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:  0-21304

RIDGEWOOD ELECTRIC POWER TRUST II

(Exact Name of Registrant as Specified in Its Charter)

Delaware	22-3206429
(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 235.3775.

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 II (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 years ended December 31, 2003 and 2004 and for the quarterly periods ended March 31, 2003, June 30, 2003, September 30, 2003, March 31, 2004, June 30, 2004, September 30, 2004 and March 31, 2005 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 Report on Form 10-K for the year ended December 31, 2005,  and Quarterly Reports on Form 10-Q for the quarterly periods ended June 30, 2005 and September 30, 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 Report on Form 10-K for the year ended December 31, 2005 and the Quarterly Reports on Form 10-Q for the periods ended 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 10, 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 Reports on Form 10-K for each of the periods beginning with the three-month period ended March 31, 2003 and continuing through the three-month period ended March 31, 2005 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 accompanying 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	4
Item 1B.	Unresolved Staff Comments	7
Item 2.	Properties	7
Item 3.	Legal Proceedings	7
Item 4.	Submission of Matters to a Vote of Security Holders	8
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Security Holder Matters and
	Issuer Purchases of Equity Securities	8
Item 6.	Selected Financial Data	8
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	10
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	19
Item 8.	Financial Statements and Supplementary Data	19
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	19
Item 9A.	Controls and Procedures	20
Item 9B.	Other Information; Unregistered Sales of Equity Securities and Use of Proceeds;
	Defaults Upon Senior Securities	21
	PART III
Item 10.	Directors and Executive Officers of the Registrant	21
Item 11.	Executive Compensation	23
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Security Holder Matters	23
Item 13.	Certain Relationships and Related Transactions	23
Item 14.	Principal Accountant Fees and Services	24
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	25
SIGNATURES		27

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 the outcome of litigation described in Item 3. "Legal Proceedings", 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 November 20, 1992 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 small-scale electricity generation projects. 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 Trust had two operating investments, both located in California and 100% owned by the Trust.  One investment is a 5.5 megawatt (“MW”) cogeneration project which suspended operations in early 2006 due to a contract dispute with its customer. See Item 3. “Legal Proceedings” for further discussion. The other investment is a collection of irrigation service engines with a production capacity of 2MW, which was sold in January 2006 for $1. Additionally, at December 31, 2005, the Trust had a long-term note receivable, which was paid in full on October 31, 2007.

Based on the status of these assets, the operating results of the Trust for future periods is expected to be materially reduced from current levels.

The Trust initiated its private placement offering in November 1992 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 January 1994 and after payment of offering fees, commissions and investment fees, the Trust had $19.4 million available for investments and operating expenses. As of September 30, 2007, the Trust had 235.3775 Investor Shares outstanding, held by 534 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 1.5% of the 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 100% owned through investment vehicles managed by the Managing Shareholder.

Projects and Properties

Monterey

In January 1995, the Trust purchased 100% of the equity interests in Sunnyside Cogeneration Partners, L.P., which owns a 5.5-megawatt cogeneration project located in Salinas, Monterey County, California (“Monterey"). The aggregate purchase price was $5.2 million.  Monterey began operations in 1991 using natural gas fired reciprocating engines to generate electricity for sale to Pacific Gas and Electric Company ("PG&E") under a long term contract expiring in 2020 (the "Power Contract"). PG&E is also obligated to pay Monterey capacity payments based on its net electrical output or its available capacity. Thermal energy from Monterey’s operations provides warm water to an adjacent greenhouse under a long-term contract that also terminates in 2020. Monterey is operated on behalf of the Trust by RPM on an at-cost basis.

Monterey’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" or SRAC.  At December 31, 2005, however, Monterey was operating pursuant to a 2001 amendment to the Power Contract with PG&E, which provided, among other things, that Monterey would receive a fixed energy payment (as well as the required capacity payment) for a term of five years, until approximately August 2006.  Upon expiration of the amendment, through the remainder of the term of the contact, the formula contained in the original contract was to be used to determine the energy price paid by PG&E.

Monterey has a non-cancelable operating lease covering its site, which expires in May 2021 with minimum annual lease payments, including the delivery of cogeneration steam.

In August 2001, Monterey entered into an agreement 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 Monterey also had a master re-sale agreement, which also expired in August 2006.  Such agreement enabled Monterey to not take delivery of, and sell back to Coral, certain amounts of natural gas once predetermined prices have been established. During 2004, 2005 and 2006, Monterey re-sold gas back to Coral.

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Monterey received notice on December 1, 2005 from PG&E directing Monterey to increase its operations from 13 hours, 5 days a week to 24 hours, 7 days a week. However, PG&E had been operating or "dispatching" Monterey on a 5 by 13 basis for over 15 years.  Monterey determined that it could not operate profitably on such a schedule and was concerned that if it Monterey only operated on a 5 by 13 basis, PG&E might refuse to pay for delivered electricity. Monterey requested from PG&E to limit its operations to the 5 by 13 basis, but this request was denied. As a result, effective January 9, 2006, Monterey ceased its operations. Monterey and PG&E have filed lawsuits against the other for breach of contract. For further discussion, see Item 3. “Legal Proceedings”. The Monterey project remains closed as of the date of this filing.  Additionally, as a result of the shut down, the project has not delivered by-product steam since it was shut down in January 2006. As a result, it may be subject to penalties from the lessor.

Pumping Project

In 1995, the Trust purchased a package of irrigation service engines (the “Pumping Project") located in Ventura County, California.  The purchase price was $952,000.  RPM operated and managed the Pumping Project. The Pumping Project had been operating since 1992 and had 10 natural-gas-fired reciprocating engines with a maximum rated equivalent capacity of 2MW to provide power for irrigation wells that furnish water for citrus orchards. The power was purchased by local farmers and farmers' co-operatives pursuant to electric services contracts. In January 2006, the engines were sold for $1 to its prior customers.

Other Investments

The Trust acquired an 80% interest in a water chilling facility in San Diego, California in March 1994 for a purchase price of $2.3 million.  The Trust made additional capital contributions, totaling $1.2 million, to the facility to fund working capital and to purchase various leased equipment.  In June 1997, the Trust sold its entire interest in the facility to subsidiaries of NRG Energy, Inc. The sale price was $6.2 million in cash and notes. The notes were paid in full in 2003.

In January 1994, the Trust made an equity investment of $2.3 million in Pittsfield Investors Limited Partnership (“PILP”), which was formed to acquire a waste-to-energy project designed and built to burn municipal solid waste supplied by the City of Pittsfield, Massachusetts, surrounding communities and other waste providers as well as to supply steam to a nearby paper mill.  The PILP project originally began operating in 1981 and was operated and co-owned with the Trust by subsidiaries of Energy Answers Corporation (“EAC”). The Trust made an additional investment with affiliates of EAC in August 1994 when it purchased an interest in the B-3 Limited Partnership (“B-3”) for $4 million.  The business of B-3 was the construction and operation of a municipal waste transfer station in Columbia County, New York.  In September 2002, the Trust sold its interests in PILP and B-3 to EAC for $1.2 million in cash and $5 million of promissory notes. The notes bore interest at a rate of 10% per annum, and were to be repaid over a 17-year term. The notes were collateralized solely by the assets of the projects and are without recourse to EAC. The note payments remained current until the notes were paid in full on October 31, 2007.

Significant Customers and Supplier

During 2005, 2004 and 2003, the Trust’s largest customer, Pacific Gas and Electric Company, accounted for 88%, 87% and 80%, respectively of total revenues. During 2005, 2004 and 2003, Monterey purchased 100% of its natural gas from Coral.

Business Segments

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

Competition

Monterey is currently bound under a long-term sale contract. Based on this, the Trust does not generally face direct competition in the sale of the electricity it generates.

Government Incentives and Regulation

Projects of the Trust have been subject to energy and environmental laws and regulations at the federal, state and local levels in connection with development, ownership, operation, geographical location, zoning and land use of a project and emissions and other substances produced by a project. These energy and environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operates in compliance with such permits and approvals. Monterey also operates under the terms of the Federal Energy Regulatory Commission (“FERC”) licenses issued to it. The Trust considers these regulations to be routine and does not consider the cost of compliance to be material.

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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.

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’s principal office is located at 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 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 remaining operating asset, Monterey, has not operated since January 2006.

If Monterey is unable to satisfactorily resolve its dispute with PG&E, its only customer, it is likely that the plant will remain closed. Other than the Trusts’ collection of its long-term notes receivable in October 2007, the Monterey project is the only remaining productive asset of the Trust. Continued closure of the Monterey project significantly reduces revenue and cash flows to the Trust. See Item 3. “Legal Proceedings” for a description of the dispute with PG&E.

The project of the Trust depends on the near-continuous operation of its 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 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 project of the Trust is 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 the Trust’s project or prevent the project from operating.

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. Also, a subsidiary of the Trust, Monterey, is involved in litigation as discussed in Item 3. “Legal Proceedings”. Although it is not possible to predict the timing, nature or outcome of such claims or lawsuits, 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.

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.

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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 1.5% of the prior years' 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.

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.

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· 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.

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

As discussed in Item 1. “Business” under the heading Projects and Properties - Monterey, for the first 15 years of operation, PG&E “dispatched” the Monterey facility to produce and deliver electricity up to its contract capacity on a 13 hour per day, five day per week basis (“13x5”).  However, on December 1, 2005, PG&E dispatched Monterey on a 24 hour per day, seven day per week basis (“24x7”) for an indefinite period, effective January 1, 2006.  Monterey advised PG&E that its 24x7 dispatch order was a breach of the parties’ power purchase agreement.  Management of Monterey was also concerned that if Monterey continued to produce and supply power consistent with the parties’ prior course of performance, PG&E would refuse to pay.  Accordingly, Monterey demanded that PG&E provide adequate assurances that it would continue to pay Monterey for its capacity and its electricity produced and delivered in accordance with the parties’ longstanding 13x5 operations.  PG&E did not provide such assurances.  In the absence of such assurances, Monterey suspended operations on or about January 9, 2006.  Monterey filed a Complaint against PG&E in the San Francisco Superior Court on May 16, 2006 (the “Monterey Complaint”).  The Monterey Complaint seeks damages for breach of contract, damages for PG&E’s breach of the implied covenant of good faith and fair dealing, and a claim for declaratory relief against PG&E, seeking a judicial determination that PG&E’s conduct materially breached the parties’ agreement and justified Monterey’s suspension of performance.  Monterey is seeking damages against PG&E estimated at approximately $5 million. A Jury Trial with regard to this matter is currently set for February 8, 2008.

7

On May 14, 2007, PG&E filed a Complaint in San Francisco Superior Court against Monterey (the “PG&E Complaint”).  The PG&E Complaint arises out of the same transactions and occurrences that gave rise to the Monterey Complaint against PG&E.  PG&E asserted claims for compensatory damages for breach of contract and breach of the implied covenant of good faith and fair dealing as well as “restitution” of capacity payments made to Monterey on a theory of unjust enrichment, and declaratory relief for repayment of capacity payments made to Monterey.  PG&E is seeking restitution damages against Monterey estimated at approximately $4.8 million.

 The claims made by PG&E have been made solely against Monterey and do not involve any claims against the Trust. Both of the above litigation matters are currently in discovery.  Monterey intends to vigorously prosecute its claims and defend against PG&E’s claims and management believes it will ultimately prevail.

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 534, 527, 525 and 525 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	$	1,177	$	1,412	$	1,412
Distributions per Investor Share		5,000		6,000		6,000
Distributions to Managing Shareholder		12		14		14

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.

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.

8

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.

(in thousands, except per share data)	December 31,
	2005		2004		2003		2002		2001
			(Restated)		(Restated)
Consolidated Statement of Operations Data:
Revenues	$	2,817	$	2,826	$	3,009	$	3,075	$	2,374
Net income (loss)		265		361		340		256		(1,089	)
Net income (loss) per Investor Share		1,116		1,516		1,432		1,086		(4,626	)
Consolidated Balance Sheet Data:
Plant and equipment, net	$	1,132	$	1,258	$	1,381	$	1,798	$	2,003
Total assets		4,384		4,964		6,060		7,561		8,216
Shareholders' equity		3,878		4,802		5,867		7,227		7,804

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.

