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, 2006

or

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:  0-25430

RIDGEWOOD ELECTRIC POWER TRUST IV

 (Exact Name of Registrant as Specified in Its Charter)

Delaware	22-3324608
(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 October 31, 2007 was 476.8875.

FORM 10-K

TABLE OF CONTENTS

PART I

Item 1.	Business	1
Item 1A.	Risk Factors	7
Item 1B.	Unresolved Staff Comments	10
Item 2.	Properties	11
Item 3.	Legal Proceedings	11
Item 4.	Submission of Matters to a Vote of Security Holders	11
PART II
Item 5.	Market for Registrant’s Common Equity, Related Security Holder Matters and Issuer Purchases of Equity Securities	11
Item 6.	Selected Financial Data	11
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	16
Item 8.	Financial Statements and Supplementary Data	16
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	16
Item 9A.	Controls and Procedures	17
Item 9B.	Other Information	17
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	18
Item 11.	Executive Compensation	19
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	20
Item 13.	Certain Relationships and Related Transactions, and Director Independence	21
Item 14.	Principal Accountant Fees and Services	22
PART IV
Item 15.	Exhibits and Financial Statement Schedules	22
SIGNATURES		24

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 results, performance and achievements projected, expected, expressed or implied by the forward-looking statements. Examples of events that could cause actual results to differ materially from historical results or those anticipated include changes in political and economic conditions, federal or state regulatory structures, government mandates, the ability of customers to pay for energy received, supplies and prices of fuels, operational status of generating plants, mechanical breakdowns, volatility in the price for electric energy, natural gas, or renewable energy. Additional information concerning the factors that could cause actual results to differ materially from those in the forward-looking statements is contained in Part I, Item 1A. “Risk Factors” and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and elsewhere in this Annual Report on Form 10-K. The Trust undertakes no obligation to publicly revise any forward-looking statements or cautionary factors, except as required by law.

PART I

ITEM 1.  BUSINESS

Overview

The Trust is a Delaware trust formed on September 8, 1994 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 using renewable sources of fuel. These projects allow the Trust to develop secure long-term positions in attractive specialty markets for products and services provided by its projects and companies. As of December 31, 2006, the projects in which the Trust then had investments were located in the United States. As of that date, the Trust had investments in landfill gas-fired electric generating projects with total capacity of 13.8 megawatts (“MW”), in irrigation service engines with total capacity of 2.4MW, in biomass-fueled electricity generating projects with total generating capacity of 49MW, and in hydroelectric generating projects with total capacity of 11.3MW.

The Trust initiated its private placement offering in February 1995 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 September 1996 and after payment of offering fees, commissions and investment fees, the Trust had $39.5 million available for investments and operating expenses. As of October 31, 2007, the Trust had 476.8875 Investor Shares outstanding, held by 1,048 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 investments, RRP locates potential projects, conducts appropriate due diligence and negotiates and completes the transactions in which the investments are made by the Trust.

In addition, RRP 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, 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.

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As compensation for its management services, the Managing Shareholder is entitled to (i) an annual management fee, payable monthly, equal to 3% of the Trust's prior year net asset value (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, such 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, 2006, all of the Trust’s projects are owned through investment vehicles that the Trust co-owns with certain affiliated investment trusts or are managed by the Managing Shareholder.

Projects and Properties

The following table is a summary of the Trust’s investment portfolio as of December 31, 2006 detailing the nature of the business, the portion of the investment owned by the Trust and the number of projects in each investment.

Company	No. of Sites	Trust Interest	Leased/ Owned1	Purpose	Structure2
Ridgewood Providence3	1 location	64.3%	Leased	Electricity Generation	Steel building/ concrete slab
Ridgewood Pump Services4	20 locations	100%	Owned	Irrigation Service  Engines	Engines
Indeck Maine5	2 locations	25%	Owned	Electricity  Generation	Industrial compound
Maine Hydro6	14 locations	50%	Owned	Hydroelectric Generation	Integral to river dams

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

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

³ Co-owned with Ridgewood Electric Power Trust III (“Trust III”). The facility is located in Rhode Island.

⁴ Assets of Ridgewood Pump Services were sold in January 2006. 

⁵ Co-owned with Ridgewood Electric Power Trust V (“Trust V”) (25%) and Indeck Energy Services LLC, an unaffiliated entity (50%). Both plants are located in northeastern Maine.

⁶ Co-owned with Trust V. All sites are located in Maine.

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Ridgewood Providence

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

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

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

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

On January 17, 2003, Ridgewood Providence received a “Statement of Qualification” from the Massachusetts Division of Energy Resources (“DOER”) pursuant to the RPS adopted by Massachusetts. Since Ridgewood Providence has now become qualified, it is able to sell to retail electric suppliers the RPS Attributes associated with its electrical energy. Retail electric suppliers need to purchase RPS Attributes associated with renewable energy and not necessarily the energy itself. Thus, electrical energy and RPS Attributes are separable products and need not be sold or purchased as a bundled product. Retail electric suppliers in Massachusetts will then use the purchase of such RPS Attributes to demonstrate compliance with the Restructuring Act and RPS regulations.

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

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

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

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Ridgewood Pump Services

Ridgewood Pump Services IV Partners, L.P. ("Ridgewood Pump Services") was formed in 1995. Ridgewood Pump Services purchased a package of irrigation service engines (the “Pumping Project") located in Ventura County, California. The purchase price was approximately $354,000 and from 1996 to 1998, the Trust bought additional engines from unaffiliated sellers. The Trust's total investment in the Pumping Project was approximately $877,000. RPM operates and manages the Pumping Project. Prior to its acquisition by the Trust, the Pumping Project had been operating since 1992 and had 20 natural-gas-fired reciprocating engines with a maximum rated equivalent capacity of approximately 2.4MW, providing power for irrigation wells furnishing water for citrus orchards. The power was purchased by local farmers and farmers' co-operatives pursuant to electric services contracts. The revenue generated from the Pumping Project was not material to the Trust’s operating results and in January 2006, the engines were sold for $1 to the local operator.

Indeck

On June 11, 1997, the Trust and Trust V (collectively the “Ridgewood Indeck Investors”) purchased, through capital contributions totaling $14.2 million, equal portions in a preferred membership interest in Indeck Maine Energy, L.L.C., an Illinois limited liability company (“Indeck Maine”) that owns two electric power generating stations fueled by clean wood biomass at West Enfield, Maine and Jonesboro, Maine. Indeck, an entity unaffiliated with the Trust, owns the remaining membership interest in Indeck Maine and was the seller in the June, 1997 transaction. Ridgewood Indeck Investors have a preferred membership interest entitling them to receive all net cash flow from operations each year until they receive an 18% annual cumulative return on their capital contributions to Indeck Maine.

From January 1998 to June 2006, Ridgewood Indeck Investors in Indeck Maine loaned an aggregate of approximately $8.2 million to Indeck Maine, in proportion to their ownership interests.

Each of the Indeck Maine projects has a capacity of 24.5MW and each uses a steam turbine to generate electricity. The plants were commissioned in November 1986 and use wood chips, bark, tree limbs and tops and other forest-related biomass as fuel. The Indeck Maine projects are members of the New England Power Pool (“NEPOOL”) and have historically sold their output to the ISO New England (a regional transmission organization serving the New England states). In September 2007, Indeck Maine was awarded a six-month contract to supply electricity to a specified segment of the Maine electricity consumers market. It is anticipated that approximately 50% of the output of the plants during the period of the contract will be sold and delivered pursuant to this award.

Indeck Maine and several of its affiliates have an agreement with a power marketer for which they are committed to sell RPS Attributes derived from their electric generation. The agreement provides such power marketer with six separate annual options to purchase such attributes from 2004 through 2009 at fixed prices, as defined. If Indeck Maine and its affiliates fail to supply the required number of RPS Attributes, penalties may be imposed. In accordance with the terms of the agreement, if the power marketer elects to exercise an annual option and Indeck Maine and its affiliates produce no RPS Attributes for such option year, Indeck Maine and its affiliates face a maximum penalty, which is adjusted annually for the change in the consumer price index, among other things, of approximately $3,283,000, measured using current factors, for that option year and any other year in which an option has been exercised and no RPS Attributes have been produced. Pursuant to the agreement, Indeck Maine is liable for 70% of the total penalty, but may be liable up to 100% in the event of a default of its affiliates.

