The Partnership restated 2002 amounts by decreasing partners’ equity as of January 1, 2003 by $352.  The following is the summary of adjustments recorded that were made to partners’ equity as of January 1, 2003: (a) understatement of accumulated amortization of electric power sales contract of $343 and (b) underaccrual of accounting fees of $9.

NOTE C - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1.     Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires the Partnership 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 ongoing basis, the Partnership evaluates its estimates, including bad debts, intangible assets and recordable liabilities for litigation and other contingencies.  The Partnership 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, recoverable value of property, plant and equipment and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates under different assumptions or conditions.

- 10 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE C (continued)

2. Cash and Cash Equivalents

The Partnership considers all highly liquid investments with maturities when purchased of three months or less as cash and cash equivalents.  Cash balances with banks as of December 31, 2005, 2004 and 2003 exceeded insured limits by $507, $599 and $606, respectively.  Restricted cash as of December 31, 2003 exceeded insured limits by $657.

3. Trade Receivables

Trade receivables are recorded at invoice price in the period in which the related revenues are earned and do not bear interest.  No allowance for bad debt expense was provided based upon historical write-off experience, evaluation of customer credit condition and the general economic status of the customer.

4. 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 electric power sales contract.  Adjustments are made to reflect actual volumes delivered when the actual volumetric information subsequently becomes available.  Final billings do not vary significantly from estimates.

Renewable attribute revenue is derived from the sale of the renewable portfolio standard attributes (“RPS Attributes”).  As discussed in Note H, qualified renewable electric generation facilities produce RPS Attributes when they generate electricity.  Renewable attribute revenue is recorded in the month in which the RPS Attributes are produced as the Partnership has substantially completed its obligations for entitled benefits, represented by the underlying generation of power within specific environmental requirements.

Sublease revenue is recorded monthly in accordance with the terms of the sublease agreement.

5. Plant and Equipment

Plant and equipment, consisting principally of electrical generating equipment, are stated at cost less accumulated depreciation.  Major renewals and betterments that increase the useful lives of the assets are capitalized.  Repair and maintenance expenditures are expensed as incurred.  Upon retirement or disposal of assets, the cost and the related accumulated depreciation are removed from the balance sheets.  The difference, if any, between the net asset value and any proceeds from such retirement of disposal is recorded as a gain or loss in the statement of operations.

- 11 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE C (continued)

The Partnership uses the straight-line method of depreciation over the estimated useful lives of the assets:

Power generation facility	20 years
Equipment	5 - 20 years
Vehicles	5 years

Rotable spare parts inventory primarily consists of parts and materials that are infrequently used in the Partnership’s operation.  An allowance is established for obsolesence on the basis of management’s review and assessment.

6. Significant Customers

During 2005, 2004 and 2003, the Partnership’s two largest customers accounted for 81.8%, 81.2% and 84.2% of total revenues, respectively.

7. Income Taxes

No provision is made for income taxes in the accompanying financial statements as the income or loss of the Partnership is passed through and included in the income tax returns of the partners.

8. Fair Value of Financial Instruments

For the years ended December 31, 2005, 2004 and 2003, the carrying value of the Partnership’s cash and cash equivalents, trade receivables, accounts payable and accrued expenses, and notes payable approximates their fair value.

9. New Accounting Standards and Disclosures

FIN 45

In November 2002, the Financial Accounting Standards Board (“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 Partnership adopted FIN 45 during the fourth quarter of 2002 with no material impact to the financial statements.
 

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Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE C (continued)

SFAS No.  154

In May 2005, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 154, “Accounting Changes and Error Corrections.”  SFAS No. 154 replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.”  This statement changes the requirements for the accounting for, and reporting of, a change in accounting principle and applies to all voluntary changes in accounting principle, as well as changes pursuant to accounting pronouncements that do not include transition rules.  Under SFAS No. 154, changes in accounting principle must be applied retrospectively to prior periods’ financial statements, or the earliest practicable date, as the required method for reporting a change in accounting principle.  The Partnership adopted SFAS No. 154 effective December 15, 2005, and accordingly restated the financial statements, as described in Note B.

NOTE D - PLANT AND EQUIPMENT

At December 31, 2005, 2004 and 2003, plant and equipment at cost and accumulated depreciation were:

	2005			2004			2003
							(Restated)
Power generation facility	$	1,905		$	1,905		$	1,905
Equipment		14,032			14,032			13,996
Rotable spare parts		699			796			823
Vehicles		32			32			32
		16,668			16,765			16,756
Less: Accumulated depreciation		(7,319	)		(6,533	)		(5,729	)
	$	9,349		$	10,232		$	11,027

During the years ended December 31, 2005, 2004 and 2003, the Partnership recorded depreciation expense of $786, $804, and $803, respectively, which is included in cost of revenues.