(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)
Consolidated Statement of Operations Data:
Revenues	$	2,107	$	2,154	$	2,261	$	792	$	746	$	835
Net income (loss)		893		634		345		819		158		(369	)
Net income (loss) per Investor Share		3,758		2,669		1,453		3,446		663		(1,551	)

	September 30,
(in thousands)	2005		2004		2003
			(Restated)		(Restated)
Consolidated Balance Sheet Data:
Plant and equipment, net	$	1,165	$	1,288	$	1,628
Total assets		5,016		5,578		6,388
Shareholders' equity		4,743		5,432		6,228

(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)
Consolidated Statement of Operations Data:
Revenues	$	1,315	$	1,408	$	1,426	$	651		$	708	$	682
Net income (loss)		74		476		714		(244	)		153		346
Net income (loss) per Investor Share		314		2,001		3,007		(1,028	)		642		1,457

	June 30,
(in thousands)	2005		2004		2003
			(Restated)		(Restated)
Consolidated Balance Sheet Data:
Plant and equipment, net	$	1,196	$	1,319	$	1,683
Total assets		4,254		5,819		7,134
Shareholders' equity		4,163		5,630		6,955

9

(in thousands, except per share data)	Three months ended March 31,
	2005		2004		2003
	(Restated)		(Restated)		(Restated)
Consolidated Statement of Operations Data:
Revenues	$	664	$	700	$	744
Net income		318		323		368
Net income per Investor Share		1,344		1,362		1,549

	March 31,
(in thousands)	2005		2004		2003
	(Restated)		(Restated)		(Restated)
Consolidated Balance Sheet Data:
Plant and equipment, net	$	1,227	$	1,350	$	1,741
Total assets		4,933		6,030		7,152
Shareholders' equity		4,764		5,834		6,965

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 10, 2007, the consolidated financial statements of the Trust included in the Trust’s Quarterly Reports on Form 10-Q and the Trust’s Annual Reports on Form 10-K for each of the periods beginning with the three-month period ended March 31, 2003 and continuing through the three-month period ended March 31, 2005 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 as more fully described in Note 2 to the accompanying consolidated financial statements. 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. 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 November 20, 1992 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 small-scale electricity generation projects. 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 Trust had two operating investments, both located in California and 100% owned by the Trust.  One investment, Monterey, is a 5.5MW cogeneration project which suspended operations in early 2006 due to a contract dispute with its customer. See Item 3. “Legal Proceedings” for further discussion. The other investment is a collection of irrigation service engines with a production capacity of 2MW, which was sold in January 2006 for $1. Additionally, the Trust has a long-term note receivable, which was paid in full on October 31, 2007.

Based on the status of these assets, the financial statement results for future periods is expected to be materially different than historical periods. Since the closing of the Monterey facility in January 2006, the Trust has not had any operating revenues, though it continued to have contractual obligations through August 2006 related to the gas purchase agreement with Coral. Upon the repayment of the Trust’s long term receivable in October 2007, the Trust no longer had any cash producing assets and may not in the future, subject to the resolution of litigation relating to the Monterey facility. During the first quarter of 2006, the Trust intends to record an asset impairment of Monterey’s remaining net book value. Monterey remains closed as of the date of this filing.

10

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. 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 3 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 Contract

In August 2001, Monterey entered into an agreement to purchase natural gas, at fixed prices, over a five-year term in connection with entering into an amendment fixing the sales price of electric power sales contracts for a similar term. This contract was entered into in order to minimize the impact of fluctuating energy prices. The Trust has determined that this contract is a derivative as defined under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. The Trust has designated the derivative as a non-hedge instrument. Accordingly, the value of the contract 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 contract is reflected as a component of cost of revenues in the consolidated statements of operations.

11

Notes Receivable

Recovery of interest and principal under the promissory notes issued in connection with the sale of the Trust’s interest in PILP and B-3 were dependent upon the operations of the partnership investment transferred. Consequently, the Trust deferred its gain on the sale of its ownership interest until the carrying value of the investments was fully recovered. The cash proceeds received for the interest and principal were recorded as a reduction of the Trust’s investment in the partnership transferred under contractual agreement through June 30, 2005.  Subsequent payments were recorded as a component of other income.

Results of Operations and Changes in Financial Condition

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

Revenues of $2.8 million in 2005 was comparable to the same period in 2004.

Cost of revenues increased approximately $0.5 million, or 18.2%, from $2.2 million for the year ended December 31, 2004 to $2.7 million for the year ended December 31, 2005. This increase was primarily attributable to the impact of the Monterey gas supply contract as by the decrease in natural gas prices decreased during 2005.

Gross profit decreased by $0.4 million, or 71.4%, from $0.6 million in 2004 to $0.2 million in 2005. This decrease was primarily due to lower natural gas prices.

In 2005, the Trust recorded gains of $0.3 million from collection on notes from the sale of its investment in B-3 and PILP.

Net income for 2005 totaled $0.3 million, a decrease of approximately $0.1 million from $0.4 million in 2004. This decrease was due to the decrease in gross profit, offset by the gains recorded during 2005 from collection of notes receivable.

Total assets at December 31, 2005 decreased by $0.6 million, from $5.0 million at December 31, 2004 to $4.4 million at December 31, 2005, primarily due to decreases of $0.4 million in payments received in the investment in partnership transferred under contractual agreement and $0.2 million in cash and cash equivalents. Total liabilities increased $0.3 million from $0.2 million at December 31, 2004 to $0.5 million at December 31, 2005, primarily due to affiliated short-term borrowings of $0.3 million.

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

Revenues decreased by $0.2 million, or 6.1%, to $2.8 million in 2004 as compared to $3 million in 2003. This decrease was primarily due to a decrease of $0.2 million in revenues from the Pumping Project in 2003, due to decreased usage. See below for a discussion of the impairment recorded in 2004 relating to the Pumping Project.

Gross profit decreased by $0.2 million to $0.6 million in 2004 as compared to $0.8 million in 2003.  Gross profit decreased primarily due to a decline in revenues from the Pumping Project of $0.2 million.

In 2003, the Trust recorded an impairment of $0.2 million related to the Pumping Project. 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.

Total assets decreased $1.1 million from $6.1 million at December 31, 2003 to $5 million at December 31, 2004. This decrease was primarily due to decreases of $0.8 million in cash and cash equivalents and $0.4 million in investments in partnership transferred under contractual agreement, partially offset by an increase of $0.4 million in the gas forward contract.  Total liabilities were $0.2 million at both December 31, 2004 and December 31, 2003.

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

Revenues decreased approximately $0.1 million, or 2.2%, from $2.2 million for the nine months ended September 30, 2004 to $2.1 million for the same period in 2005. This decrease was primarily due to a decrease in Pumping Project revenues for the 2005 period as compared to the 2004 period.

Gross profit increased approximately $0.1 million to $0.9 million for the nine months ended September 30, 2005 as compared to $0.8 million for the same period in 2004. This increase was primarily attributable to lower cost of revenues due to the impact of price changes for natural gas.

12

During the nine months ended September 30, 2005, the Trust recorded a gain on sale of investments of $0.2 million from its investment in B-3 and PILP.

Total assets of $5 million at September 30, 2005 were comparable to the balance at December 31, 2004. Total liabilities were $0.3 million at September 30, 2005 as compared to $0.2 million at December 31, 2004, an increase of $0.1 million. This increase was primarily due to an increase in borrowings from affiliates.

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

Revenues decreased $0.1 million, or 4.7%, to $2.2 million for the nine months ended September 30, 2004 as compared to $2.3 million for the nine months ended September 30, 2003.  This decrease was primarily due to a decrease of $0.1 million in revenues from the Pumping Project.

Cost of revenues for the first nine months of 2004 was $1.3 million as compared to $1.7 million for the comparable 2003 period, a decrease of $0.4 million. This decrease was primarily due to higher natural gas prices.

Gross profit increased by approximately $0.2 million from $0.6 million for the nine months ended September 30, 2003 to $0.8 million for the same period in 2004. This increase was primarily due to lower cost of revenues resulting from increased natural gas prices.

Total assets at September 30, 2004 were $5.6 million, a decrease of $0.5 million from the December 31, 2003 balance of $6.1 million. This decrease was primarily due to decreases of $0.7 million in cash and cash equivalents and $0.3 million in an investment in partnership transferred under contractual agreement, partially offset by an increase of $0.6 million in the gas forward contract. Total liabilities decreased by approximately $0.1 million from $0.2 million at December 31, 2003 to $0.1 million at September 30, 2004, primarily due to reduced amounts due to affiliates.

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

Revenues increased approximately $0.1 million, or 6.3%, to $0.8 million for the three months ended September 30, 2005 as compared to $0.7 million for the same period in 2004. This increase was primarily due to an increase in Pumping Project revenues.

Cost of revenues for the three months ended September 30, 2005 was $0.1 million, a decrease of approximately $0.4 million, or 83.3%, as compared to $0.5 million for the same period in 2004. The decrease was primarily due to higher natural gas prices.

Gross profit increased by $0.5 million from $0.2 million for the three months ended September 30, 2004 to $0.7 million for the same period in 2005.  This increase was primarily due to the increase in natural gas prices.

For the three months ended September 30, 2005, the Trust recorded a gain of $0.2 million from the collection of notes receivable relating to the sale of its investment in B-3 and PILP.

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

Revenues decreased approximately $0.1 million, or 10.8%, to $0.7 million for the three months ended September 30, 2004 as compared to $0.8 million for the same period in 2003. This decrease was primarily due to a decrease in Pumping Project revenues.

Cost of revenues for the third quarter of 2004 was $0.5 million as compared to $1.2 million for the third quarter of 2003, a decrease of $0.7 million, or 52.8%. The decrease was primarily due to higher natural gas prices.

Gross profit of $0.2 million for the three months ended September 30, 2004 increased $0.5 million from a loss $0.3 million loss for the same period in 2003.  The gross profit increased primarily due to increases in natural gas prices.

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

Revenues decreased $0.1 million, or 6.6%, from $1.4 million for the six months ended June 30, 2004 to $1.3 million for the six months ended June 30, 2005.  This decrease was primarily due to a decrease of $0.1 million in Pumping Project revenues.

Cost of revenues increased $0.4 million, or 47.4%, from $0.8 million for the six months ended June 30, 2004 to $1.2 million for the six months ended June 30, 2005.  The increase was primarily due to lower natural gas prices.

Gross profit decreased $0.4 million to $0.2 million for the six months ended June 30, 2005 as compared to $0.6 million for the same period in 2004.  The decrease was primarily due to lower natural gas prices.

13

Total assets at June 30, 2005 were $4.3 million, a decrease of $0.7 million from $5 million at December 31, 2004. The decrease was caused by decreases in cash and cash equivalents of $0.3 million and investment in partnership transferred under contractual agreement of $0.4 million. Total liabilities decreased $0.1 million from $0.2 million at December 31, 2004 to $0.1 million at June 30, 2005. This decrease was primarily the result of decreases of in accounts payable and accrued expenses and amounts due to affiliates.

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

Revenues of $1.4 million for the six months ended June 30, 2004 was comparable to the same period in 2003.

Cost of revenues increased $0.2 million to $0.8 million for the six months ended June 30, 2004 from $0.6 million for the same period in 2003.  The increase was primarily due to lower natural gas prices.

Gross profit decreased approximately $0.3 million to $0.6 million for the six months ended June 30, 2004 as compared to $0.9 million for the same period in 2003. This decrease was primarily due to lower natural gas prices in 2004 as compared to 2003.

Total assets at June 30, 2004 were $5.8 million, a decrease of approximately $0.3 million from the December 31, 2003 balance of $6.1 million. The decrease was caused by decreases of $0.4 million in cash and cash equivalents million and $0.2 million in investment in partnership transferred under contractual agreement, partially offset by increases of $0.5 million in the gas forward contract. Total liabilities of $0.2 million at June 30, 2004 was comparable to the balance at December 31, 2003.

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

Revenues of $0.7 million for the second quarter of 2005 was comparable to the second quarter of 2004.

Cost of revenues for the quarter ended June 30, 2005 increased $0.4 million, to $0.9 million from $0.5 million for the same period in 2004. The increase was primarily due to a temporary decline in natural gas prices during the 2005 quarter.

Gross profit decreased $0.4 million to a $0.2 million loss for the three months ended June 30, 2005 as compared to a $0.2 million profit for the same period in 2004.  This decrease was primarily due to the decline in natural gas prices in 2005 as compared to 2004.

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

Revenues of $0.7 million for the second quarter of 2004 was comparable to the second quarter of 2003.

Cost of revenues for the three months ended June 30, 2004 was $0.5 million as compared to $0.3 million for the same period in 2003. The increase of $0.2 million was primarily due to an increase in the price of natural gas.

Gross profit decreased $0.2 million to $0.2 million for the three months ended June 30, 2004 as compared to $0.4 million for the same period in 2003.  This decrease was primarily due to 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 totaled $0.7 million for the three months ended March 31, 2005 and March 31, 2004.

Gross profit was $0.4 million for the three months ended March 30, 2005 and 2004.

General and administrative expenses decreased $35,000, or 43.8%, to $45,000 in the first quarter of 2005 from $80,000 for the same period in 2004, primarily due to lower professional fees.

Total assets at March 31, 2005 were $4.9 million, a decrease of approximately $31,000 from $5 million at December 31, 2004. Total liabilities remained flat at $0.2 million at March 31, 2005 and December 31, 2004.

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

Revenues were $0.7 million for the three months ended March 31, 2005 and 2004.

14

Gross profit decreased approximately $0.1 million to $0.4 million for the three months ended March 30, 2004 as compared to $0.5 million for the same period in 2003. This decrease was primarily due to a decrease in Pumping Project revenues. 

Total assets at March 31, 2004 were $6 million, a decrease of approximately $30,000 from $6.1 million at December 31, 2003. Total liabilities remained flat at $0.2 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 $0.2 million, a decrease of $0.2 million from December 31, 2004. The cash flows for 2005 consisted of $0.6 million provided by operating activities, $0.4 million provided by investing activities and $1.2 million used in financing activities.

In 2005, the Trust’s operating activities provided cash of $0.6 million as compared to $0.2 million in 2004, an increase of $0.4 million, primarily due to increased cash flows from ongoing operations.

In 2005 and 2004, investing activities provided $0.4 million and $0.4 million from collection of notes receivable related to the sale of investments in B-3 and PILP, respectively.