The plants are operated and maintained by RPM, on an at-cost basis and their output qualifies for section 45 federal tax credits. The federal tax credit eligibility of the projects is expected to continue until the fourth quarter of 2009.

Maine Hydro

In 1996, the Trust and Trust V formed Ridgewood Maine Hydro Partners, L.P. (“Maine Hydro”) for the purpose of acquiring a portfolio of hydroelectric facilities from CHI Energy, Inc. The Trust and Trust V own equal interests in Maine Hydro. On December 23, 1996, Maine Hydro acquired 14 hydroelectric projects located in Maine from CHI Energy, Inc. for $13.4 million. The projects acquired have a combined 11.3MW of generating capacity and are operated under contract by RPM on an at-cost basis. The acquired projects were commissioned between 1980 and 1987.

Since before the time of the acquisition by Maine Hydro, the electricity generated by the Maine Hydro projects has been sold under long-term electricity sales contracts with either Central Maine Power or Bangor Hydro-Electric Company. Eleven of the purchase agreements expire at the end of 2008 and one each expires in 2007, 2014 and 2017. When the contracts expire, it is anticipated that the affected projects will sell their output on the wholesale power market.

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Significant Customers and Supplier

During 2006, 2005 and 2004, the Trust’s two largest customers, NEP and Select Energy, accounted for 80.7%, 79.5% and 77.9%, respectively, of total revenues. During 2006, 2005 and 2004, the Trust purchased 100% of its landfill gas from one supplier, CGLP.

Business Segments

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

Project Feedstock/Raw Materials

The Ridgewood Providence and Indeck projects of the Trust each convert a raw material into a finished product and the arrangements for obtaining these raw materials are a key element in the business of the Trust. The landfill facilities consist of reciprocating engine generator sets that use methane-containing landfill gas as fuel. Each project location owns and operates a network of wells, pipes and fans that collect gas from the landfills as produced through natural anaerobic digestion of the waste. Ridgewood Providence does not own or operate the landfill but has arrangements with site owner/operator which give the projects certain rights, including the right to build the projects, occupy the compound, operate the gas collection system and use the gas from the landfill. This agreement is a long-term agreement and includes provisions for royalty payments from the projects to the landfill operator as compensation for the granting of these rights.

The Trust’s hydroelectric projects are all located on, and are integral parts of, dams on river ways. Most of the projects of the Trust are considered run-of-river, meaning that they generate such electricity as the natural flow of the river will produce with little or no ability to alter its flow rate or store water up-river of the dam. Output of these projects (and hence revenue) is characterized by high degrees of variability and seasonality. The projects do not make payments for throughput water.

Competition

Power generated from Ridgewood Providence and Maine Hydro is sold pursuant to long-term contracts. Since Indeck Maine has historically sold output in its wholesale markets, competition is focused on wood supplies as the projects compete mostly with non-power generation businesses like paper and lumber companies for forest material. This competition is based on price, consistency of demand and relationships with suppliers. The Indeck Maine projects also compete for this material, in part, by their ability to use clean biomass that is waste-wood in certain other applications. Also, there are geographic limits to this competition because this clean biomass can only be economically transported over relatively short distances. Beginning in 2006, Indeck Maine has attempted to compete in the market to deliver electricity to final customers through supply auctions. Success in such auctions is based largely on price, reliability and financial strength but success can bring higher prices to the Indeck Maine projects than are available in the wholesale market.

Seasonality/Weather Effects

Ground conditions in the tree harvesting areas that Indeck Maine projects look to for fuel can have a considerable impact on the price, quality and availability of that fuel. During periods of spring and fall rains and during periods of spring thaw, fuel suppliers may not have suitable access to tree-harvesting areas for the purpose of bringing fuel out of those areas. Also, fuel collected during these times tends to have a higher moisture content which reduces its value as a fuel. The prices received by Indeck Maine for its electricity output follow seasonal demand trends so that prices tend to be lower in the moderate spring and fall and higher in the winter and summer as demand for heating and cooling increases.

The output of the Trust’s hydroelectric projects is affected by seasonal weather patterns including rainfall and snowpack runoff. These factors tend to concentrate the output of these projects in the spring and fall with little or no output in the winter and summer months. Management of these sites takes advantage of these patterns to perform maintenance during periods of low output. Because river flows are the dominant factor in determining the output of the hydroelectric projects, output can vary widely from year-to-year based on amounts of rain and snowfall.

Government Incentives and Regulation

Certain of the projects of the Trust qualify for incentives because of their location or their use of renewable fuels.

In 1997, Massachusetts enacted the Electric Restructuring Act of 1997 (the “Restructuring Act”). Among other things, the Restructuring Act requires that all retail electricity suppliers in Massachusetts (i.e., those entities supplying electric energy to retail end-use customers in Massachusetts) purchase a minimum percentage of their electricity supplies from qualified new renewable generation units powered by one of several renewable fuels, such as solar, biomass or landfill. Beginning in 2003, each such retail supplier must obtain at least one (1%) percent of its supply from qualified new renewable generation units. Each year thereafter, the requirement increases one-half of one percentage point until 2009, when the requirement equals four (4%) percent of each retail supplier’s sales in that year. Subsequent to 2009, the increase in the percentage requirement will be determined and set by DOER.

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On January 17, 2003, Ridgewood Providence received a “Statement of Qualification” from the DOER pursuant to the RPS adopted by Massachusetts.  During 2004, Ridgewood Providence also became qualified to sell RPS Attributes in Connecticut under a similar RPS program, except that the Connecticut program does not have a “vintage” prohibition, which in Massachusetts disqualifies the amount of a facility’s generation of electric energy measured by its average output during the period 1995 through 1997. Thus, Ridgewood Providence can sell the 86,000 MWhs that are ineligible under Massachusetts standards into the Connecticut market.

On July 8, 2002, Indeck Maine received a “Statement of Qualification” from the DOER pursuant to the renewable portfolio standards (“RPS”) adopted by Massachusetts.

Since Ridgewood Providence and Indeck Maine have been qualified, they have sold to retail electric suppliers the RPS Attributes associated with their electrical energy. Retail electric suppliers need to purchase RPS Attributes associated with renewable energy and not necessarily the energy itself. Thus, electrical energy and RPS Attributes are separable products and need not be sold or purchased as a bundled product. Retail electric suppliers in Massachusetts and Connecticut will then use the purchase of such RPS Attributes to demonstrate compliance with the Restructuring Act and RPS regulations.

The hydroelectric projects operate under the terms of the Federal Energy Regulatory Commission (“FERC”) licenses issued to them. Even though these projects have no employees, they are affected by general employment regulations in the jurisdictions of its facilities through the RPM operations and maintenance agreements. The Trust considers these regulations to be routine and does not consider the cost of compliance to be material.

Insurance

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

Employees

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

Offices

The principal office of the Trust is located at 1314 King Street, Wilmington, Delaware, 19801 and its phone number is 302-888-7444. The Managing Shareholder’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.

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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.

The Trust’s landfill methane business depends on the production of landfill methane from the landfill sites on which they operate and access to that gas production.

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

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

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

The Trust’s biomass business can be affected by factors including weather and business conditions in other industries.

Greater than normal amounts of rain or snowfall, while benefiting hydroelectric projects of the Trust, could adversely affect the ability of suppliers to provide wood fuel to the Indeck Maine projects, which could result in increased supply costs. Conversely, moderate weather could adversely affect the prices Indeck Maine receives for its electricity generation. As a result, the projects could have to reduce production, or alternatively, suspend its operations. Changes in conditions of the paper, lumber or other wood-products industries in the area of the plants could increase competition for the material used by the Indeck Maine projects for fuel. Such a circumstance could adversely impact operations of the projects by reducing availability of fuel to the plants or by increasing the cost of fuel.

The Trust’s hydroelectric business can be affected by adverse weather conditions.