- 13 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE E - ELECTRIC POWER SALES CONTRACT

The Partnership is committed to sell all of the electricity it produces to NEP for prices as specified in the Power Purchase Agreement.  The agreement with NEP expires in the year 2020 and can be terminated by NEP under certain conditions in 2010.  As defined, the Prices are adjusted annually for changes in the Consumer Price Index through 2010, and become market prices thereafter.

A portion of the purchase price of the Providence Project was assigned by the Partnership to the electric power sales contract and is being amortized through its early termination date of 2010 (a period of approximately 14 years) on a straight-line basis.  At December 31, 2005, 2004 and 2003, the gross and net carrying amounts of the electric power sales contract were:

	2005			2004			2003
							(Restated)
Electricity power sales contract - gross	$	8,338		$	8,338		$	8,338
Less: Accumulated amortization		(5,878	)		(5,274	)		(4,671	)
Electricity power sales contract - net	$	2,460		$	3,064		$	3,667

For the years ended December 31, 2005, 2004 and 2003, the Partnership recorded amortization expense of $603, which is included in cost of revenues.  The Partnership expects to record amortization expense during the next five years as follows:

Year ended
December 31,
2006	$603
2007	603
2008	603
2009	603
2010	48

- 14 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE F - NOTES PAYABLE

The Partnership did not have any outstanding debt at December 31, 2005 and 2004.  At December 31, 2003, the Partnership owed $867 under senior collateralized non-recourse notes which were due in monthly installments of $91, including interest at 9.6%.  Although the final payment was due on October 15, 2004, the Partnership made a payment of $813 on February 13, 2004 to pay off the remaining balance of the note.  The final payment consisted of cash and the transfer of the balance in the restricted debt service fund at February 13, 2004.  The notes provided for additional interest equal to 5% of the annual net cash flow of the Partnership, as defined.  No additional interest was due.  Prior to their retirement, the notes were collateralized by a leasehold mortgage on substantially all of the assets of the Partnership.  The loan agreement also required a funded debt service reserve.  At December 31, 2003, the cash balance in the restricted debt service reserve was $757, which was used as part of the 2004 repayment.

NOTE G - LANDFILL LEASE AND SUBLEASE

The Partnership leases its site on the Central Landfill, located in Johnston, Rhode Island from Rhode Island Resource Recovery Corporation (“RIRRC”) under a lease which expires in 2020 and can be extended for an additional 10 years by mutual agreement of the parties under certain conditions.  The lease requires the Partnership to pay a contingent rent in the form of a royalty equal to 15% of net revenue, as defined, until 2006.  For subsequent years, the royalty is 15% of net revenues for each month in which the average daily kilowatt hour production is less than 180,000, and 18% of net revenues for each month in which the average daily kilowatt hour production exceeds 180,000.  For the years ended December 31, 2005, 2004 and 2003, royalty expense relating to the RIRRC lease amounted to $1,090, $1,102, and $1,069, respectively.  The royalty expense has been included in the cost of revenues in the statements of operations.

The Partnership subleases a portion of the Central Landfill to the Central Gas Limited Partnership (“Gasco”), an unaffiliated entity.  Gasco operates and maintains a portion of the landfill gas collection system and supplies landfill gas to the Providence Project.  The sublease agreement is effective through December 31, 2010 and provides for the following:

Sublease Revenue - Effective January 1, 2001, Gasco is to pay the Partnership an annual amount equal to the product of $45 (adjusted annually for inflation from January 1, 2001) times the assumed output capacity of each original engine generator set in megawatts installed and operated by the joint venture.  The Partnership recognized sublease revenue of $571, $571 and $554 for the years ended December 31, 2005, 2004 and 2003, respectively.

- 15 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE G (continued)

Fuel Expense - The Partnership is to purchase all the landfill gas produced by Gasco and pay Gasco on a monthly basis approximately $.05 to $.005 per kilowatt hour based on the kilowatt hours generated.  The price is adjusted annually for changes in the Consumer Price Index, as defined.  Purchases from Gasco for the years ended December 31, 2005, 2004 and 2003 amounted to $1,008, $1,020, and $993, respectively.  Fuel expenses have been included in the cost of revenues in the statements of operations.

NOTE H - 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 gas.  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 Massachusetts Division of Energy Resources (“DOER”).

On January 17, 2003, the Partnership received a “Statement of Qualification” from the DOER pursuant to the renewable portfolio standards (“RPS”) adopted by Massachusetts.  Since the Partnership has now 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.

During 2004, the Partnership became qualified to sell RPS Attributes in Connecticut under a similar RPS program, except that the Connecticut program does not have a “vintage” prohibition, which in Massachusetts disqualifies the amount of a facility’s generation measured by its average output during the period 1995 through 1997.  Thus, the Partnership can sell the 86,000 megawatt hours (“MWhs”) that are ineligible under Massachusetts standards into the Connecticut market.  During 2004, the Partnership sold its “vintage” RPS Attributes pursuant to agreements with various power marketers.