In 2005, the Trust used $1.2 million in financing activities as compared to $1.4 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 $0.4 million, a decrease of $0.8 million from December 31, 2003. The cash flows for the year 2004 consisted of $0.2 million provided by operating activities, $0.4 million provided by investing activities and $1.4 million used in financing activities.

In 2004, the Trust’s operating activities provided cash of $0.2 million as compared to $0.6 million in 2003, a decrease of approximately $0.4 million. This decrease was primarily due to an increase in restricted cash of $0.6 million, offset by a gain on gas purchase contract.

In 2004 the Trust’s investing activities provided cash of $0.4 million as compared to $0.7 million in 2003. Both amounts relate to the collection of payments received from the sale of investments.

In 2004 and 2003, the Trust used cash of $1.4 million in financing activities, which in both cases represents cash distributions to shareholders.

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 $0.1 million, a decrease of $0.3 million from December 31, 2004. The cash flows for the first nine months of 2005 were $0.3 million provided by operating activities, $0.4 million provided in investing activities and $1 million used in financing activities.

Cash provided by operating activities for the nine months ended September 30, 2005 was $0.3 million as compared to $81,000 for the nine months ended September 30, 2004. This 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 $0.1 million in net amounts due to affiliates and $0.2 million of gain from sale of investments.

Cash provided by investing activities provided cash of $0.4 million during the first nine months of 2005 as compared to $0.3 million in the same period 2004, an increase of $0.1 million. This increase in cash provided was primarily due to the collection of payments received from the sale of investments.

Cash used in financing activities was $1 million in the nine months ended September 30, 2005 and $1.1 million in the same period in 2004, which in each case 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 $0.5 million, a decrease of $0.7 million from December 31, 2003. The cash flows for the first nine months of 2004 were $0.1 million provided by operating activities, $0.3 million used in investing activities and $1.1 million used in financing activities.

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Cash provided by operating activities for the nine months ended September 30, 2004 was $81,000 as compared to $0.4 million for the nine months ended September 30, 2003. The decrease in cash flow was primarily due to the elimination of restricted cash of $0.6 million in the 2004 period.

Cash provided by investing activities was $0.3 million during the first nine months of 2004 as compared to $0.6 million in the first nine months of 2003.  The decrease in cash was primarily due to a note receivable that was fully recovered in 2003.

Cash used in financing activities for the first nine months of 2004 and 2003 was $1.1 million, which in each case represents cash 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 $0.1 million, a decrease of approximately $0.3 from December 31, 2004. The decrease was the result of $33,000 provided by operating activities, $0.4 million provided by investing activities and $0.7 million used in financing activities.

Cash provided by operating activities for the six months ended June 30, 2005 was $33,000 as compared to $69,000 for the six months ended June 30, 2004. The decrease in cash flow was primarily due to payments in accounts payable and accrued expenses for the 2005 period.

Cash provided by investing activities was $0.4 million during the first six months of 2005 as compared to $0.2 million in the first six months of 2004.  This increase in cash provided was primarily due to an increase in proceeds related to the collection of payments received from the sale of investments for the 2005 period.

Cash used in financing activities for the first six months of 2005 and 2004 was $0.7 million, which in each case represents cash 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 $0.8 million, a decrease of $0.4 million from December 31, 2003. The decrease was the result of $69,000 provided by operating activities, $0.2 million provided by investing activities and $0.7 million used in financing activities.

Cash provided by operating activities for the six months ended June 30, 2004 was $69,000 as compared to cash used of $31,000 for the six months ended June 30, 2003. The increase in cash provided by operating activities was primarily due to an increase in a gain on gas forward contract of $0.3 million and a decrease of $0.1 million to pay accounts payable and accrued expenses.

Cash provided by investing activities was $0.2 million for the first six months of 2004 and $0.4 million for the first six months of 2003. The decrease in cash was primarily due to collection of a note receivable that was fully collected in the 2003 period.

Cash used in financing activities for the first half of 2004 and 2003 was $0.7 million, each of which represented cash 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 $0.4 million, a decrease of $28,000 from December 31, 2004. The decrease was primarily the result of $0.1 million provided by operating activities. $0.2 million provided by investing activities and $0.3 million used in financing activities.

Cash provided by operating activities for the three months ended March 31, 2005 was $0.1 million as compared to cash provided of $27,000 for the three months ended March 31, 2004. This increase in cash flow in the 2005 period as compared to the 2004 period was primarily due to an increase in accounts payable and accrued expenses.

Cash provided by investing activities was $0.2 million during the first three months of 2005 as compared to $0.1 million in the first three months of 2004.  This increase in cash provided was primarily due to an increase in the collection of payments received from the sale of investments.

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

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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 $1 million, a decrease of $0.2 million from December 31, 2003. The decrease was the result of $27,000 provided by operating activities and $0.1 million provided by investing activities, which was offset by $0.4 million used in financing activities.

Cash provided by operating activities for the three months ended March 31, 2004 was $27,000 as compared to cash used of $74,000 for the three months ended March 31, 2003. The increase of $0.1 million in cash flows from operating activities was primarily the result of increases in accounts payable and accrued expenses.

Cash provided by investing activities was $0.1 million during the first three months of 2004 and $0.3 million for the three months of 2003. This decrease in cash was primarily due to a note receivable that was fully recovered in the 2003 period.

Cash used in financing activities for the first quarter of 2004 and 2003 was $0.4 million, which in each case represents cash distributions to shareholders.

Off-Balance Sheet Arrangements

In connection with the gas supply contract at Monterey, the Trust has issued a standby letter of credit totaling $230,000 at December 31, 2005. The letter 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		1 - 3 years		4 - 5 years		More than 5 years
Ground lease *	$	189	$	12	$	36	$	24	$	117
Gas forward contract, net**		570		570		-		-		-
Total	$	759	$	582	$	36	$	24	$	117

             *    Excludes payments for delivered steam per contract.

             ** Amounts presented are net of forward sales commitments.

The gas forward contract requires Monterey to purchase minimum quantities of natural gas through August 2006. Amounts reflected above are net of agreements to resell the purchased gas back to Monterey’s supplier.

In connection with the ground lease, Monterey has not delivered by-product steam since it was shut down in January 2006. As a result, it may be subject to penalties from the lessor.

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.

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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.

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.

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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:

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.

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.

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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.

ITEM 9A.  CONTROLS AND PROCEDURES

In accordance with Rule 13a-15(b) of 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 March 31, 2005 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 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 10, 2007, management of the Trust concluded that the Trust’s previously issued financial statements for the period ended March 31, 2003 through the period ended March 31, 2005 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 March 31, 2005, 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.

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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, General Counsel and Secretary 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.

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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 235.3775 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	1.45	*
Executive officers as a group	1.45	*

*              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 1.5% of the Trusts’ prior year net asset value, which equals $72, $91 and $109 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.

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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 $133,000, $138,000 and $140,000, respectively, for overhead items allocated in proportion to the amount invested in projects managed. In addition, RPM charged the projects approximately $2,407,000, $2,012,000 and $1,903,000, respectively, for all of the direct operating and non-operating expenses incurred during such periods.

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 $12,000, $14,000 and $14,000 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 other 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*	$	116	$	94	$	94
Audit-Related Fees		-		-		-
Tax Fees		-		-		-
All Other Fees		-		-		-
Total	$	116	$	94	$	94
* These fees are being borne by the Managing Shareholder.

The above table excludes fees for services rendered by Perelson Weiner, the Trust’s original principal accountant for the Trust’s 2004 and 2003 audits. Total fees for services rendered by Perelson Weiner for the Trust’s original 2004 audit and for 2004 tax services totaled $31,000 and $25,000, respectively. Total Perelson Weiner fees for services for the Trust’s 2003 audit and for 2003 tax services totaled $26,000 and $25,000, respectively.

24

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 on Form 10 filed with the SEC on February 27, 1993).
3	(i)(B)	*	Certificate of Amendment to the Certificate of Trust of the Registrant filed with the Delaware Secretary of State on December 18, 2003.
3	(ii)(A)		Amended and Restated Declaration of Trust of the Registrant (incorporated by reference to Exhibit 4 to the Registrant’s Report on Form 10-Q-A for the quarter ended September 30, 1993 filed with the SEC on November 17, 1993, SEC File No. 000-21034).
3	(ii)(B)	*	January 2000 Amendment to Declaration of Trust by Consent of the Registrant.
3	(ii)(C)		Amendment No. 1 to the Declaration of Trust of the Registrant (incorporated by reference to Exhibit A to the Registrant’s Proxy Statement filed with the SEC on November 5, 2001, SEC File No. 000-21304).
10.1		#	Management Agreement between the Trust and Managing Shareholder (incorporated by reference to the Registrant’s Registration Statement on Form 10 filed with the SEC on February 27, 1993).
10.2		*	Long-Term Energy and Capacity Power Purchase Agreement between Sunnyside Cogeneration Partners L.P. and Pacific Gas and Electric Company dated May 1984 (as amended).
10.3		*	Limited Recourse Term Note issued by EAC Operations, Inc. to the Registrant dated September 20, 2002 for $3,000,000 as payment for the B-3 Limited Partnership interests.
10.4		*	Limited Recourse Term Note issued by EAC Operations, Inc. to the Registrant dated September 20, 2002 for $2,000,000 as payment for the Pittsfield Investors Limited Partnership interests.

25

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.

_____________________

* 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.

26

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 II
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

27

RIDGEWOOD ELECTRIC POWER TRUST II
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, and 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 II

We have audited the accompanying consolidated balance sheets of Ridgewood Electric Power Trust II (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 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 II 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 years ended December 31, 2004 and 2003 have been restated as discussed in Note 2 to the consolidated financial statements.

As discussed in Note 10 to the consolidated financial statements, Sunnyside Cogeneration Partners, L.P. ceased operations in January 2006 and recognized an impairment of the remaining net book value of its assets during the first quarter of 2006.

/s/ GRANT THORNTON LLP

Edison, New Jersey

December 13, 2007

F-2

Ridgewood Electric Power Trust II
Consolidated Balance Sheets
(in thousands, except share data)
	December 31,
	2005			2004			2003
				(Restated)			(Restated)
ASSETS
Current assets
Cash and cash equivalents	$	196		$	430		$	1,218
Accounts receivable		420			216			224
Due from affiliates		1			-			15
Gas forward contract - current portion		898			494			223
Other current assets		39			52			42
Total current assets		1,554			1,192			1,722
Plant and equipment, net		1,132			1,258			1,381
Intangibles, net		1,698			1,819			1,940
Investment in partnership transferred under contractual agreement		-			363			808
Gas forward contract - noncurrent portion		-			332			209
Total assets	$	4,384		$	4,964		$	6,060
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	152		$	100		$	111
Due to affiliates		354			62			82
Total current liabilities		506			162			193
Commitments and contingencies
Shareholders' equity (deficit):
Shareholders' equity (235.3775 Investor Shares
issued and outstanding)		4,040			4,955			6,010
Managing shareholder's accumulated deficit
(1 management share issued and outstanding)		(162	)		(153	)		(143	)
Total shareholders' equity		3,878			4,802			5,867
Total liabilities and shareholders' equity	$	4,384		$	4,964		$	6,060

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

.

F-3

Ridgewood Electric Power Trust II
Consolidated Statements of Operations
(in thousands, except per share data)
	Years Ended December 31,
	2005			2004		2003
				(Restated)		(Restated)
Revenues	$	2,817		$	2,826	$	3,009
Cost of revenues		2,650			2,242		2,226
Gross profit		167			584		783
Operating expenses:
General and administrative expenses		138			152		166
Impairment of equipment and intangibles		-			-		190
Management fee to the Managing Shareholder		72			91		109
Total operating expenses		210			243		465
(Loss) income from operations		(43	)		341		318
Other income:
Interest  income		4			6		22
Gain on sale of investments		304			-		-
Other income		-			14		-
Total other income		308			20		22
Net income	$	265		$	361	$	340
Managing Shareholder - Net income	$	3		$	4	$	3
Shareholders - Net income		262			357		337
Net income per Investor Share		1,116			1,516		1,432

 

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

F-4

Ridgewood Electric Power Trust II
Consolidated Statements of Changes in Shareholders' Equity (Deficit)
Years Ended December 31, 2005, 2004 and 2003
(in thousands)
	Shareholders			Managing Shareholder			Total Shareholders' Equity
Shareholders’ balance January 1, 2003,  restated	$	7,085		$	(132	)	$	6,953
Net income,  restated		337			3			340
Distributions		(1,412	)		(14	)		(1,426	)
Shareholders’ balance December 31, 2003,  restated		6,010			(143	)		5,867
Net income,  restated		357			4			361
Distributions		(1,412	)		(14	)		(1,426	)
Shareholders’ balance December 31, 2004,  restated		4,955			(153	)		4,802
Net income		262			3			265
Distributions		(1,177	)		(12	)		(1,189	)
Shareholders’ balance December 31, 2005	$	4,040		$	(162	)	$	3,878