The Trust’s hydroelectric generation projects rely on rainfall and snowfall to provide water flow for electricity production. Rainfall and snowfall vary from year-to-year and an extended period of below-normal rainfall and/or snowfall would significantly reduce electricity revenue. Each project is entirely dependent on the water flow through where it is located.

Certain of the Trust’s projects sell all or a portion of their electricity output at open market prices and could be adversely affected should prices fall substantially.

Portions of the Trust’s revenues come from open market pricing and the reliance on this pricing will be increasing over the next few years. Should the price of electricity fall substantially, the Trust would be adversely affected and it is possible that the projects affected could not be operated profitably.

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

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

The operations of the Trust may experience competitive price pressure and competition for project development opportunities.

Competition for new project opportunities is based largely on price, service and reliability. While it is difficult to displace the existing projects of the Trust from their customers, competition exists for new projects and this competition may, in some circumstances, drive down the prices of the products and services offered by the Trust’s projects or drive up the costs of its feedstock resources.

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

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

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

This area of risk is inherently difficult to predict but could include matters such as the owners of dams or hydroelectric generators to provide for fish passages either upstream or downstream of the dams that affect Maine Hydro. Such changes could increase costs at affected projects or prevent certain projects from operating.

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

The Trust may become involved in litigation.

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

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.

8

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

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

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

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

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

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

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

The Managing Shareholder is entitled to receive an annual management fee from the Trust regardless of whether the Trust is profitable in that year. The annual fee, payable monthly, is equal to 3% of the Trust's prior year net asset value. In addition to its annual management fee, the Managing Shareholder, as compensation for its management services, will receive 20% of the Trust’s cash distributions to shareholders upon the shareholders having received a certain minimum level of distributions as set out in the Declaration of Trust, even though the Managing Shareholder has not contributed any cash to the Trust. Accordingly, shareholders contribute all of the cash utilized for the Trust’s investments and activities. If the Trust’s projects are unsuccessful, the shareholders may lose 100% of their investment while the Managing Shareholder will not suffer any investment losses because it did not contribute any capital. None of the compensation to be received by the Managing Shareholder has been derived as a result of arm’s length negotiations.

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

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

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.

9

TAX RISKS ASSOCIATED WITH AN INVESTMENT IN SHARES

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

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

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

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

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

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

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

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

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

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

The IRS may audit the Trust’s tax returns. Any audit issues will be resolved at the Trust level by the Managing Shareholder.

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

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

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

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

ITEM 1B.  UNRESOLVED STAFF COMMENTS

Not applicable.

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ITEM 2.  PROPERTIES

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

ITEM 3.  LEGAL PROCEEDINGS

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

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

None.

PART II

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

Market Information

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

Holders

As of October 31, 2007 and December 31, 2006, there were 1,047 and 1,051 holders of Investor Shares, respectively.

Dividends

Trust distributions for the years ended December 31, 2006 and 2005 were as follows (in thousands, except per share data):

	2006		2005
Distributions to Investors	$	3,734	$	1,307
Distributions per Investor Share		8,000		2,500
Distributions to Managing Shareholder		38		13

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, 2006, 2005 and 2004 and the consolidated balance sheet data as of December 31, 2006 and 2005, are derived from audited financial statements included in this Form 10-K. The consolidated statement of operations data for the years ended December 31, 2003 and 2002 and the consolidated balance sheet data as of December 31, 2004, 2003 and 2002 are derived from audited consolidated financial statements not included in this Form 10-K.  The consolidated statement of operations and the consolidated balance sheet data for the year ended December 31, 2002 are derived from audited consolidated financial statements that have not been restated, and as a result, may not be comparable to subsequent periods.

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	December 31,
(in thousands, except per share data)	2006		2005		2004		2003			2002
Consolidated Statement of Operations Data (1):
Revenues	$	12,037	$	12,261	$	12,727	$	9,105		$	8,028
Net income (loss)		3,147		4,216		448		(1,314	)		(1,374	)
Net income (loss) per Investor Share		6,533		8,752		677		(2,728	)		(2,853	)
Consolidated Balance Sheet Data:
Plant and equipment, net		8,561		9,351		10,234		11,029			11,305
Total assets		23,668		24,404		22,054		24,554			27,633
Long-term debt (less current portion)		-		-		-		-			867
Minority interest		4,566		4,632		5,070		5,489			5,717
Shareholders' equity		17,934		17,838		14,887		15,853			18,960

(1) Increase in 2004 revenues was a result of Ridgewood Providence becoming qualified to sell to retail electric suppliers the RPS Attributes associated with its electrical energy in the states of Massachusetts and Connecticut.

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.

Overview

The Trust is a Delaware trust formed on September 8, 1994 to primarily make investments in projects and businesses in the energy and infrastructure sectors. RRP, 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 using renewable sources of fuel. These projects allow the Trust to develop secure long-term positions in attractive specialty markets for products and services provided by its projects and companies. As of December 31, 2006, the projects in which the Trust had investments were located in the United States. As of that date, the Trust had investments in landfill gas-fired electric generating projects with total capacity of 13.8MW, in biomass-fueled electricity generating projects with total generating capacity of 49MW and in hydroelectric generating projects with total capacity of 11.3MW.

The Trust’s accompanying consolidated financial statements include the financial statements of Ridgewood Providence and Ridgewood Pump Services. The Trust’s consolidated financial statements also include the Trust’s 25% interest in Indeck Maine and its 50% interest in Maine Hydro which are accounted for under the equity method of accounting as the Trust has the ability to exercise significant influence but does not control the operating and financial policies of these investments.

The Trust owns a 64.3% interest in Ridgewood Providence and the remaining 35.7% minority interest is owned by Trust III. The interests of Trust III are presented as minority interest in the consolidated financial statements of the Trust.

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.

12

Revenue Recognition

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

Renewable attribute revenue is derived from the sale of the RPS Attributes. Qualified renewable electric generation facilities produce RPS Attributes when they generate electricity. Renewable attribute revenue is recorded in the month in which the RPS Attributes are produced as Ridgewood Providence has substantially completed its obligations for entitled benefits, represented by the underlying generation of power within specific environmental requirements.

Sublease revenue is recorded monthly in accordance with the terms of the sublease agreement.

Accounts Receivable

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

Plant and Equipment

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

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

Impairment of Intangibles and Long-Lived Assets

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

Management Fee

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

Income Taxes

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

13

Results of Operations

Year ended December 31, 2006 compared to the year ended December 31, 2005

Revenues decreased by approximately $0.3 million, or 1.8%, from $12.3 million in 2005 to $12 million in 2006. The decrease in power generation revenue of $0.4 million was due to the sale of Ridgewood Pump Service operations in January 2006, partially offset by an increase of $0.1 million in revenues from Ridgewood Providence resulting from slightly higher production in 2006 compared to 2005.

Cost of revenues decreased by approximately $0.2 million, or 1.9%, from $9.4 million for 2005 to $9.2 million in 2006. This was primarily attributable to a decrease in cost of revenues of Ridgewood Pump Services by $0.4 million, partially offset by higher royalty expense of $0.2 million driven by increased revenue at Ridgewood Providence.

Gross profit of $2.8 million for 2006 decreased $0.1 million, or 1.5%,  from 2005 gross profit of $2.9 million. This decrease was primarily due to decreased revenues.

General and administrative expenses decreased by approximately $0.1 million from $0.3 million in 2005 to $0.2 million in 2006. The decrease was primarily attributable to lower professional fees.

The management fee due to the Managing Shareholder for 2006 was $0.5 million compared to $0.4 million for 2005. The management fee was paid to the Managing Shareholder for certain management, administrative and advisory services, office space and other facilities provided to the Trust. In 2006, the Managing Shareholder waived its right to receive $0.7 million of 2006 and prior years unpaid accrued management fees and interest.

In 2006, the Trust recorded equity income of $1 million from its investment in Maine Hydro compared to $0.6 million in 2005. The increase in equity income of approximately $0.4 million was primarily the result of the increase in revenues resulting from higher production and decrease in impairment expenses of property, plant and equipment and electricity sales agreements in 2006.