- 16 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE H (continued)

Similar agreements have committed the Partnership to sell its 2005 and 2006 “vintage” RPS Attributes to such designated parties at certain fixed quantities and prices.  Pursuant to the terms of the agreement, the Partnership is only required to deliver the specified RPS Attributes it generates and is not obligated to produce, nor is it subject to penalty if it is unable to produce, contracted quantities.

NOTE I - ROYALTY EXPENSE

On August 1, 2003, the Partnership entered into an Environmental Attribute Agreement with RIRRC and Ridgewood Gas Services, LLC (“RGS”), an affiliate of the Partnership that provides management services to RIRRC.  Pursuant to the terms of the agreement, the Partnership is required to pay certain royalties to RIRRC and RGS which are derived from the sale of RPS Attributes and are the only direct costs of the renewable attribute revenue.  The term of the agreement coincides with the Central Landfill lease agreement, which expires in 2020 and provides for an extension of an additional ten years.  During the years ended December 31, 2005, 2004, and 2003, the Partnership recognized royalty expense of $1,181, $1,245 and $127, respectively, related to this agreement which is included in cost of revenues in the accompanying statements of operations.  The royalty expenses recognized above include 50% of royalty expenses to RGS for each of the years ended December 31, 2005, 2004 and 2003.

NOTE J - RELATED PARTY TRANSACTIONS

Under an Operating Agreement with the Trusts, Ridgewood Power Management LLC (“Ridgewood Management”), an entity related to the Managing Shareholder of the Trusts through common ownership, provides management, purchasing, engineering, planning and administrative services to the Partnership.  Ridgewood Management charges the Partnership 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 years ended December 31, 2005, 2004 and 2003, Ridgewood Management charged the Partnership $500, $439 and $452, respectively, for overhead items allocated in proportion to the amount invested in projects managed, which is included in cost of revenues in the accompanying statements of operations.  Ridgewood Management also charged the Partnership for all of the remaining direct operating and non-operating expenses attributable to the activities of the Partnership incurred during the periods. These charges may not be indicative of costs incurred if the Partnership were not operated by Ridgewood Management.

- 17 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE J (continued)

The Partnership 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, 2005, 2004 and 2003, the Partnership had outstanding receivables and payables with the following affiliates:

	Due from						Due to
	2005		2004		2003		2005		2004		2003
					(Restated)						(Restated)
Ridgewood Management	$	-	$	-	$	-	$	167	$	291	$	2
RRP		-		-		-		-		-		98
Trust III		-		-		-		349		461		575
Trust IV		-		-		206		628		208		-
Other affiliates		20		-		-		89		89		85
	$	20	$	-	$	206	$	1,233	$	1,049	$	760

NOTE K - OTHER INCOME

During the first quarter of 2002, the Partnership experienced the failure of one of its engines.  The Partnership submitted a claim with its insurance carrier for the replacement of the engine and lost profits as a result of the business interruption it experienced.  For the year ended December 31, 2003, the Partnership recorded $160 of other operating income as a result of its claim.

NOTE L - COMMITMENTS AND CONTINGENCIES

The Partnership and several of its affiliates have an agreement with a power marketer for which they are committed to sell a portion of their RPS Attributes derived from their electric generation.  The agreement provides such power marketer with six separate annual options to purchase such RPS Attributes from 2004 through 2009 at fixed prices, as defined.  If the Partnership and its affiliates fail to supply the required number of RPS Attributes, penalties may be imposed.  In accordance with the terms of the agreement, if the power marketer elects to exercise an annual option and the Partnership and its affiliates produce no renewable attributes for such option year, the Partnership and its affiliates face a maximum penalty, which is adjusted annually for the change in the consumer price index, among other things, of approximately $3,300, measured using current factors, for that option year and any other year in which an option has been exercised and no renewable attributes have been produced.  Pursuant to the agreement, the Partnership is liable for 8% of the total penalty.  In the fourth quarters of 2006 and 2005, the power marketer notified the Partnership and its affiliates that it has elected to purchase the output for 2007 and 2006, respectively, as specified in the agreement.  In 2004, the Partnership incurred a penalty of approximately $4 for the shortfall in production of RPS Attributes.  In 2006, 2005 and 2003, the Partnership satisfied and delivered RPS Attributes as prescribed in the agreements and therefore no penalties were incurred.

- 18 -

Ridgewood Providence Power Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2005, 2004 and 2003

(dollar amounts in thousands)

NOTE L (continued)

As part of the RPS Attribute agreements, the Partnership has assigned and pledged its receivables derived from a portion of its renewable attribute revenue to the power marketer as well as deposited $300 with the power marketer during 2004.  In addition to the current security deposit, the Partnership deposited an additional $105 with the power marketer in 2005. The affiliates of the Partnership that are parties to the agreement have also deposited amounts with the power marketer in proportion to their obligations under the agreement.

- 19 -