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

F-5

Ridgewood Electric Power Trust II
Consolidated Statements of Cash Flows
(in thousands)
	Years Ended December 31,
	2005			2004			2003
				(Restated)			(Restated)
Cash flows from operating activities:
Net income	$	265		$	361		$	340
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		247			245			349
Impairment of equipment and intangibles		-			-			190
Gas forward contract		(72	)		(395	)		(750	)
Changes in operating assets and liabilties:
Restricted cash		-			-			550
Accounts receivable		(204	)		9			31
Other current assets		14			(11	)		6
Accounts payable and accrued expenses		51			(10	)		(133	)
Due to/from affiliates, net		291			(6	)		34
Total adjustments		327			(168	)		277
Net cash provided by operating activities		592			193			617
Cash flows from investing activities:
Proceeds from notes receivable		-			-			278
Proceeds from investment in partnership
transferred under contractual agreement		363			445			400
Net cash provided by investing activities		363			445			678
Cash flows from financing activities:
Cash distributions to shareholders		(1,189	)		(1,426	)		(1,426	)
Net decrease in cash and cash equivalents		(234	)		(788	)		(131	)
Cash and cash equivalents, beginning of year		430			1,218			1,349
Cash and cash equivalents, end of year	$	196		$	430		$	1,218

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

F-6

Ridgewood Electric Power Trust II
Consolidated Balance Sheets (unaudited)
(in thousands, except share data)
	2005
	September 30			June 30			March 31
ASSETS							(Restated)
Current assets:
Cash and cash equivalents	$	138		$	113		$	402
Accounts receivable		319			247			197
Due from affiliates		-			5			-
Gas forward contract - current portion		1,616			646			736
Other current assets		50			13			49
Total current assets		2,123			1,024			1,384
Plant and equipment, net		1,165			1,196			1,227
Intangibles, net		1,728			1,759			1,789
Investment in partnership transferred under contractual agreement		-			-			141
Gas forward contract - noncurrent portion		-			275			392
Total assets	$	5,016		$	4,254		$	4,933
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	112		$	48		$	148
Due to affiliates		161			43			21
Total current liabilities		273			91			169
Commitments and contingencies
Shareholders' equity (deficit):
Shareholders' equity (235.3775 investor shares
issued and outstanding)		4,897			4,323			4,918
Managing shareholder's accumulated deficit
(1 management share issued and outstanding)		(154	)		(160	)		(154	)
Total shareholders' equity		4,743			4,163			4,764
Total liabilities and shareholders' equity	$	5,016		$	4,254		$	4,933

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

F-7

Ridgewood Electric Power Trust II
Consolidated Balance Sheets (unaudited)
(in thousands, except share data)
	2004
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
ASSETS
Currents assets:
Cash and cash equivalents	$	530		$	774		$	1,022
Accounts receivable		266			290			231
Due from affiliates		1			15			40
Gas forward contract - current portion		587			434			333
Other current assets		64			14			46
Total current assets		1,448			1,527			1,672
Plant and equipment, net		1,288			1,319			1,350
Intangibles, net		1,849			1,880			1,910
Investment in partnership transferred under contractual agreement		508			608			675
Gas forward contract- noncurrent portion		485			485			423
Total assets	$	5,578		$	5,819		$	6,030
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	99		$	104		$	99
Due to affiliates		47			85			97
Total current liabilities		146			189			196
Commitments and contingencies
Shareholders' equity (deficit):
Shareholders' equity (235.3775 investor shares
issued and outstanding)		5,579			5,775			5,977
Managing shareholder's accumulated deficit
(1 management share issued and outstanding)		(147	)		(145	)		(143	)
Total shareholders' equity		5,432			5,630			5,834
Total liabilities and shareholders' equity	$	5,578		$	5,819		$	6,030

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

F-8

Ridgewood Electric Power Trust II
Consolidated Balance Sheets (unaudited)
(in thousands, except share data)
	2003
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
ASSETS
Currents assets:
Cash and cash equivalents	$	1,316		$	1,036		$	1,189
Restricted cash		-			550			550
Accounts receivable		322			292			256
Due from affiliates		15			15			15
Notes receivable		-			47			140
Gas forward contract - current portion		102			206			121
Other current assets		64			24			35
Total current assets		1,819			2,170			2,306
Plant and equipment, net		1,628			1,683			1,741
Intangibles, net		1,971			2,001			2,031
Investment in partnership transferred under contractual agreement		879			1,008			1,074
Gas forward contract- noncurrent portion		91			272			-
Total assets	$	6,388		$	7,134		$	7,152
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	102		$	122		$	89
Due to affiliates		58			57			47
Total current liabilities		160			179			136
Gas forward contract		-			-			51
Total liabilities		160			179			187
Commitments and contingencies
Shareholders' equity (deficit):
Shareholders' equity (235.3775 investor shares
issued and outstanding)		6,367			7,087			7,097
Managing shareholder's accumulated deficit
(1 management share issued and outstanding)		(139	)		(132	)		(132	)
Total shareholders' equity		6,228			6,955			6,965
Total liabilities and shareholders' equity	$	6,388		$	7,134		$	7,152

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

F-9

Ridgewood Electric Power Trust II
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	$	2,107	$	2,154	$	2,261	$	792	$	746	$	835
Cost of revenues		1,250		1,334		1,713		89		547		1,152
Gross profit (loss)		857		820		548		703		199		(317	)
Operating expenses:
General and administrative expenses		106		143		142		34		21		33
Management fee to the Managing Shareholder		54		68		81		18		22		27
Total operating expenses		160		211		223		52		43		60
Income (loss) from  operations		697		609		325		651		156		(377	)
Other income:
Interest income		3		4		20		1		2		8
Gain on sale of investments		193		-		-		167		-		-
Other income		-		21		-		-		-		-
Total other income		196		25		20		168		2		8
Net income (loss)	$	893	$	634	$	345	$	819	$	158	$	(369	)
Managing Shareholder - Net income (loss)	$	9	$	6	$	3	$	8	$	2	$	(4	)
Shareholders - Net income (loss)		884		628		342		811		156		(365	)
Net income (loss) per Investor Share		3,758		2,669		1,453		3,446		663		(1,551	)

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

F-10

Ridgewood Electric Power Trust II
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	$	1,315	$	1,408	$	1,426	$	651		$	708	$	682
Cost of revenues		1,161		787		561		877			498		285
Gross profit (loss)		154		621		865		(226	)		210		397
Operating expenses:
General and administrative expenses		72		122		109		27			42		28
Management fee to the Managing Shareholder		36		46		54		18			23		27
Total operating expenses		108		168		163		45			65		55
Income (loss) from operations		46		453		702		(271	)		145		342
Other income:
Interest income		2		2		12		1			1		4
Gain on sale of investments		26		-		-		26			-		-
Other income		-		21		-		-			7		-
Total other income		28		23		12		27			8		4
Net income (loss)	$	74	$	476	$	714	$	(244	)	$	153	$	346
Managing Shareholder - Net income (loss)	$	-	$	5	$	6	$	(2	)	$	2	$	3
Shareholders - Net income (loss)		74		471		708		(242	)		151		343
Net income (loss) per Investor Share		314		2,001		3,007		(1,028	)		642		1,457

 

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

F-11

Ridgewood Electric Power Trust II
Consolidated Statements of Operations (unaudited)
(in thousands, except per share data)
	Three Months Ended March 31,
	2005		2004		2003
	(Restated)		(Restated)		(Restated)
Revenues	$	664	$	700	$	744
Cost of revenues		284		289		275
Gross profit		380		411		469
Operating expenses:
General and administrative expenses		45		80		82
Management fee to the Managing Shareholder		18		23		27
Total operating expenses		63		103		109
Income from operations		317		308		360
Other income:
Interest income		1		1		8
Other income		-		14		-
Total other income		1		15		8
Net income	$	318	$	323	$	368
Managing Shareholder - Net income	$	2	$	3	$	3
Shareholders - Net income		316		320		365
Net income per Investor Share		1,344		1,362		1,549

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

F-12

Ridgewood Electric Power Trust II
Consolidated Statements 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)
	Shareholders			Managing Shareholder			Total Shareholders' Equity
Three months ended 03/31/03:
Shareholders’ balance January 1, 2003,  restated	$	7,085		$	(132	)	$	6,953
Net income,  restated		365			3			368
Distributions		(353	)		(3	)		(356	)
Shareholders’ balance March 31, 2003,  restated	$	7,097		$	(132	)	$	6,965
Six months ended 06/30/03:
Shareholders’ balance January 1, 2003,  restated	$	7,085		$	(132	)	$	6,953
Net income,  restated		708			6			714
Distributions		(706	)		(6	)		(712	)
Shareholders’ balance June 30, 2003,  restated	$	7,087		$	(132	)	$	6,955
Nine months ended 09/30/03:
Shareholders’ balance January 1, 2003,  restated	$	7,085		$	(132	)	$	6,953
Net income,  restated		342			3			345
Distributions		(1,060	)		(10	)		(1,070	)
Shareholders’ balance September 30, 2003,  restated	$	6,367		$	(139	)	$	6,228
Three months ended 03/31/04:
Shareholders’ balance January 1, 2004,  restated	$	6,010		$	(143	)	$	5,867
Net income,  restated		320			3			323
Distributions		(353	)		(3	)		(356	)
Shareholders’ balance March 31, 2004,  restated	$	5,977		$	(143	)	$	5,834
Six months ended 06/30/04:
Shareholders’ balance January 1, 2004,  restated	$	6,010		$	(143	)	$	5,867
Net income,  restated		471			5			476
Distributions		(706	)		(7	)		(713	)
Shareholders’ balance June 30, 2004,  restated	$	5,775		$	(145	)	$	5,630
Nine months ended 09/30/04:
Shareholders’ balance January 1, 2004,  restated	$	6,010		$	(143	)	$	5,867
Net income,  restated		628			6			634
Distributions		(1,059	)		(10	)		(1,069	)
Shareholders’ balance September 30, 2004,  restated	$	5,579		$	(147	)	$	5,432
Three months ended 03/31/05:
Shareholders’ balance January 1, 2005,  restated	$	4,955		$	(153	)	$	4,802
Net income,  restated		316			2			318
Distributions		(353	)		(3	)		(356	)
Shareholders’ balance March 31, 2005,  restated	$	4,918		$	(154	)	$	4,764
Six months ended 06/30/05:
Shareholders’ balance January 1, 2005,  restated	$	4,955		$	(153	)	$	4,802
Net income		74			-			74
Distributions		(706	)		(7	)		(713	)
Shareholders’ balance June 30, 2005	$	4,323		$	(160	)	$	4,163
Nine months ended 09/30/05:
Shareholders’ balance January 1, 2005,  restated	$	4,955		$	(153	)	$	4,802
Net income		884			9			893
Distributions		(942	)		(10	)		(952	)
Shareholders’ balance September 30, 2005	$	4,897		$	(154	)	$	4,743

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

F-13

Ridgewood Electric Power Trust II
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	$	893		$	634		$	345
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization		183			183			262
Gas forward contract		(789	)		(640	)		(510	)
Changes in operating assets and liabilities:
Restricted cash		-			-			550
Accounts receivable		(103	)		(41	)		(67	)
Other current assets		2			(22	)		(17	)
Accounts payable and accrued expenses		12			(13	)		(141	)
Due to/from affiliates, net		99			(20	)		9
Total adjustments		(596	)		(553	)		86
Net cash provided by operating activities		297			81			431
Cash flows from investing activities:
Proceeds from notes receivable		-			-			278
Proceeds from investment in partnership
transferred under contractual agreement		363			300			328
Net cash provided by investing activities		363			300			606
Cash flows from financing activities:
Cash distributions to shareholders		(952	)		(1,069	)		(1,070	)
Net decrease in cash and cash equivalents		(292	)		(688	)		(33	)
Cash and cash equivalents, beginning of period		430			1,218			1,349
Cash and cash equivalents, end of period	$	138		$	530		$	1,316

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

F-14

Ridgewood Electric Power Trust II
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	$	74		$	476		$	714
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		122			122			176
Gas forward contract		(93	)		(487	)		(794	)
Changes in operating assets and liabilities:
Accounts receivable		(31	)		(65	)		(37	)
Other current assets		39			28			23
Accounts payable and accrued expenses		(53	)		(7	)		(122	)
Due to/from affiliates, net		(25	)		2			9
Total adjustments		(41	)		(407	)		(745	)
Net cash provided by operating activities		33			69			(31	)
Cash flows from investing activities:
Proceeds from notes receivable		-			-			230
Proceeds from investment in partnership
transferred under contractual agreement		363			200			200
Net cash provided by investing activities		363			200			430
Cash flows from financing activities:
Cash distributions to shareholders		(713	)		(713	)		(712	)
Net (decrease) increase in cash and cash equivalents		(317	)		(444	)		(313	)
Cash and cash equivalents, beginning of period		430			1,218			1,349
Cash and cash equivalents, end of period	$	113		$	774		$	1,036

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

F-15

Ridgewood Electric Power Trust II
Consolidated Statements of Cash Flows (unaudited)
(in thousands)
	Three Months Ended March 31,
	2005			2004			2003
	(Restated)			(Restated)			(Restated)
Cash flows from operating activities:
Net income	$	318		$	323		$	368
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization		61			61			88
Gas forward contract		(302	)		(323	)		(386	)
Changes in operating assets and liabilities:
Accounts receivable		19			(7	)		(1	)
Other current assets		4			(5	)		12
Accounts payable and accrued expenses		47			(12	)		(154	)
Due to/from affiliates, net		(41	)		(10	)		(1	)
Total adjustments		(212	)		(296	)		(442	)
Net cash provided by (used in) operating activities		106			27			(74	)
Cash flows from investing activities:
Proceeds from notes receivable		-			-			137
Proceeds from investment in partnership
transferred under contractual agreement		222			133			133
Net cash provided by investing activities		222			133			270
Cash flows from financing activities:
Cash distributions to shareholders		(356	)		(356	)		(356	)
Net decrease in cash and cash equivalents		(28	)		(196	)		(160	)
Cash and cash equivalents, beginning of period		430			1,218			1,349
Cash and cash equivalents, end of period	$	402		$	1,022		$	1,189

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

F-16

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

1. DESCRIPTION OF BUSINESS

Ridgewood Electric Power Trust II (the “Trust”) was formed as a Delaware trust on November 20, 1992.  The Trust began offering shares on January 4, 1993 and concluded its offering on January 31, 1994. 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 Trust have characteristics that qualify the projects for government incentives.