In 2006, the Trust recorded equity income of $0.6 million from its investment in Indeck Maine compared to $2.2 million in 2005. The decrease in equity income of approximately $1.6 million was primarily due to an increase in cost of revenues resulting from higher fuel expenses in 2006 compared to 2005.

Net income for the 2006 period was $3.1 million, a decrease of approximately $1.1 million from net income of $4.2 million for the comparable period in 2005. The decrease in net income was primarily due to a decrease in equity income from Indeck Maine, partially offset by an increase in equity income from Maine Hydro.

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

Revenues decreased by approximately $0.4 million, or 3.7%, from $12.7 million in 2004 to $12.3 million in 2005. This decrease was primarily due to decreases of $0.3 million in power generation revenue and $0.1 million in renewable attribute revenue. Production output decreased by 3,078 MWh, or 3%, to 99,577 MWh in 2005 as compared to 2004.

Cost of revenues of $9.4 million for 2005 was comparable to cost of revenues in 2004.

Gross profit decreased by approximately $0.3 million, or 11.2%, from $3.2 million in 2004 to $2.9 million in 2005. Gross profit margin in 2005 decreased to 23.5% from 25.5% in 2004 primarily due to the decrease in revenues.

General and administrative expenses increased by approximately $0.1 million from $0.2 million in 2004 to $0.3 million in 2005. The increase was primarily attributable to higher professional fees.

The management fee due to the Managing Shareholder of $0.4 million for 2005 was comparable to the 2004 management fee. The management fee was paid to the Managing Shareholder for certain management, administrative and advisory services, office space and other facilities provided to the Trust.

Interest income increased by approximately $0.2 million, from $0.2 million in 2004 to $0.4 million in 2005, reflecting interest earned on a higher note receivable balance in the 2005 period.

In 2005, the Trust recorded equity income of $0.6 million from its investment in Maine Hydro compared to $0.5 million in 2004. The increase in equity income of $87,000 was primarily due to an increase in revenue resulting from higher production in 2005 compared to 2004, partially offset by an increase in cost of revenues. In addition, 2004 equity income included settlement of a legal complaint with the prior manager of the Maine Hydro projects which resulted in the receipt of $0.5 million in damages and the waiver of $0.4 million in fees as settlement of past due invoices, allocated equally between the Trust and Trust V.

14

In 2005, the Trust recorded equity income of $2.2 million from its investment in Indeck Maine compared to an equity loss of $1.6 million in 2004. The increase in equity income of $3.8 million was primarily due to an increase in gross profit in 2005 as compared to 2004 as a result of Indeck Maine experiencing increased revenues from the resumption of one of its operations (“Eastport Project”) in May 2004. This increase was partially offset by an increase in interest expense payable on member loans and increased general and administrative expenses.

Minority interest in the earnings of subsidiaries decreased $0.2 million, from earnings of $1.2 million in 2004 to $1 million in 2005. This was due to a decrease in the net earnings of Ridgewood Providence in 2005 as compared to 2004.

Net income for the 2005 period was $4.2 million, an increase of approximately $3.8 million from the net income of $0.4 million for the comparable period in 2004. The increase in net income was primarily due to an increase in equity income from Indeck Maine.

Liquidity and Capital Resources

Year ended December 31, 2006 compared to the year ended December 31, 2005

At December 31, 2006, the Trust had cash of $0.8 million, an increase of approximately $0.2 million from December 31, 2005. The cash flows for the year 2006 were $4.3 million provided by operating activities, $0.7 million provided by investing activities and $4.8 million used in financing activities.

In 2006, the Trust’s operating activities generated cash of $4.3 million compared to $3.9 million in 2005, an increase of approximately $0.4 million, primarily due to a decrease in accounts receivable resulting from improved collection efforts.

In 2006, investing activities provided cash of $0.7 million compared to cash used of $1.2 million in 2005, an increase of cash inflow of approximately $1.9 million. This increase in cash provided in 2006 was due to loans in 2005 made to Indeck Maine and Ridgewood Power B Fund/Providence Expansion (“B Fund”) of $1 million and $0.2 million, respectively.  In addition, the increase in cash inflow in 2006 was also due to the repayment of $0.2 million in notes receivable from the B Fund and $0.5 million in interest received on the Indeck Maine loan.

In 2006, the Trust used cash of $4.8 million in financing activities, primarily as a result of $1.1 million and $3.8 million used for cash distributions to minority interest and shareholders, respectively.  In 2005, the Trust used cash of $2.8 million, which includes $1.5 million and $1.3 million of cash distributions to minority interest and shareholders, respectively.

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

At December 31, 2005, the Trust had cash of $0.6 million, a decrease of $93,000 from December 31, 2004. The cash flows for the year 2005 were $3.9 million provided by operating activities, $1.2 million used in investing activities and $2.8 million used in financing activities.

In 2005, the Trust’s operating activities generated cash of $3.9 million compared to $4.1 million in 2004, a decrease of approximately $0.2 million, primarily due to an increase in accounts receivable partially offset by an increase in net income.

In 2005, investing activities used $1.2 million compared to $1 million in 2004. The increase was primarily due to the $207,000 loan to B Fund.

In 2005, the Trust used cash of $2.8 million in financing activities, primarily as a result of $1.5 million used for cash distributions to minority interest holders and $1.3 million for cash distributions to shareholders. In 2004, the Trust used $3.1 million of cash in financing activities primarily as a result of $1.5 million used for cash distributions to shareholders, $1.6 million in cash distributions to minority interest holders and $0.8 million for term loan repayments. In addition, in 2004, the restricted cash balance of $0.8 million was applied to the outstanding term loan in accordance with the loan agreement.

Future Liquidity and Capital Resource Requirements

The Trust expects cash flows from operating activities, along with existing cash, will be sufficient to provide working capital and fund capital expenditures for the next 12 months.

15

Off-Balance Sheet Arrangements

The Trust has not entered into any off-balance sheet arrangements that either have, or are reasonable likely to have, a material adverse current or future effect on the Trust’s financial condition, revenues or expenses, result of operations, liquidity, capital expenditures or capital resources that are material to the Trust.

Contractual Obligations and Commitments

The Trust has no contractual obligations and commitments at December 31, 2006.

Recent Accounting Pronouncements

FIN 48 

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”) an interpretation of FASB Statement No. 109, Accounting for Income Taxes. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 will be effective for the Trust beginning January 1, 2007. The Trust does not believe that the adoption of FIN 48 will have a material impact on its consolidated financial statements.

SFAS 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), to define fair value, establish a framework for measuring fair value in accordance with generally accepted accounting principles (GAAP) and expand disclosures about fair value measurements. SFAS 157 requires quantitative disclosures using a tabular format in all periods (interim and annual) and qualitative disclosures about the valuation techniques used to measure fair value in all annual periods. SFAS 157 will be effective for the Trust beginning January 1, 2008. The Trust is currently evaluating the impact of adopting SFAS 157.

SAB 108

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 requires analysis of misstatements using both an income statement (rollover) approach and a balance sheet (iron curtain) approach in assessing materiality and provides for a one-time cumulative effect transition adjustment. SAB 108 is effective for fiscal years ending on or after November 15, 2006. The adoption of this standard did not have a material impact on the Trust’s consolidated financial statements.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 will be effective for the Trust on January 1, 2008. The Trust is currently evaluating the impact of adopting SFAS 159 on its 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

None.

16

ITEM 9A.  CONTROLS AND PROCEDURES

In accordance with Rule 13a-15(b) under the Exchange Act, the Trust’s Chief Executive Officer and Chief Financial Officer, evaluate 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, 2006, which revealed that the following material weaknesses previously identified continue to exist:

(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.

The Trust’s Chief Executive Officer and Chief Financial Officer have concluded that there was no change in the Trust's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act, as amended) that occurred during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

Since December 31, 2006, the Trust has implemented the following to address the above weaknesses:  

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

· 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’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 the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act and concluded that, as of the end of the period covered by this report, because of the material weaknesses noted above, the Trust’s disclosure controls and procedures were not effective.   