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.

Subsequent to December 31, 2005, the operations of the Trust have significantly changed as more fully described in Note 10.

2.     RESTATEMENT OF FINANCIAL STATEMENTS

The Trust has identified a series of adjustments, including adjustments related to an impairment of assets, accounting for professional service fees, value of the steam by-product generated at one of its plants, and accounting for derivatives, which have resulted in the restatement of the previously issued financial statements of the Trust for the quarter ended March 31, 2005, for the quarters ended March 31, June 30 and September 30 of 2004 and 2003, and for the years ended December 31, 2004 and 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 Sheets
	December 31,
	2004			2003
ASSETS
Gas forward contract	$	60		$	(56	)	(A)
Plant and equipment, net		(114	)		(190	)	(B)
Total assets	$	(54	)	$	(246	)
LIABILITIES AND SHAREHOLDERS' EQUITY
Accrued expenses		(41	)		(40	)	(C)
Shareholders' equity		(13	)		(206	)	(A) (B) (C)
Total liabilities and shareholders' equity	$	(54	)	$	(246	)

F-17

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Statements of Operations	Years ended December 31,
	2004			2003
Revenues, increase	$	325		$	302		(D)
Cost of revenues, decrease		153			452		(A) (B) (D) (E)
General and administrative expenses, (increase)		(7	)		(25	)	(C) (E)
Impairment of equipment and intangibles, (increase)		-			(190	)	(B)
Income from operations, increase		471			539
Other income, (decrease)		(278	)		(488	)	(A) (E)
Other expense, decrease		-			16		(E)
Net income	$	193		$	67
Managing Shareholder - Net income, increase	$	2		$	1
Shareholders- Net income, increase		191			66
Net income per Investor Share, increase		812			282

(A) Originally, the Trust did not properly recognize the market value related to its gas purchase contract. As a result, the Trust recorded a liability value of $316 at the beginning of 2003 with a corresponding decrease to beginning shareholders’ equity. Additionally, the Trust did not properly record the changes in the value of the contract that occurred during 2003 and 2004 and as a result, the Trust recorded a gain of $748 and $393, respectively as a component of cost of revenues. Previously, the Trust recorded the changes in the value of the contract that occurred during 2003 and 2004 to other income.  Accordingly in this restatement, the gain of $488 and $278 was reclassified to cost of revenues during 2003 and 2004, respectively.

(B) In the previously issued financial statements, the Trust failed to recognize an impairment of equipment for irrigation service engines. An impairment was determined, and restated by the Trust, based on projected cash flows to be required effective December 31, 2003.  As a result, the Trust recorded an impairment in 2003 of approximately $190; offset by a decrease to the recorded net book value of the engines.  Furthermore, in 2004, as a result of the impairment, depreciation expense subsequent to the impairment was overstated by $104.  As a result, the Trust decreased depreciation expense and decreased accumulated depreciation by $104.

(C) 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 $41 and $40 of professional fees for the years ended December 31, 2004 and 2003, respectively.  The 2004 over accrual was adjusted by recording a decrease to accrued expenses of $41, and decreases to general and administrative expenses and beginning shareholders’ equity of $2 and $41, respectively.  On December 31, 2003, the overaccrual was adjusted by recording a decrease to accrued expenses of $40, and an increase to general and administrative expenses and beginning shareholders’ equity of $2 and $40, respectively.

(D) In the previously issued financial statements, the Trust failed to value the steam by-product generated at one of its plants that is provided to its site landlord.  Although there was no affect on the Trust’s net operating results, the Trust recorded the value of this by-product as an increase to revenue of $302 and $325 with corresponding increases to cost of revenues in the years ending December 31, 2003 and 2004, respectively.

 (E) Certain items in the previously issued financial statements for the years ended December 31, 2003 and 2004 have been reclassified to conform to the current year presentation.  These reclassifications had no material effect on net income.

The Trust restated 2002 amounts by decreasing the Trust’s beginning shareholders’ equity as of January 1, 2003 by $274. The adjustments recorded that were made to the Trust’s equity as of January 1, 2003, was an overstatement of accrued professional service fees of $42 offset by a decrease in its gas purchase contract of $316.

F-18

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Quarterly Balance Sheets (unaudited)
	March 31
	2005
ASSETS
Gas forward contract	$	(20	)	(A)
Plant and equipment, net		(87	)	(B)
Total assets	$	(107	)
LIABILITIES AND SHAREHOLDERS' EQUITY
Accrued expenses	$	(16	)	(C)
Shareholders' equity		(91	)	(A) (B) (C)
Total liabilities and shareholders' equity	$	(107	)

	2004
	September 30			June 30			March 31
ASSETS
Gas forward contract	$	(247	)	$	(95	)	$	36		(A)
Due from affiliates		-			(2	)		(1	)	(E)
Plant and equipment, net		(129	)		(139	)		(164	)	(B)
Total assets	$	(376	)	$	(236	)	$	(129	)
LIABILITIES AND SHAREHOLDERS' EQUITY
Accrued expenses	$	(4	)	$	9		$	-		(C)
Due to affiliates		-			(2	)		(1	)	(E)
Shareholders' equity		(372	)		(243	)		(128	)	(A) (B)
Total liabilities and shareholders' equity	$	(376	)	$	(236	)	$	(129	)

	2003
	September 30			June 30			March 31
ASSETS
Gas forward contract	$	(60	)	$	478		$	121		(A)
Due from affiliates		(1	)		(2	)		(3	)	(E)
Plant and equipment, net		-			-			-
Total assets	$	(61	)	$	476		$	118
LIABILITIES AND SHAREHOLDERS' EQUITY
Accrued expenses	$	(16	)	$	(9	)	$	(1	)	(C)
Due to affiliates		(1	)		(2	)		(3	)	(E)
Loss on Gas forward contract		-			-			51		(A)
Shareholders' equity		(44	)		487			71		(A) (C)
Total liabilities and shareholders' equity	$	(61	)	$	476		$	118

F-19

Ridgewood Electric Power Trust II

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, increase	$	244		$	227		$	81		$	76		(D)
Cost of revenues, decrease  (increase)		455			292			83			(351	)	(A) (B) (D) (E)
General and administrative expenses, (increase)  decrease		(36	)		(39	)		13			(3	)	(C) (E)
Income (loss) from operations		663			480			177			(278	)
Other income, (decrease)		(831	)		(254	)		(305	)		(254	)	(A)
Other expense, decrease (increase)		2			4			(1	)		1		(E)
Net (loss) income	$	(166	)	$	230		$	(129	)	$	(531	)
Managing Shareholder - Net (loss) income, (decrease) increase	$	(2	)	$	2		$	(1	)	$	(5	)
Shareholders- Net (loss) income, (decrease) increase		(164	)		228			(128	)		(526	)
Net (loss) income per Investor Share, (decrease) increase		(698	)		967			(543	)		(2,233	)

	Six Months Ended June 30,						Three Months Ended June 30,
	2004			2003			2004			2003
Revenues, increase	$	163		$	151		$	82		$	75	(D)
Cost of revenues, decrease		372			643			106			335	(A) (B) (D) (E)
General and administrative expenses, (increase) decrease		(49	)		(36	)		(9	)		6	(C) (E)
Income from operations		486			758			179			416
Other income, (decrease)		(526	)		-			(293	)		-	(A)
Other expense, decrease		3			3			-			-	(E)
Net (loss) income	$	(37	)	$	761		$	(114	)	$	416
Managing Shareholder - Net (loss) income, (decrease) increase	$	(1	)	$	8		$	(1	)	$	4
Shareholders- Net (loss) income, (decrease) increase		(36	)		753			(113	)		412
Net (loss) income per Investor Share, (decrease) increase		(153	)		3,201			(479	)		1,750

Quarterly Statements of Operations (unaudited)	Three Months Ended March 31,
	2004			2003
Revenues, increase	$	81		$	76		(D)
Cost of revenues, decrease		266			308		(A) (B) (D) (E)
General and administrative expenses, (increase)		(40	)		(42	)	(C) (E)
Income from operations		307			342
Other income, (decrease)		(233	)		-		(A)
Other expense, decrease		3			3		(E)
Net income	$	77		$	345
Managing Shareholder - Net income, increase	$	1		$	3
Shareholders- Net income, increase		76			342
Net income per Investor Share, increase		324			1,451

F-20

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

(A) The Trust did not properly account for the changes in the value of its gas purchase contract. As a result, the Trust recorded the following adjustments (unaudited):

	2005			2004									2003
		3/31			9/30			6/30			3/31			9/30			6/30			3/31
Gas forward contract, (decrease) increase	$	(20	)	$	(247	)	$	(94	)	$	36		$	(51	)	$	478		$	70
Beginning shareholders' equity, decrease  (increase)		20			247			94			(36	)		51			(478	)		(70	)
Cost of revenues, (decrease)		(304	)		(640	)		(487	)		(324	)		(510	)		(794	)		(386	)
Other income, decrease		383			831			526			233			254			-			-

(B) The Trust did not properly recognize an impairment of equipment for irrigation service engines.  As a result, the Trust recorded the following adjustments (unaudited):

	2005			2004									2003
		3/31			9/30			6/30			3/31			9/30		6/30		3/31
Plant and equipment, net (decrease)	$	(87	)	$	(129	)	$	(139	)	$	(164	)	$	-	$	-	$	-
Beginning shareholders' equity, decrease		87			129			139			164			-		-		-
Depreciation expense, (decrease)		(26	)		(77	)		(51	)		(26	)		-		-		-

(C) 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):

	2005			2004									2003
		3/31				9/30			6/30			3/31		9/30			6/30			3/31
Accrued professional fees, decrease (increase)	$	16			$	4		$	(9	)	$	-	$	16		$	9		$	1
Beginning shareholders' equity , (increase) decrease		(16	)			(4	)		9			-		(16	)		(9	)		(1	)
General and administrative expenses, increase		26				36			49			40		26			33			41

(D) The Trust failed to value the steam by-product generated at one of its plants that is provided to its site landlord.  Although there was no affect on its net operating results, the Trust recorded the value of this by-product as an increase to revenue with corresponding increases to cost of revenues.  As a result, the Trust recorded the following adjustments (unaudited):

	2005		2004							2003
		3/31			9/30		6/30		3/31		9/30		6/30		3/31
Revenues, increase	$	101		$	244	$	163	$	81	$	227	$	151	$	76
Cost of revenues, increase		101			244		163		81		227		151		76

(E) Originally, the Trust did not properly classify general and administrative 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
Cost of revenues, increase (decrease)	$	2		$	2		$	3		$	(9	)	$	1		$	2
General and administrative expenses, increase		-			-			-			13			3			1
Other expense, (decrease)		(2	)		(2	)		(3	)		(4	)		(4	)		(3	)

F-21

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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.

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.

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 $96, $330 and $1,118, 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 customers.

f) Plant and Equipment

Plant and equipment, consists of equipment, leasehold improvements, and building which 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.

Equipment	3 - 20 years
Leasehold improvements	15 years
Building	20 years

F-22

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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 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.

h) Gas Contract

In August 2001, Monterey entered into an agreement to purchase natural gas, at fixed prices, over a five-year term in connection with entering into an amendment fixing the sales price of electric power sales contracts for a similar term. This contract was entered into in order to minimize the impact of fluctuating energy prices. The Trust has determined that this contract is a derivative as defined under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. The Trust has designated the derivatives as a non-hedge instrument. Accordingly, the value of the contract 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 contract is reflected as a component of cost of revenues in the consolidated statements of operations.

i) 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.

j) Comprehensive Income (Loss)

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

k) Significant Customer and Supplier

During 2005, 2004, and 2003, the Trust’s largest customer, Pacific Gas and Electric Company (“PG&E”), accounted for 88%, 87%, and 80%, respectively, of total revenues.  During 2005, 2004 and 2003, the Trust purchased substantially all of its gas supply from one supplier.

l) Fair Value of Financial Instruments

At December 31, 2005, 2004 and 2003, the carrying value of the Trust’s cash and cash equivalents, accounts receivable, and accounts payable and accrued expenses approximates their fair value.

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.

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.

F-23

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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.

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.  

F-24

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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.

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

Sunnyside Cogeneration Partners,  L.P.