Because the Trust is not an “Accelerated Filer” as defined in Rule 12b-2 of the Exchange Act, the Trust is not presently required to file Management’s annual report on internal control over financial reporting and the Attestation report of the registered public accounting firm required by Item 308(a) and (b) of Regulation S-K promulgated under the Securities Act of 1933, as amended.  Under current rules, because the Trust is neither a “large accelerated filer” nor an “accelerated filer”, the Trust is not required to provide management’s report on internal control over financial reporting until the Trust files its annual report for 2007 and compliance with the auditor’s attestation report requirement is not required until the Trust files its annual report for 2008.  The Trust currently expects to comply with these requirements at such time as the Trust is required to do so.

ITEM 9B.  OTHER INFORMATION

None.

17

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Trust’s Managing Shareholder, RRP, 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.

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

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

18

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 not to 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. 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, and Director Independence”.

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 Robert E. Swanson during the year ended December 31, 2006 as he failed to timely file a Form 4. This report has since been filed with the SEC.

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 in accordance with the terms of the Trust’s Declaration of 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.

19

Compensation Discussion and Analysis

The executive officers of the Trust, Mr. Holmes, Mr. Swanson, Mr. Strasberg, Mr. Gulino and Mr. Wilson, are employed by, and are executive officers of, the Managing Shareholder and provide managerial services to the Trust in accordance with the terms of the Trust’s Declaration of Trust. The Trust does not have any other executive officers. The Managing Shareholder determines and pays the compensation of these officers. Each of the executive officers of the Trust also serves as an executive officer of each of the other investment trust managed by the Managing Shareholder. Messrs. Swanson, Strasberg and Gulino also serve in similar capacities for trusts managed by affiliates of the Managing Shareholder. Because the executive officers are not employees of the Trust and provide managerial services to all of the trusts managed by the Managing Shareholder and its affiliates in the course of such employment, they do not receive additional compensation for providing managerial services to the Trust.

The Managing Shareholder is fully responsible for the payment of compensation to the executive officers, and the Trust does not pay any compensation to its executive officers and does not reimburse the Managing Shareholder for the compensation paid to executive officers. The Trust does, however, pay the Managing Shareholder a management fee and the Managing Shareholder 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, and Director Independence” for more information regarding Managing Shareholder compensation and payments to affiliated entities.

Report of the Managing Shareholder

Because the Trust is managed by the Managing Shareholder and does not have a Board of Directors or a Compensation Committee, the Managing Shareholder reviewed and discussed with management the Compensation Discussion and Analysis included in this Annual Report on Form 10-K. Based on such review and discussion, the Managing Shareholder determined that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for filing with the Securities and Exchange Commission.

Submitted by the Managing Shareholder

Robert E. Swanson, Chairman

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

The following table sets forth information with respect to the beneficial ownership of the Trust’s Investor Shares as of December 31, 2006 (no person owns more than 5%) by:

· each executive officer of the Trust (there are no directors); 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 476.8875 Investor Shares outstanding at December 31, 2006. 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	2.0331	*
Executive officers as a group	2.0331	*

*  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, and Director Independence”.

20

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Under the terms of the 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 3% of the Trusts’ prior year net asset value, which equals $535,000 for the year ended December 31, 2006, 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.

For the year ended December 31, 2006, the Trust accrued interest expense of $62,000 on accrued but unpaid management fees. The interest accrued has been waived by the Managing Shareholder and recorded as capital contribution in the period waived.

The shareholders of the Trust other than the Managing Shareholder were allocated 99% of each contribution and the Managing Shareholder was allocated 1% so that the amount of the contribution allocated offset the amount of the expense initially accrued. For the year ended December 31, 2006, the Trust made management fee payments to the Managing Shareholder of $257,000.  In the fourth quarter of 2006, the Managing Shareholder forgave $278,000 of 2006 unpaid accrued management fees and $381,000 of prior years unpaid accrued management fees, which were recorded as deemed capital contributions.

Under the Management Agreement with the Managing Shareholder, 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 Trust. 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. For the year ended December 31, 2006, RPM charged the projects $1,533,000 for overhead items allocated in proportion to the amount invested in projects managed. In addition, RPM charged the projects $6,447,000 for all of the direct operating and non-operating expenses incurred during 2006.

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 $38,000 for the year ended December 31, 2006. 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 and funds that it manages. As part of the agreement, the Trust agreed to limitations on its ability to incur indebtedness, liens and to provide guarantees.

Related Persons Transactions

The Trust relies upon the Managing Shareholder to review and approve all transactions with related persons required to be reported under the rules of the SEC (“related person transactions”). Prior to approving a related person transaction, the Managing Shareholder considers the relevant facts and circumstances, including, to the extent applicable, the relationships between all parties that would qualify as “related persons” under the rules of the SEC and such person’s or entity’s relationship to the Trust, such person’s or entity’s interest in the transaction, and the material facts and terms of the transaction. The Managing Shareholder approves those transactions that it determines are entered into in good faith and on fair and reasonable terms for, and in the best interests of, the Trust. The Trust does not maintain a written policy in connection with this process. Instead, the Managing Shareholder’s determinations regarding which related person transactions to enter into on behalf of the Trust are evidenced in the business records of the Trust and the Managing Shareholder.

21

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, 2006 and 2005 (in thousands).

	2006		2005
Audit Fees*	$	317	$	173
Audit-Related Fees		-		-
Tax Fees		53		-
All Other Fees		-		-
Total	$	370	$	173
* The fees for 2005 were borne by the Managing Shareholder.

Audit Committee Pre-Approval Policy

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

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)           Financial Statements

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

(b)           Exhibits

Exhibits required by Section 601 of Regulation S-K:

Exhibit No.		Description
3	(i)(A)	Certificate of Trust of the Registrant (incorporated by reference to the Registrant’s Registration Statement filed with the SEC on or about January 24, 1995).
3	(i)(B)	Certificate of Amendment to the Certificate of Trust of the Registrant filed with Delaware Secretary of State on December 18, 2003 (incorporated by reference to the Registrant’s Annual Report on Form 10-K filed with the SEC on October 30, 2007).
3	(ii)(A)	Declaration of Trust of the Registrant (incorporated by reference to the Registrant’s Registration Statement filed with the SEC on or about January 24, 1995).
3	(ii)(B)	Amendment No. 1 to Amended and Restated Declaration of Trust of the Registrant (incorporated by reference to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1996; SEC File No. 000-25430).
3	(ii)(C)	Amendment No. 2 to the Amended and Restated Declaration of Trust (incorporated by reference to the Registrant’s Proxy Statement filed with the SEC on November 5, 2001; SEC File No. 000-25430).

22

Exhibit No.			Description
3	(ii)(D)		Amendment to the Amended Declaration of Trust of the Registrant effective January 1, 2005 (incorporated by reference to the Registrant’s Annual Report on Form 10-K filed with the SEC on October 30, 2007).
10.1		#	Management Agreement between the Trust and Managing Shareholder, dated January 3, 1995 (incorporated by reference to the Registrant’s Annual Report on Form 10-K or the year ended December 31, 1996; SEC File No. 000-25430).
10.2		*	Power Purchase Agreement between New England Power Company and Ridgewood Providence Power Partners, as successor in interest, dated November 1987 (as amended).
14			Code of Ethics, adopted on March 1, 2004 (incorporated by reference to Exhibit 14 of the Annual Report on Form 10-K filed by The Ridgewood Power Growth Fund with the SEC on March 1, 2006).
21		*	Subsidiaries of the Registrant.
31.1		*	Certification of Randall D. Holmes, Chief Executive Officer of the Registrant, pursuant to Securities Exchange Act Rule 13a-14(a).
31.2		*	Certification of Jeffrey H. Strasberg, Chief Financial Officer of the Registrant, pursuant to Securities Exchange Act Rule 13a-14(a).
32		*	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, signed by Randall D. Holmes, Chief Executive Officer of the Registrant, and Jeffrey H. Strasberg, Chief Financial Officer of the Registrant.
99.1		*	Financial statements of Indeck Maine Energy, LLC.
99.2		*	Financial statements of Ridgewood Maine Hydro Partners, LP.

____________________

* 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.