On January 9, 1995, the Trust acquired 100% of the existing partnership interests of Sunnyside Cogeneration Partners, L.P., which owns and operates a 5.5 megawatt (“MW”) electric cogeneration facility, located in Monterey County, California (“Monterey”). The aggregate purchase price was $5,198 including transaction costs. Electricity is sold to PG&E under a long term contract expiring in 2020.

The acquisition of Monterey was accounted for as a purchase and the results of operations of Monterey have been included in the Trust’s consolidated financial statements since the acquisition date.  The purchase price was allocated to the net assets acquired, based on their respective fair values.  Of the purchase price, $3,032 was allocated to the electric power sales contract and is being amortized over the life of the contract of 25 years.

Monterey suspended operations in January 2006. See Note 10 for further discussion.

F-25

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Pump Services Company, LP

In 1995, the Trust purchased a package of irrigation service engines (the “Pumping Project") located in Ventura County, California.  The purchase price was $952.  The Trust performed an impairment assessment in 2003 using a discounted cash flow valuation methodology, and noted the carrying value of the Pumping Project exceeded its estimated fair value. As a result, the Trust recorded an impairment of the remaining net book value of the equipment for $190 in 2003.  The engines were sold in January 2006 for $1.

B-3 Limited Partnership and Pittsfield Investor Limited Partnership

In January 1994, the Trust made an equity investment of $2,300 in Pittsfield Investors Limited Partnership (“PILP”), which was formed to acquire a waste-to-energy project designed and built to burn municipal solid waste supplied by the City of Pittsfield, Massachusetts, surrounding communities and other waste providers as well as to supply steam to a nearby paper mill.  The PILP project originally began operating in 1981 and was operated and co-owned with the Trust by subsidiaries of Energy Answers Corporation (“EAC”). The Trust made an additional investment with affiliates of EAC in August 1994 when it purchased an interest in the B-3 Limited Partnership (“B-3”) for $3,975.  The business of B-3 was the construction and operation of a municipal waste transfer station in Columbia County, New York.  In September 2002, the Trust sold its interests in PILP and B-3 to EAC for $1,200 in cash and $5,000 of promissory notes. The notes bore interest at a rate of 10% per annum, and were to be paid over a 17-year term. The notes were collateralized solely by the assets of the projects and are without recourse to EAC.

Recovery of interest and principal under the promissory notes were dependent upon the operations of the partnership investment transferred. Consequently, the Trust deferred its gain on the sale of its ownership interest until the carrying value of the investments were fully recovered. The cash proceeds received for the interest and principal were recorded as a reduction of its investment in partnership transferred under contractual agreement through June 30, 2005.  The note payments remained current until the notes were paid in full on October 31, 2007.

5.  PLANT AND EQUIPMENT

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

	2005			2004			2003
				(Restated)			(Restated)
Equipment	$	2,935		$	2,935		$	2,935
Leasehold improvements		166			166			166
Building		150			150			150
		3,251			3,251			3,251
Less: accumulated depreciation		(2,119	)		(1,993	)		(1,870	)
	$	1,132		$	1,258		$	1,381

For the years ended December 31, 2005, 2004 and 2003, depreciation expense was $126, $124 (restated) and $228 (restated), respectively, which is included in cost of revenues.

F-26

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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

 

	2005
	September 30			June 30			March 31
							(Restated)
Equipment	$	2,935		$	2,935		$	2,935
Leasehold improvements		166			166			166
Building		150			150			150
		3,251			3,251			3,251
Less: accumulated depreciation		(2,086	)		(2,055	)		(2,024	)
	$	1,165		$	1,196		$	1,227

 Depreciation expense for the 2005 year-to-date periods ended September 30, June 30 and March 31 was $92, $62 and $31 (restated), respectively.

	2004
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Equipment	$	2,935		$	2,935		$	2,935
Leasehold improvements		166			166			166
Building		150			150			150
		3,251			3,251			3,251
Less: accumulated depreciation		(1,963	)		(1,932	)		(1,901	)
	$	1,288		$	1,319		$	1,350

 Restated depreciation expense for the 2004 year-to-date periods ended September 30, June 30 and March 31 was $92, $62 and $31, respectively.

	2003
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Equipment	$	3,125		$	3,125		$	3,125
Leasehold improvements		166			166			166
Building		150			150			150
		3,441			3,441			3,441
Less: accumulated depreciation		(1,813	)		(1,758	)		(1,700	)
	$	1,628		$	1,683		$	1,741

Restated depreciation expense for the 2003 year-to-date periods ended September 30, June 30 and March 31 was $171, $116 and $58, respectively.

6.  INTANGIBLE ASSETS

A portion of the purchase price of Monterey was assigned to electric power sales contracts and is being amortized over the lives of the contracts on a straight-line basis. During 2005, 2004 and 2003, the Trust recorded amortization expense of $121 per year.

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)			(Restated)
Electricity sales contract - gross	$	3,032		$	3,032		$	3,032
Less: accumulated amortization		(1,334	)		(1,213	)		(1,092	)
Intangibles, net	$	1,698		$	1,819		$	1,940

F-27

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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

Years ended
December 31,	Amortization
2006	$	121
2007		121
2008		121
2009		121
2010		121
Thereafter		1,093

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

	2005
	September 30			June 30			March 31
							(Restated)
Electricity sales contract- gross	$	3,032		$	3,032		$	3,032
Less: accumulated amortization		(1,304	)		(1,273	)		(1,243	)
Intangibles, net	$	1,728		$	1,759		$	1,789

Amortization expense for the 2005 year-to-date periods ended September 30, June 30 and March 31, was $90, $60 and $30 (restated), respectively.

	2004
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Electricity sales contract- gross	$	3,032		$	3,032		$	3,032
Less: accumulated amortization		(1,183	)		(1,152	)		(1,122	)
Intangibles, net	$	1,849		$	1,880		$	1,910

Restated amortization expense for the 2004 year-to-date periods ended September 30, June 30 and March 31, was $90, $60 and $30, respectively.

	2003
	September 30			June 30			March 31
	(Restated)			(Restated)			(Restated)
Electricity sales contract- gross	$	3,032		$	3,032		$	3,032
Less: accumulated amortization		(1,061	)		(1,031	)		(1,001	)
Intangibles, net	$	1,849		$	2,001		$	2,031

Restated amortization expense for the 2003 year-to-date periods ended September 30, June 30 and March 31, was $90, $60 and $30, respectively.

7. COMMITMENTS AND CONTINGENCIES

Monterey has a non-cancelable operating lease which expires in May 2021. Future minimum lease payments as of December 31, 2006 are approximately $12 per annum along with the delivery of by-product steam.  Rent expense for the years ended December 31, 2005, 2004 and 2003 was $417, $338 and $315, respectively, including the value of the by-product steam.

Monterey has a long-term agreement to purchase natural gas from its supplier at a fixed price throughout the term, which expired in August 2006.  At December 31, 2005, future minimum purchases under the agreement, net of resale agreements, was $473, all of which occurred in 2006.

F-28

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

During the years ended December 31, 2005, 2004 and 2003, the Trust recorded, as a component of cost of revenues, gains from changes in the fair value of its gas supply contract of $72, $393 and $748, respectively.

The following table provides the contractual obligations and commitments of the Trust for the future minimum payments as of December 31, 2005.

Years ended December 31,	Ground lease *		Gas forward contract, net **
2006	$	12	$	570
2007		12		-
2008		12		-
2009		12		-
2010		12		-
Thereafter		129		-
Total	$	189	$	570

             *    Excludes payments for delivered steam per contract.

             ** Amounts presented are net of forward sales commitments.

In connection with the ground lease, Monterey has not delivered by-product steam since it was shut down in January 2006. As a result, it may be subject to penalties from the lessor. The Trust considers the likelihood of any claim in this matter to be remote.

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.

8. TRANSACTION 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 1.5% 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 $72, $91, and $109, 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.

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, cash distributions to the Managing Shareholder were $12, $14 and $14, respectively. The Trust has not yet reached Payout.

The Managing Shareholder owns 1.45 investor shares. The Trust granted the Managing Shareholder a single Management Share representing the Managing Shareholder's management rights and rights to distributions of cash flow.

F-29

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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 $133, $138 and $140, respectively, for overhead items allocated in proportion to the amount invested in projects managed. In addition, RPM charged the projects $2,407, $2,012 and $1,903, respectively, for all of the direct operating and non-operating expenses incurred during such periods.

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 for the benefit of the trusts and extended the Managing Shareholder’s line of credit, through May 31, 2008.  As part of the agreement, the Trust agreed to limitations on its ability to incur indebtedness, and liens and to provide guarantees.  In August 2003, the Trust issued through its bank a standby letter of credit, in the amount of $504 to secure the gas purchases for Monterey.  In August of 2004, the supplier of natural gas to Monterey agreed to reduce the standby letter of credit to $230.  The standby letter of credit remained at $230 on December 31, 2005 until it expired and was reduced to zero at August 31, 2006.

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)				(Restated)		(Restated)
RPM	$	-	$	-	$	-	$	53	$	61	$	82
RRP		1		-		-		300		-		-
Trust II		-		-		-		1		1		-
Trust III		-		-		10		-		-		-
Trust IV		-		-		5		-		-		-
Other affiliates		-		-		-		-		1		-
Total	$	1	$	-	$	15	$	354	$	63	$	82

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
					(Restated)						(Restated)
RPM	$	-	$	5	$	-	$	48	$	42	$	20
RRP		-		-		-		112		-		-
Trust II		-		-		-		1		1		1
Total	$	-	$	5	$	-	$	161	$	43	$	21

F-30

Ridgewood Electric Power Trust II

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	$	1	$	-	$	25	$	47	$	85	$	97
RRP		-		-		-		-		-		-
Trust II		-		-		-		-		-		-
Trust III		-		10		10		-		-		-
Trust IV		-		5		5		-		-		-
Other affiliates		-		-		-		-		-		-
Total	$	1	$	15	$	40	$	47	$	85	$	97
	2003
	September 30		June 30		March 31		September 30		June 30		March 31
	Due from						Due to
	(Restated)		(Restated)		(Restated)		(Restated)		(Restated)		(Restated)
RPM	$	-	$	-	$	-	$	58	$	57	$	47
RRP		-		-		-		-		-		-
Trust II		-		-		-		-		-		-
Trust III		10		10		10		-		-		-
Trust IV		5		5		5		-		-		-
Other affiliates		-		-		-		-		-		-
Total	$	15	$	15	$	15	$	58	$	57	$	47

9. SELECTED UNAUDITED QUARTERLY FINANCIAL DATA

	2005 Quarters
	1st		2nd			3rd		4th
	(restated)
Revenues	$	664	$	651		$	792	$	710
Gross profit (loss)		380		(226	)		703		(690	)
Income (loss) from operations		317		(271	)		651		(740	)
Net income (loss)		318		(244	)		819		(628	)
Net income (loss) per Investor Share		1,344		(1,028	)		3,446		(2,646	)

		2004 Quarters
	1st		2nd		3rd		4th
	(restated)		(restated)		(restated)		(restated)
Revenues	$	700	$	708	$	746	$	672
Gross profit (loss)		411		210		199		(245	)
Income (loss) from operations		308		145		156		(268	)
Net income (loss)		323		153		158		(273	)
Net income (loss) per Investor Share		1,362		642		663		(1,151	)

F-31

Ridgewood Electric Power Trust II

Notes To Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

	2003 Quarters
	1st		2nd		3rd			4th
	(restated)		(restated)		(restated)			(restated)
Revenues	$	744	$	682	$	835		$	748
Gross profit (loss)		469		397		(317	)		234
Income (loss) from operations		360		342		(378	)		(6	)
Net income (loss)		368		346		(369	)		(5	)
Net income (loss) per Investor Share		1,549		1,457		(1,551	)		(23	)

10. SUBSEQUENT EVENTS

For the first 15 years of operation, PG&E “dispatched” Monterey to produce and deliver electricity up to its contract capacity on a 13 hour per day, five day per week basis (“13x5”).  However, on December 1, 2005, PG&E dispatched Monterey on a 24 hour per day, seven day per week basis (“24x7”) for an indefinite period, effective January 1, 2006. Monterey advised PG&E that its 24x7 dispatch order was a breach of the parties’ power purchase agreement.  Management of Monterey was also concerned that if the facility continued to produce and supply power consistent with the parties’ prior course of performance, PG&E would refuse to pay.  Accordingly, Monterey demanded that PG&E provide adequate assurances that it would continue to pay Monterey for its capacity and its electricity produced and delivered in accordance with the parties’ longstanding 13x5 operations.  PG&E did not provide such assurances.  In the absence of such assurances, Monterey suspended operations on or about January 9, 2006.  Monterey filed a Complaint against PG&E in the San Francisco Superior Court on May 16, 2006 (the “Monterey Complaint”).  The Monterey Complaint seeks damages for breach of contract, damages for PG&E’s breach of the implied covenant of good faith and fair dealing, and a claim for declaratory relief against PG&E, seeking a judicial determination that PG&E’s conduct materially breached the parties’ agreement and justified Monterey’s suspension of performance. Monterey is seeking damages against PG&E estimated at approximately $5,000.  A Jury Trial with regard to this matter is currently set for February 8, 2008.

On May 14, 2007, PG&E filed a Complaint in San Francisco Superior Court against Monterey (the “PG&E Complaint”).  The PG&E Complaint arises out of the same transactions and occurrences that gave rise to the Monterey Complaint against PG&E.  PG&E asserted claims for compensatory damages for breach of contract and breach of the implied covenant of good faith and fair dealing as well as “restitution” of capacity payments made to Monterey on a theory of unjust enrichment, and declaratory relief for repayment of capacity payments made to the Monterey. PG&E is seeking restitution damages against Monterey estimated at approximately $4,800.

The claims made by PG&E have been made solely against Monterey and do not involve any claims against the Trust. Both of the above litigation matters are currently in discovery.  Monterey intends to vigorously prosecute its claims and defend against PG&E’s claims and believes it will ultimately prevail.

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.

On October 31, 2007, the Trust received approximately $5,000 as full payment of the PILP and B-3 notes.

F-32

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 II
(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. al., 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 02:16 PM 12/18/2003
   FILED 02:16 PM 12/18/2003
  SRV 030805634 - 2316790 FILE

EX-3.IIB

                                                                Exhibit 3(ii)(B)

                              CONSENT IN WRITING BY
                                 SOLE MANAGER OF
                               RIDGEWOOD POWER LLC

The undersigned, being the sole manager of Ridgewood Power LLC, a New Jersey
limited liability company (the "Company"), consents in writing to the following
resolutions as of the 1st day of January, 2000:

WHEREAS, the Company is the Managing Shareholder of Ridgewood Electric Power
Trust II, a Delaware business trust (The "Trust") which is treated as a
partnership for federal income tax purposes, and

WHEREAS, the Trust is governed by a Declaration of trust (the "Declaration") as
amended, and

WHEREAS, the Declaration provides for the allocation of profit and loss for tax
purposes in a method that causes the allocation of profit and loss to diverge
from the allocation of distributions among Shareholders of the Trust, and

WHEREAS, Section 15.8(a) of the Declaration authorizes the Managing Shareholder,
without notice to or approval by the Investors, to cure ambiguities, formal
defects and omissions and to correct or supplement inconsistent provisions of
the Declaration, to make other changes so long as the changes do not materially
and adversely affect the interest of any Investor, and to make certain other
amendments, and

WHEREAS, the effect of the changes made by the following resolution are within
the scope of Section 15.8(a),

NOW, THEREFORE, BE IT RESOLVED, that Section 4.2 of the Declaration be amended
to read in its entirety as follows, effective January 1, 2000:

(a)     Profits and Losses from Dispositions Prior to Payout. After giving
effect to the provisions of Sections 4.5, 4.6 and 7.4, Profits or Losses from
Dispositions prior to Payout (as defined in Section 8.1 (g)) shall be allocated
99% to Investors and 1% to the Managing Shareholder.

(b)     Profits from Dispositions after Payout: After giving effect to the
provisions of Sections 4.5, 4.6 and 7.4, Profits from Dispositions after Payout
(as defined in Section 8.1(g)) shall be allocated among the Shareholders as
follows:

        (1)     First, the Investors and the Managing Shareholder in proportion
                to any deficit balances in their respective Capital Accounts
                until such Capital Account is restored to zero;
        (2)     Second, 100% to the Investors until the aggregate of the
                Investors' Capital Account equals the Unreturned Investor
                Amounts;
        (3)     Third, 100% to the Managing Shareholder in an amount equal to
                the Managing Shareholder Target Amount; and
        (4)     The balance, if any, 80% to the Investors and 20% to the
                Managing Shareholder.

(c)     Losses from Dispositions After Payout. After giving effect to the
provisions of Sections 4.5, 4.6 and 7.4, Losses from Dispositions after Payout
(as defined in Section 8.19g)) shall be allocated among the Shareholders as
follows:



        (1)     First, 99% to the Investors and 1% to the Managing Shareholder
                until the Managing Shareholder's Capital Account equals 20% of
                Shareholder' aggregate Capital Account balances (including the
                Managing Shareholder's Capital Account); and

        (2)     Second, the balance, if any, 80% to the Investors and 20% to the
                Managing Shareholder

RESOLVED, that the officers of the Company, be, and each of them is, authorized
to do or cause to be done any act or thing and to make, execute and deliver any
amendment, certificate, agreement, instrument or document necessary or
appropriate, in his or their sole discretion, to effectuate the foregoing
resolution, the taking of any such action or the execution of any such document
to be conclusive evidence of the authorized exercise of the discretionary
authority herein conferred.

IN WITNESS WHEREOF, I have signed this Consent in Writing this 20th day of
March, 2001.



                              /s/ Robert E. Swanson
                              ---------------------
                                Robert E. Swanson

EX-10.2

                                                                    Exhibit 10.2

                            Power Purchase Agreement
                            ------------------------


The Sunnyside Project operates under a Standard Offer No. 2 Power Purchase
Agreement with PG&E, which provides for the following:

Term:               30 years from date operations commenced (May 1991).

Capacity:           5,500 Kilowatts, firm, delivered to PG&E system (after
                    considering parasitic requirements of the plant site).

Capacity            $209.00 per Kilowatt-year plus bonuses of up to $36.88 per
Price:              kilowatt-year. Both are subject to a line-loss adjustment
                    factor of .989 to yield net capacity payments of $206.70 and
                    $36.48, respectively.

Capacity            See Capacity Payments Section herein.
Payements:

Energy              100% of PG&E's full short-run avoided operating cost
Price:              ("SRAC") per Kilowatt hour as approved by the California
                    Public Utilities Commission. (Prices vary between On-Peak,
                    Partial-Peak, Off-Peak and Super-Off-Peak hours, and differ
                    between Period A and Period B.)

Availability:       During applicable operating period (generally 13 hours per
                    day), the Project must be available to operate at a minimum
                    of 80% of contract capacity. The Project is "dispatchable"
                    and may be called upon by PG&E to produce electricity at any
                    time.

Payments:           PG&E shall provide statements and issue checks in favor of
                    the Project on a monthly basis. (in general, the Project
                    receives capacity and energy payments within 35 days of the
                    last day of the month in which power is produced, e.g., May
                    revenues are collected by July 5.)

Scheduled           The Project may have outages of up to 840 hours per year for
Maintenance         scheduled maintenance. (Scheduled Maintenance outages are
Outages:            generally not permitted during On-Peak hours of the three
                    Peak Months.)

                                       41


                           Capacity Payments From PG&E
                           ---------------------------


Capacity Payment Revenues consist of Base Capacity Payments and Capacity
Bonuses. A combined formula which calculates the total Capacity Payments for a
month is shown below:


                 Capacity Payment = Period Price Factor ("PPF")

                                      Times
                                      -----

                       Monthly Delivered Capacity ("MDC")

                                      Times
                                      -----


                  Capacity Line Loss Adjustment Factor ("CLAF")

                                      Times
                                      -----

                        Performance Bonus Factor ("PBF")


PPF:    The Period Price Factor segments the annual Base Capacity Payment per
        Kilowatt of contract capacity into a monthly base payment per Kw which,
        for Sunnyside, is equal throughout the year.

                           Base Capacity
                               PG&E's                  Payment
                           Monthly Factor               Per Kw
                           --------------               ------
        January                 8.3333%                $ 17.42
        February                8.3333                   17.42
        March                   8.3333                   17.42
        April                   8.3333                   17.42
        May                     8.3333                   17.42
        June                    8.3333                   17.42
        July                    8.3333                   17.42
        August                  8.3333                   17.42
        September               8.3333                   17.42
        October                 8.3333                   17.42
        November                8.3333                   17.42
        December                8.3333                   17.42
                              --------                 -------
                              100.0000%                $209.00
                              ========                 =======

                                       42


MDC:    Monthly Delivered Capacity is the product of (x) contract firm capacity
        of the facility times (y) the actual Monthly Capacity Factor ("MCF")
        achieved during the month during both On-Peak and Partial-Peak hours (a
        total of 13 hours per day during Period A).

        The contract firm capacity of the Project is 5,500 Kw.

        The Monthly Capacity Factor, MCF, represents (1) the actual electric
        output of the facility during applicable hours divided by (2) (i)
        contract firm capacity times (ii) hours in the period (minus PG&E's
        forced outage hours and scheduled maintenance hours) times (iii) 80%.
        The MCF is limited to not more than 1.0 (100%).

        Thus, by operating the Project at 80% of contract capacity during the
        On-Peak and Partial-Peak hours (13 hours) for the month the MDC equals:


                                Contract
                                  Firm
                                Capacity         MCF          MDC
                                --------         ---          ---

                                5,500      X     1  =        5.500


CLAF:   This factor is a multiplier designed to account for line losses which
        occur between (x) the point of delivery into PG&E's system and (y) the
        point of delivery to the ultimate end-user. Contractually, PG&E and the
        Protect have agreed that the line-loss is 1.1%, hence a factor of .989
        (98.9%)

PBF:    The Performance Bonus Factor is designed to increase the Capacity
        Payment by a "Capacity Bonus". Eligibility for the Capacity Bonus
        payment is measured relative to the On-Peak hours (noon to 6:00 p.m.
        weekdays) of each Peak Month (June, July and August). A Capacity Bonus
        can be earned by any Project that exceeds an 85% average output
        (measured solely with reference to the energy produced by the Project's
        contractually specified firm capacity) during the On-Peak hours of the
        three Peak Months. The "Performance Bonus Factor (PBF) is a multiplier
        representing the percentage (up to 17.65%) by which the Projects On-Peak
        output exceeds 85% of contract firm capacity. Thus, a Performance Bonus
        Factor of 1.1765 (the maximum PBF; 100% divided by 85% = 1.1765 or
        1.1765% of contract firm capacity) represents a 100% capacity factor
        during the On-Peak hours of each of the Peak Months. (The PBF is 1.0 for
        output between 80% and 95% of capacity during the On-Peak hours.) In
        determining Capacity Bonus Payments. PG&E has the right to, and does,
        accumulate performance for up to five consecutive Bonus Periods.

                                       43


The Maximum Capacity Payment for the Sunnyside Project is shown below:



                                             Kilowatts
                           Period             Monthly            Capacity      Performance       Maximum
                           Price             Delivered          Line-Loss         Bonus         Capacity
                           Factor            Capacity             Factor         Factor          Payment
                           ------            --------             ------         ------          -------
                            PPF       x        MDC         x       CLAF     x     PBF      =
                                                                               
January                   $ 17.42             5,500                .989           1.176       $  111,456
February                    17.42             5,500                .989           1.176          111,456
March                       17.42             5,500                .989           1.176          111,456
April                       17.42             5,500                .989           1.176          111,456
May                         17.42             5,500                .989           1.176          111,456
June                        17.42             5,500                .989           1.176          111,456
July                        17.42             5,500                .989           1.176          111,456
August                      17.42             5,500                .989           1.176          111,456
September                   17.42             5,500                .989           1.176          111,456
October                     17.42             5,500                .989           1.176          111,456
November                    17.42             5,500                .989           1.176          111,456
December                    17.42             5,500                .989           1.176          111,456
                            -----                                                 -----          -------
                          $209.00                                                 1.176       $1,337,477
                          =======                                                 =====       ==========

Base Payment                                                                      1.000       $1,136,856
Bonus Payment                                                                      .176          200,621
                                                                                   ----          -------
                                                                                  1.176       $1,337,477
                                                                                  =====       ==========



Threshold Output

In order to meet the contractual obligations of supplying firm capacity, and to
become "eligible" for receiving the full amount of firm capacity payments, a
Project must deliver its contractually specified firm capacity for all of PG&E's
On-Peak hours (12:00 noon - 6:00 p.m.) during each of the Peak Months (June,
July and August), subject to a 20% forced outage rate (forced by equipment
failure, etc.). (Maintenance outages are generally not permitted during the Peak
Months.) Stated another way, an average of at least 80% of the
contractually-specified firm capacity must be delivered during each of the
On-Peak hours in each of the Peak Months. Failure to meet this minimum
performance standard will result in the Project being placed on probation for a
period not to exceed 15 months, during which time Capacity Payments will be
reduced in accordance with the contract. If at the end of the probation period
the Project cannot meet the performance requirements for the firm capacity it
has pledged, PG&E can permanently de-rate the Project's firm capacity.

                                       44

EX-10.3

                                                                    Exhibit 10.3

                           LIMITED RECOURSE TERM NOTE

$3,000,000                                                      Albany, New York
                                                              September 20, 2002

        On or before October 1, 2019, for value received, EAC Operations, Inc.,
a New York corporation ("Borrower"), promises to pay to Ridgewood Electric Power
Trust II ("Lender"), or order, at its place of business at 947 Linwood Avenue,
Ridgewood, New Jersey 07450, or such other place as the holder of this Note may
designate, the principal sum of Three Million Dollars ($3,000,000.00) U.S., or,
if less, the outstanding principal balance of all loans and advances made by
Lender hereunder, together with accrued interest at the rate set forth below
calculated on the basis of the actual days elapsed and a 365-day year and a
366-day leap year.

1.      Interest Rate. Interest shall accrue at the rate of Ten Percent (10%)
per annum.

2.      Payment. Principal and interest shall be payable as follows:

        (a)     On October 1, 2002, Borrower shall make a payment of all
interest that has accrued on this Note from the date of this Note through
September 30, 2002.

        (b)     On the 1st day of each month, beginning on November 1, 2002, and
continuing until, and including, October 1, 2004, Borrower shall make a monthly
payment of interest only of Twenty Five Thousand Dollars ($25,000.00).