23

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 IV
Date:  December 14, 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 14, 2007
Randall D. Holmes	(Principal Executive Officer)
/s/ Jeffrey H. Strasberg	Executive Vice President and Chief Financial Officer	December 14, 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 14, 2007
Randall D. Holmes

24

RIDGEWOOD ELECTRIC POWER TRUST IV

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets at December 31, 2006 and 2005	F-3
Consolidated Statements of Operations for the three years ended December 31, 2006	F-4
Consolidated Statements of Changes in Shareholders’ Equity (Deficit) for the three years ended December 31, 2006	F-5
Consolidated Statements of Cash Flows for the three years ended December 31, 2006	F-6
Notes to Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Managing Shareholder and Shareholders

Ridgewood Electric Power Trust IV

We have audited the accompanying consolidated balance sheets of Ridgewood Electric Power Trust IV (a Delaware trust) and subsidiaries as of December 31, 2006 and 2005, 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, 2006. 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 audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ridgewood Electric Power Trust IV as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Edison, New Jersey

December 14, 2007

F-2

RIDGEWOOD ELECTRIC POWER TRUST IV
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
	December 31,
	2006			2005
ASSETS
Current assets:
Cash	$	819		$	639
Accounts receivable		2,252			2,045
Notes receivable, affiliates – current portion		-			207
Due from affiliates		59			95
Prepaid expenses and other current assets		80			102
Total current assets		3,210			3,088
Notes receivable, affiliates – noncurrent portion		4,859			4,926
Investments		4,776			4,174
Plant and equipment, net		8,561			9,351
Intangibles, net		1,857			2,460
Other assets		405			405
Total assets	$	23,668		$	24,404
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	432		$	582
Accrued royalty expense		451			409
Due to affiliates		285			943
Total current liabilities		1,168			1,934
Minority interest		4,566			4,632
Total  liabilities		5,734			6,566
Commitments and contingencies
Shareholders’ equity (deficit):
Shareholders’ equity (476.8875 Investor Shares           issued and outstanding)		18,024			17,928
Managing Shareholder’s accumulated deficit          (1 management share issued and outstanding)		(90	)		(90	)
Total shareholders’ equity		17,934			17,838
Total liabilities and shareholders’ equity	$	23,668		$	24,404

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

F-3

RIDGEWOOD ELECTRIC POWER TRUST IV
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
	Years Ended December 31,
	2006			2005			2004
Power generation revenue	$	7,503		$	7,676		$	7,979
Renewable attribute revenue		3,957			4,014			4,177
Sublease revenue		577			571			571
Total revenues		12,037			12,261			12,727
Cost of revenues		9,199			9,379			9,483
Gross profit		2,838			2,882			3,244
Operating expenses:
General and administrative expenses		163			316			174
Management fee to the Managing Shareholder		535			447			476
Total operating expenses		698			763			650
Income from operations		2,140			2,119			2,594
Other income (expense):
Interest income		435			354			172
Interest expense		(74	)		(67	)		(67	)
Equity in income of Maine Hydro		1,027			616			529
Equity in income (loss) of Indeck Maine		624			2,215			(1,630	)
Total other income (expense), net		2,012			3,118			(996	)
Income before minority interest		4,152			5,237			1,598
Minority interest in the earnings of subsidiaries		(1,005	)		(1,021	)		(1,150	)
Net income	$	3,147		$	4,216		$	448
Managing Shareholder – Net income	$	31		$	42		$	125
Shareholders – Net income		3,116			4,174			323
Net income per Investor Share		6,533			8,752			677

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

F-4

RIDGEWOOD ELECTRIC POWER TRUST IV
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 2004, 2005 AND 2006
(in thousands)
	Shareholders' Equity			Managing Shareholder Deficit			Total Shareholders' Equity
Balance at January 1, 2004	$	16,083		$	(230	)	$	15,853
Net income		323			125			448
Cash distributions		(1,452	)		(14	)		(1,466	)
Capital contribution		52			-			52
Balance at December 31, 2004		15,006			(119	)		14,887
Net income		4,174			42			4,216
Cash distributions		(1,307	)		(13	)		(1,320	)
Capital contribution		55			-			55
Balance at December 31, 2005		17,928			(90	)		17,838
Net income		3,116			31			3,147
Cash distributions		(3,734	)		(38	)		(3,772	)
Capital contribution		714			7			721
Balance at December 31, 2006	$	18,024		$	(90	)	$	17,934

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

F-5

RIDGEWOOD ELECTRIC POWER TRUST IV
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
	Years Ended December 31,
	2006			2005			2004
Cash flows from operating activities:
Net Income	$	3,147		$	4,216		$	448
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization		1,399			1,389			1,407
Change in rotable spare parts		(6	)		97			28
Forgiveness of unpaid and accrued interest on management fees		721			55			52
Interest income on notes receivable		(404	)		(339	)		(172	)
Minority interest in the earnings of subsidiaries		1,005			1,021			1,150
Equity interest in (income) loss of:
Maine Hydro		(1,027	)		(616	)		(529	)
Indeck Maine Hydro		(624	)		(2,215	)		1,630
Cash distributions from Maine Hydro		1,050			842			877
Changes in operating assets and liabilities
Accounts receivable		(207	)		(630	)		(443	)
Prepaid expenses and other current assets		22			13			(38	)
Accounts payable		(150	)		331			7
Accrued royalty expense		41			52			135
Due to/from affiliates, net		(622	)		(219	)		(111	)
Other assets		-			(105	)		(300	)
Total adjustments		1,198			(324	)		3,693
Net cash provided by operating activities		4,345			3,892			4,141
Cash flows from investing activities:
Repayment of notes receivable, affiliates		207			-			-
Loans to Indeck Maine		-			(1,000	)		(1,000	)
Loans to Ridgewood Power B Fund/ Providence Expansion		-			(207	)		-
Interest received on Indeck Maine loan		471			-			-
Captial expenditures		-			-			(35	)
Net cash provided by (used in) investing activities		678			(1,207	)		(1,035	)
Cash flows from financing activities:
Cash distributions to minority interest		(1,071	)		(1,458	)		(1,569	)
Cash distributions to shareholders		(3,772	)		(1,320	)		(1,466	)
Repayments of term loan		-			-			(867	)
Change in restricted cash		-			-			757
Net cash used in financing activities		(4,843	)		(2,778	)		(3,145	)
Net increase (decrease) in cash		180			(93	)		(39	)
Cash, beginning of year		639			732			771
Cash, end of year	$	819		$	639		$	732
Supplemental disclosure of cash flow information:
Interest paid	$	-		$	-		$	14

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

F-6

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

1.        DESCRIPTION OF BUSINESS

Ridgewood Electric Power Trust IV (the “Trust”) is a Delaware trust formed in September 1994. The Trust began offering shares on February 6, 1995 and concluded its offering on September 30, 1996. 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 independent power generation facilities, water desalinization plants and other infrastructure projects in the US. The projects owned by the Trust have characteristics that qualify the projects for government incentives. Among the incentives are ancillary revenue opportunities related to the fuel used by the power plants.

The Trust’s accompanying consolidated financial statements include its wholly-owned subsidiaries and the financial statements of Ridgewood Providence Power Partners, L.P. (“Ridgewood Providence”). The Trust’s consolidated financial statements also include the Trust’s 50% interest in Ridgewood Maine Hydro Partners, L.P. (“Maine Hydro”) and its 25% interest in Ridgewood Indeck Maine Energy, LLC (“Indeck Maine”) which are accounted for under the equity method of accounting as the Trust has the ability to exercise significant influence but does not control the operating and financial policies of these entities.

The revenues generated from Ridgewood Pump Services IV Partners, L.P. ("Pump Services"), a wholly-owned subsidiary of Trust IV, were not material to the Trust’s operating results for the periods presented, and in January 2006, the engines were sold for $1 to the local operator.  The Trust did not record any gain or loss on the sale as the assets of Pump Services were fully impaired in 2003.

The Trust owns 64.3% interest in Ridgewood Providence and the remaining 35.7% minority interest is owned by Ridgewood Electric Power Trust III (“Trust III”). The interest of Trust III is presented as minority interest in the consolidated balance sheets and statements of operations. Ridgewood Providence and the Trust, along with Trust III and RRIG, are evaluating expanding the generation facilities at the site. If such expansion were to occur, the Trust may make an additional investment in Ridgewood Providence.

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

2.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

a) Principles of Consolidation

The consolidated financial statements include the accounts of the Trust and its majority-owned subsidiaries. Minority interests of majority-owned subsidiaries are calculated based upon the respective minority interest ownership percentages. All material intercompany transactions have been eliminated in consolidation.

The Trust uses the equity method of accounting for its investments in affiliates which are 50% or less owned as the Trust has the ability to exercise significant influence over the operating and financial policies of the affiliates but does not control the affiliate. The Trust’s share of the earnings or losses of the affiliates is included in the consolidated financial statements.

F-7

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

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

Renewable attribute revenue is derived from the sale of the renewable portfolio standard attributes (“RPS Attributes”). As discussed in Note 8, qualified renewable electric generation facilities produce RPS Attributes when they generate electricity. Renewable attribute revenue is recorded in the month in which the RPS Attributes are produced as Ridgewood Providence has substantially completed its obligations for entitled benefits, represented by the underlying generation of power within specific environmental requirements.

Sublease revenue is recorded monthly in accordance with the terms of the sublease agreement.

d) Cash

Cash balances with banks as of December 31, 2006 and 2005 exceeded insured limits by $619 and $507, respectively.

e) Accounts Receivable

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

f) Plant and Equipment

Plant and equipment, consisting principally of a power generating facility, 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 the related accumulated depreciation are removed from the balance sheets. The difference, if any, between the net asset value and any proceeds from such retirement or disposal is recorded as a gain or loss in the statement of operations.

The Trust uses the straight-line method of depreciation over the estimated useful life of the assets:

Power generation facility	20 years
Equipment	5-20 years
Vehicles	5 years

Rotable spare parts inventory primarily consists of parts and materials that are infrequently used in the Trust’s operation.  An allowance is established for obsolescence on the basis of management’s review and assessment.

F-8

Ridgewood Electric Power Trust IV

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) Fair Value of Financial Instruments

At December 31, 2006 and 2005, the carrying value of the Trust’s cash, accounts receivable, accounts payable and accrued expenses approximates their fair value.

i) Comprehensive Income

The Trust's comprehensive income consists only of net income.

j) Significant Customers

During 2006, 2005 and 2004, the Trust’s two largest customers accounted for 80.7%, 79.5% and 77.9%, respectively, of total revenues. During 2006, 2005 and 2004, the Trust purchased 100% of its gas from one supplier.

k) Income Taxes

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

l) Recent Accounting Pronouncements

FIN 48

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”) an interpretation of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 will be effective for the Trust beginning January 1, 2007. The Trust does not believe that the adoption of FIN 48 will have a material impact on its consolidated financial statements.

SFAS 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements ("SFAS 157"), to define fair value, establish a framework for measuring fair value in accordance with generally accepted accounting principles (GAAP) and expand disclosures about fair value measurements. SFAS 157 requires quantitative disclosures using a tabular format in all periods (interim and annual) and qualitative disclosures about the valuation techniques used to measure fair value in all annual periods. SFAS 157 will be effective for the Trust beginning January 1, 2008. The Trust is currently evaluating the impact of adopting SFAS 157.

F-9

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

SAB 108

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements ("SAB 108"). SAB 108 requires analysis of misstatements using both an income statement (rollover) approach and a balance sheet (iron curtain) approach in assessing materiality and provides for a one-time cumulative effect transition adjustment. SAB 108 is effective for fiscal years ending on or after November 15, 2006. The adoption of this standard did not have a material impact on the Trust's consolidated financial statements.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS 159 will be effective for the Trust on January 1, 2008. The Trust is currently evaluating the impact of adopting SFAS 159 on its consolidated financial statements.

3.         NOTES RECEIVABLE, AFFILIATES

In September 2005, the Trust loaned $207 to Ridgewood Power B Fund/Providence Expansion (“B Fund”), an affiliate of the Trust.  The note receivable was paid off by the B Fund during the first quarter of 2006.

At December 31, 2006, the Trust loan balance to Indeck Maine was $4,075. During 2005 and 2004, the Trust loaned $1,000 each year to Indeck Maine which bears interest at 18% and 12% per annum, respectively. The interest income accrued on the notes receivable for the years ended December 31, 2006, 2005 and 2004 was $404, $339 and $171, respectively, which is included in notes receivable affiliates in the consolidated balance sheets. Ridgewood Electric Power Trust V (“Trust V”) made identical loans to Indeck Maine.

The notes and the related accrued interest, which are payable on demand are subordinate to the $6 million mortgage loan agreement with Commerce Bank/North (“Commerce”) entered into by Indeck Maine on August 6, 2004. As a part of the subordination agreement, the Trust and Trust V (collectively  the “Ridgewood Indeck Investors”) have agreed that prior to the payment in full of the Commerce loan and termination of all obligations of Commerce, the Ridgewood Indeck Investors shall not, without prior written consent of Commerce, accelerate the maturity of all or any portion of the subordinated debt and related interest, or take any action towards collection of all or any portion of the subordinated debt or enforcement of any rights, powers or remedies under the subordinated debt documents.

On August 28, 2006, Indeck Maine and Commerce amended the mortgage loan note and subordination agreement, whereby, Indeck Maine was permitted to make payments of up to $2,500 to Ridgewood Indeck Investors and Indeck Energy Services LLC, an unaffiliated entity in 2006 towards outstanding obligations.  On December 18, 2006, Trust received $471of interest on the subordinated notes.

4.         PLANT AND EQUIPMENT

At December 31, 2006 and 2005, plant and equipment at cost and accumulated depreciation were:

	2006		2005
Power generation facility	$	15,914	$	16,924
Rotable spare parts		705		699
Equipment		24		24
Vehicles		33		33

		16,676			17,680
Less: accumulated depreciation		(8,115	)		(8,329	)
	$	8,561		$	9,351

F-10

 

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

For the years ended December 31, 2006, 2005 and 2004, depreciation expense was $796, $786 and $804, respectively, which is included in cost of revenues.

5.         INTANGIBLE ASSETS

Ridgewood Providence is committed to sell all of the electricity it produces to New England Power (“NEP”) for prices as specified in the power purchase agreement. The agreement with NEP expires in the year 2020 and can be terminated by NEP under certain conditions in 2010. As defined, the prices are adjusted annually for changes in the consumer price index through 2010, and become market prices thereafter.

A portion of the purchase price of Ridgewood Providence was assigned to the electricity sales contracts and is being amortized through its early termination date of 2010 (a period of approximately 14 years) on a straight-line basis. At December 31, 2006 and 2005, the gross and net carrying amounts of the electric sales contracts were:

	2006			2005
Electricity sales contracts - gross	$	8,338		$	8,338
Less: accumulated amortization		(6,481	)		(5,878	)
Intangibles, net	$	1,857		$	2,460

For each of the years ended December 31, 2006, 2005 and 2004, amortization expense was $603, which is included in cost of revenues. The Trust expects to record amortization expense during the next four years as follows:

Year ended December 31,
2007	$	603
2008		603
2009		603
2010		48
Total	$	1,857

6.         INVESTMENTS

The Trust’s investments include a 50% interest in Maine Hydro and a 25% interest in Indeck Maine.

Maine Hydro

On August 15, 1996, Maine Hydro was formed as a Delaware limited partnership. Ridgewood Maine Hydro Corporation, a Delaware corporation (“RMHCorp”), is the sole general partner of Maine Hydro and is owned equally by the Trust and Trust V, both Delaware trusts (collectively, the “Trusts”). The Trusts are equal limited partners in Maine Hydro and have RRP as a common Managing Shareholder. Maine Hydro operations shall continue to exist until December 31, 2046 unless terminated sooner by certain provisions of the partnership agreement.

On December 23, 1996, in a merger transaction, Maine Hydro acquired 14 hydroelectric projects located in Maine from CHI Energy, Inc. Maine Hydro has electrical generating capacity of 11.3 megawatts (“MW”) and its projects are operated under contract by Ridgewood Power Management LLC (“RPM”), an affiliate of the Managing Shareholder. The electricity generated is sold under long-term electricity sales agreements.