        (c)     On the 1st day of each month, beginning on November 1, 2004, and
continuing until maturity, Borrower shall make a combined monthly payment of
principal and interest of Thirty Two Thousand Two Hundred Thirty Eight Dollars
and Fifteen Cents ($32,238.15), which amount consists of a principal payment
sufficient to amortize the outstanding principal balance of this Note over a
period of 15 years from October 1, 2004, plus all accrued interest and charges.

        (d)     The entire principal balance of this Note, plus accrued and
unpaid interest and any other charges due hereunder, shall be due and payable on
October 1, 2019, if not paid sooner.

        (e)     At the option of Lender, any interest not paid within thirty
(30) days of the date it becomes due, shall be added to principal and become a
part thereof and thereafter bear interest at the same rate (including any
applicable default rate) as the principal.

3.      Prepayment. This Note may be prepaid in whole, but not in part, at any
        time with the following prepayment premium: if this Note is prepaid in
        whole prior to the third anniversary of the date of this Note, the
        prepayment premium shall be Six Hundred Thousand Dollars ($600,000.00);
        if this Note is prepaid in whole on or after the third anniversary of
        the date of this Note, the prepayment premium shall decrease by Sixty
        Thousand Dollars ($60,000.00) as of such third anniversary and further
        decrease by Sixty Thousand Dollars ($60,000.00) upon each such

                                       1


        anniversary thereafter (such that no prepayment premium shall be payable
        on and after the twelfth anniversary of the date of this Note). Any such
        prepayment premium shall be payable by Borrower to Lender upon
        prepayment of this Note.

4.      Books and Records. The actual amount due and owing from time to time
under this Note shall be evidenced by Lender's books and records of receipts and
disbursements hereunder. Lender shall set up and establish for Borrower an
account on the books of Lender in which will be recorded payments and other
appropriate debits and credits in connection with this Note. Lender shall also
record, in accordance with customary accounting practice, all other interest,
charges, expenses and other items properly chargeable to Borrower, and other
appropriate debits and credits. Such books and records of Lender shall be
presumed to be complete and accurate and shall be deemed correct, except to the
extent shown by Borrower to be erroneous.

5.      Joint and Several Obligation. This Note shall be the joint and several
obligation of all makers, sureties, guarantors and endorsers, and shall be
binding upon them and their successors and assigns.

6.      Default and Default Remedies. Borrower hereby consents and expressly
agrees that upon an Event of Default under the Loan Agreement by and between
Lender, Borrower, B-3 Limited Partnership and Pittsfield Investors Limited
Partnership of even date herewith (the "Loan Agreement"), the unpaid balance of
this Note shall, at the option of the holder hereof at once become due and
payable without further demand or notice. Notwithstanding the foregoing, a PILP
Non-Extension Default (as defined in the Loan Agreement) shall not constitute a
default under this Note, and the holder hereof shall have no right to demand
payment of the unpaid balance of this Note or exercise any other remedies
hereunder as a result of a PILP Non-Extension Default. Interest shall continue
to be charged on the unpaid principal plus accrued interest after default at the
rate otherwise applicable under this Note, plus 5% per annum, all at the option
of the Lender, until the indebtedness is paid in full. Failure to exercise any
rights or remedies hereunder shall not constitute a waiver of such right in the
event of a subsequent default. Upon the occurrence of a default or event of
default, Borrower promises to pay all costs of collection, including reasonable
attorney's fees.

7.      Security.

        (a)     The indebtedness evidenced by this Note and any renewals or
extension thereof is secured by the B-3 Collateral, as evidenced by the B-3
Collateral Documents (as such terms are defined in the Loan Agreement). Upon an
Event of Default (other than a PILP Non-Extension Default), the Lender shall be
entitled to exercise any and all remedies available under the B-3 Collateral
Documents. Borrower consents and agrees that all of terms, conditions and
covenants in the B-3 Collateral Documents including, but not limited to, Events
of Default under the Loan Agreement and the Lender's rights as to acceleration
of the indebtedness evidenced by this Note, are incorporated herein by reference

                                       2


and made a part hereof. This Note is given to Lender pursuant to the Loan
Agreement, and the holder of this Note shall be subject to the obligations of
Lender under the Loan Agreement.

8.      Miscellaneous. If any provision of this Note should conflict with
applicable law, such conflict shall not affect any other provision which can be
given effect without the conflicting provision, and to this end the provisions
of this Note are declared to be severable. If any part of this Note is deemed
ambiguous, such ambiguity shall not be resolved against Lender simply because
Lender was the author of this Note. All rights and obligations hereunder shall
be governed by the laws of the State of New York, and Borrower hereby submits to
the jurisdiction of any court of competent jurisdiction in New York. Borrower
expressly waives trial by jury of any issue arising out of Lender's enforcement
of this note and Lender's granting and administering the loan represented
hereby. Waiver of or acquiescence in any default by Borrower, or failure of
Lender to insist upon strict performance by Borrower of any provision of this
Note, shall not constitute a waiver of any subsequent or other default or
failure. No provision of this Note shall be amended or modified, except in a
writing signed by both Borrower and Lender. Except in connection with a
Permitted Transfer (as defined in the Loan Agreement). Borrower may not assign
any of its rights or delegate any of its obligations under this Note without the
prior written consent of Lender, which may be withheld in Lender's sole
discretion. The rights and obligations of Lender under the terms of this Note
are freely assignable by Lender.

9.      Limited Recourse Nature of Note. The limited recourse provisions of
Section 18 of the Loan Agreement are hereby incorporated by reference into this
Note.

        IN WITNESS WHEREOF, the undersigned have executed this Note as of the
date set forth above.

                                            EAC OPERATIONS, INC.

/s/ Thomas Moody                            By:/s/ Larry D. Richardson
- ---------------------                          -------------------------------
Witness                                     Larry D. Richardson, President



                                       3

EX-10.4

                                                                    Exhibit 10.4

                           LIMITED RECOURSE TERM NOTE

$2,000,000                                                      Albany, New York
                                                              September 20, 2002

        On or before October 1, 2019, for value received, EAC Operations, Inc.,
a New York corporation ("Borrower"), promises to pay to Ridgewood Electric Power
Trust II ("Lender"), or order, at its place of business at 947 Linwood Avenue,
Ridgewood, New Jersey 07450, or such other place as the holder of this Note may
designate, the principal sum of Two Million Dollars ($2,000,000.00) U.S., or, if
less, the outstanding principal balance of all loans and advances made by Lender
hereunder, together with accrued interest at the rate set forth below calculated
on the basis of the actual days elapsed and a 365-day year and a 366-day leap
year.

1.      Interest Rate. Interest shall accrue at the rate of Ten Percent (10%)
per annum.

2.      Payment. Principal and interest shall be payable as follows:

        (a)     On October 1, 2002, Borrower shall make a payment of all
interest that has accrued on this Note from the date of this Note through
September 30, 2002.

        (b)     On the 1st day of each month, beginning on November 1, 2002, and
continuing I until, and including, October 1, 2004, Borrower shall make a
monthly payment of interest only of Sixteen Thousand Six Hundred Sixty Six
Dollars and Sixty Seven Cents ($16,666.67).

        (c)     On the 1st day of each month, beginning on November 1, 2004, and
continuing until maturity, Borrower shall make a combined monthly payment of
principal and interest of Twenty One Thousand Four Hundred Ninety Two Dollars
and Ten Cents ($21,492.10), which amount consists of a principal payment
sufficient to amortize the outstanding principal balance of this Note over a
period of 15 years from October 1, 2004, plus all accrued interest and charges.

        (d)     The entire principal balance of this Note, plus accrued and
unpaid interest and any other charges due hereunder, shall be due and payable on
October 1, 2019, if not paid sooner.

        (e)     Notwithstanding the foregoing, prior to October 1, 2004,
Borrower will have the option to defer up to fifty percent (50%) of the interest
payment due in any given month upon delivery of notice of such deferral to
Lender. All amounts so deferred shall be added to the principal amount of this
Note and bear interest at ten percent (10%) per annum beginning on October 1,
2004. The combined monthly payment of principal and interest set forth above
shall be increased to reflect the addition of such deferred interest to the
principal amount of this Note and the interest accruing thereon.

        (f)     Other than as provided in Section 2(e) above, at the option of
Lender, any interest not paid within thirty (30) days of the date it becomes
due, shall be added to principal and become a part thereof, and thereafter bear
interest at the same rate (including any applicable default rate) as the
principal.

                                       1


3.      Prepayment. This Note may be prepaid in whole, but not in part, at any
time with the following prepayment premium: if this Note is prepaid in whole
prior to the third anniversary of the date of this Note, the prepayment premium
shall be Four Hundred Thousand Dollars ($400,000.00); if this Note is prepaid in
whole on or after the third anniversary of the date of this Note, the prepayment
premium shall decrease by Forty Thousand Dollars ($40,000.00) as of such third
anniversary and further decrease by Forty Thousand Dollars ($40,000.00) upon
each such anniversary thereafter (such that no prepayment premium shall be
payable on and after the twelfth anniversary of the date of this Note). Any such
prepayment premium shall be payable by Borrower to Lender upon prepayment of
this Note.

4.      Books and Records. The actual amount due and owing from time to time
under this Note shall be evidenced by Lender's books and records of receipts and
disbursements hereunder. Lender shall set up and establish for Borrower an
account on the books of Lender in which will be recorded payments and other
appropriate debits and credits in connection with this Note. Lender shall also
record, in accordance with customary accounting practice, all other interest,
charges, expenses and other items properly chargeable to Borrower, and other
appropriate debits and credits. Such books and records of Lender shall be
presumed to be complete and accurate and shall be deemed correct, except to the
extent shown by Borrower to be erroneous.

5.      Joint and Several Obligation. This Note shall be the joint and several
        obligation of all makers, sureties, guarantors and endorsers, and shall
        be binding upon them and their successors and assigns.

6.      Default and Default Remedies. Borrower hereby consents and expressly
agrees that upon an Event of Default under the Loan Agreement by and between
Lender, Borrower, B-3 Limited Partnership and Pittsfield Investors Limited
Partnership of even date herewith (the "Loan Agreement"), the unpaid balance of
this Note shall, at the option of the holder hereof at once become due and
payable without further demand or notice. Interest shall continue to be charged
on the unpaid principal plus accrued interest after default at the rate
otherwise applicable under this Note, plus 5% per annum, all at the option of
the Lender, until the indebtedness is paid in full. Failure to exercise any
rights or remedies hereunder shall not constitute a waiver of such right in the
event of a subsequent default. Upon the occurrence of a default or event of
default, Borrower promises to pay all costs of collection, including reasonable
attorney's fees.

7.      Security

        (a)     The indebtedness evidenced by this Note and any renewals or
extension thereof is secured by the PILP Collateral, evidenced by the PILP
Collateral Documents (as such terms are defined in the Loan Agreement). Upon an
Event of Default, the Lender shall be entitled to exercise any and all remedies
available under the PILP Collateral Documents. Borrower consents and agrees that
all of terms, conditions and covenants in the PILP Collateral Documents
including, but not limited to, Events of Default under the Loan Agreement and
the Lender's rights as to acceleration of the indebtedness evidenced by this

                                       2


Note, are incorporated herein by reference and made a part hereof. This Note is
given to Lender pursuant to the Loan Agreement, and the holder of this Note
shall be subject to the obligations of Lender under the Loan Agreement.

8.      Miscellaneous. If any provision of this Note should conflict with
applicable law, such conflict shall not affect any other provision which can be
given effect without the conflicting provision, and to this end the provisions
of this Note are declared to be severable. If any part of this Note is deemed
ambiguous, such ambiguity shall not be resolved against Lender simply because
Lender was the author of this Note. All rights and obligations hereunder shall
be governed by the laws of the Commonwealth of Massachusetts, and Borrower
hereby submits to the jurisdiction of any court of competent jurisdiction in
Massachusetts. Borrower expressly waives trial by jury of any issue arising out
of Lender's enforcement of this note and Lender's granting and administering the
loan represented hereby. Waiver of or acquiescence in any default by Borrower,
or failure of Lender to insist upon strict performance by Borrower of any
provision of this Note, shall not constitute a waiver of any subsequent or other
default or failure. No provision of this Note shall be amended or modified,
except in a writing signed by both Borrower and Lender. Except in connection
with a Permitted Transfer (as defined in the Loan Agreement), Borrower may not
assign any of its rights or delegate any of its obligations under this Note
without the prior written consent of Lender, which may be withheld in Lender's
sole discretion. The rights and obligations of Lender under the terms of this
Note are freely assignable by Lender.

9.      Limited Recourse Nature of Note. The limited recourse provisions of
Section 18 of the Loan Agreement are hereby incorporated by reference into this
Note.

        IN WITNESS WHEREOF, the undersigned have executed this Note as of the
date set forth above.

                                            EAC OPERATIONS, INC.

/s/ Thomas Moody                            By:/s/ Larry D. Richardson
- ---------------------                          -------------------------------
Witness                                     Larry D. Richardson, President



                                       3

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

Subsidiary	Jurisdiction of Organization
RW Monterey, Inc.	California
Sunnyside Cogeneration Partners, LP	California
Ridgewood Pump Services Corporation	California
Pump Services Company, L.P.	California

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 II;

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 II;

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 II (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