F-11

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Summarized balance sheet data for Maine Hydro at December 31, 2006 and 2005 is as follows:

	2006		2005
Current assets	$	1,448	$	1,764
Non-current assets		4,739		4,182
Total assets	$	6,187	$	5,946
Current liabilities	$	900	$	606
Non-current liabilities		5		12
Partners’ equity		5,282		5,328
Total liabilities and partners' equity	$	6,187	$	5,946
Trust share of Maine Hydro equity	$	2,641	$	2,664

Summarized statements of operations data for Maine Hydro for the years ended December 31, 2006, 2005 and 2004 is as follows:

	2006		2005		2004
Revenues	$	5,221	$	4,806	$	3,429
Cost of revenues		2,991		3,060		2,813
Other expenses (income), net		176		514		(443	)
Total expenses		3,167		3,574		2,370
Net income	$	2,054	$	1,232	$	1,059
Trust share of income in Maine Hydro	$	1,027	$	616	$	529

Indeck Maine

On June 11, 1997, Ridgewood Indeck Investors equally purchased 50% of the membership interest in Indeck Maine, an Illinois limited liability company, which owns two electric power generating stations fueled by clean wood biomass at West Enfield, Maine and Jonesboro, Maine. Indeck Energy Services, Inc. ("Indeck"), an entity unaffiliated with the Trust, owns the remaining 50% membership interest in Indeck Maine and was the seller in the June, 1997 transaction. Ridgewood Indeck investors have a preferred membership interest entitling them to receive all net cash flow from operations each year until they receive an 18% annual cumulative return on their capital contributions to Indeck Maine.

From January 1998 through June 2005, the Ridgewood Indeck Investors loaned approximately $8.2 million in total to Indeck Maine, in proportion to their ownership interests.

Each of the Indeck Maine projects has a capacity of 24.5MW and each uses a steam turbine to generate electricity. Indeck Maine and several of its affiliates have an agreement with a power marketer for which they are committed to sell renewable portfolio standard attributes (“RPS Attributes”) derived from their electric generation. The agreement provides such power marketer with six separate annual options to purchase such attributes from 2004 through 2009 at fixed prices, as defined. If Indeck Maine and its affiliates fail to supply the required number of attributes, penalties may be imposed. In accordance with the terms of the agreement, if the power marketer elects to exercise an annual option and Indeck Maine and its affiliates produce no attributes for such option year, Indeck Maine and its affiliates face a maximum penalty, which is adjusted annually for the change in the consumer price index, among other things, of approximately $3,300, measured using current factors, for that option year and any other year in which an option has been exercised and no attributes have been produced. Pursuant to the agreement, Indeck Maine is liable for 70% of the total penalty, but may be liable up to 100% in the event of a default of its affiliates.

F-12

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Summarized balance sheet data for Indeck Maine at December 31, 2006 and 2005 is as follows:

	2006			2005
Current assets	$	8,817		$	10,983
Non-current assets		11,468			9,329
Total assets	$	20,285		$	20,312
Current liabilities	$	3,715		$	4,053
Notes payable to members		16,301			16,301
Loan payable – long-term portion		788			2,036
Interest payable to members		3,135			3,403
Members’ deficit		(3,654	)		(5,481	)
Total liabilities and members' deficit	$	20,285		$	20,312
Trust share of Indeck Maine equity	$	2,134		$	1,510

Summarized statements of operations data for Indeck Maine for the years ended December 31, 2006, 2005 and 2004 is as follows:

	2006		2005		2004
Revenues	$	33,539	$	33,819	$	14,784
Cost of revenues		29,921		26,870		16,542
Other expenses		1,791		2,007		1,196
Total expenses		31,712		28,877		17,738
Net income (loss)	$	1,827	$	4,942	$	(2,954	)
Trust share of income (loss) in Indeck Maine	$	624	$	2,215	$	(1,630	)

7.         LANDFILL LEASE AND SUBLEASE

Ridgewood Providence leases its site on the Central Landfill, located in Johnston, Rhode Island from Rhode Island Resource Recovery Corporation (“RIRRC”) under a lease which expires in 2020 and can be extended for an additional 10 years by mutual agreement of the parties under certain conditions. The lease requires Ridgewood Providence to pay a contingent rent in the form of a royalty equal to 15% of net revenue, as defined, until 2006. For subsequent years, the royalty is 15% of net revenues for each month in which the average daily kilowatt hour production is less than 180,000, and 18% of net revenues for each month in which the average daily kilowatt hour production exceeds 180,000. For the years ended December 31, 2006, 2005 and 2004, royalty expense relating to the RIRRC lease amounted to $1,320, $1,090 and $1,102, respectively. The royalty expense has been included in the cost of revenues in the statements of operations.

Ridgewood Providence subleases a portion of the Central Landfill to the Central Gas Limited Partnership (“Gasco”), an unaffiliated entity. Gasco operates and maintains a portion of the landfill gas collection system and supplies landfill gas to Ridgewood Providence. The sublease agreement is effective through December 31, 2010 and provides for the following:

F-13

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

a) Sublease Revenue - Effective January 1, 2001, Gasco is to pay Ridgewood Providence an annual amount equal to the product of $45 (adjusted annually for inflation from January 1, 2001) times the assumed output capacity of each original engine generator set in megawatts installed and operated by the joint venture. The Trust recognized sublease revenue of $577, $571 and $571 for the years ended December 31, 2006, 2005 and 2004 respectively.

b) Fuel Expense - Ridgewood Providence is to purchase all the landfill gas produced by Gasco and pay Gasco on a monthly basis approximately $.05 to $.005 per kilowatt hour based on the kilowatt hours generated. The price is adjusted annually for changes in the Consumer Price Index, as defined. Purchases from Gasco for the years ended December 31, 2006, 2005 and 2004 amounted to $1,031, $1,008 and $1,020, respectively. Fuel expenses have been included in the cost of revenues in the statements of operations.

8.         RENEWABLE ATTRIBUTE REVENUE

In 1997, Massachusetts enacted the Electric Restructuring Act of 1997 (the “Restructuring Act”). Among other things, the Restructuring Act requires that all retail electricity suppliers in Massachusetts (i.e., those entities supplying electric energy to retail end-use customers in Massachusetts) purchase a minimum percentage of their electricity supplies from qualified new renewable generation units powered by one of several renewable fuels, such as solar, biomass or landfill gas. Beginning in 2003, each such retail supplier must obtain at least one (1%) percent of its supply from qualified new renewable generation units. Each year thereafter, the requirement increases one-half of one percentage point until 2009, when the requirement equals four (4%) percent of each retail supplier’s sales in that year. Subsequent to 2009, the increase in the percentage requirement will be determined and set by the Massachusetts Division of Energy Resources (“DOER”).

On January 17, 2003, Ridgewood Providence received a “Statement of Qualification” from the DOER pursuant to the renewable portfolio standards (“RPS”) adopted by Massachusetts. Since Ridgewood Providence has now become qualified, it is able to sell to retail electric suppliers the RPS Attributes associated with its electrical energy. Retail electric suppliers need to purchase RPS Attributes associated with renewable energy and not necessarily the energy itself. Thus, electrical energy and RPS Attributes are separable products and need not be sold or purchased as a bundled product. Retail electric suppliers in Massachusetts will then use the purchase of such RPS Attributes to demonstrate compliance with the Restructuring Act and RPS regulations.

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

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

9.         ROYALTY EXPENSE

On August 1, 2003, Ridgewood Providence entered into an Environmental Attribute Agreement with RIRRC and Ridgewood Gas Services, LLC (“RGS”), an affiliate of Ridgewood Providence that provides management services to RIRRC. Pursuant to the terms of the agreement, Ridgewood Providence is required to pay 15% net revenue royalty to both RIRRC and RGS from revenues derived from the sale of RPS Attributes which are the only direct costs of the renewable attribute revenue. The term of the agreement coincides with the Central Landfill lease agreement, which expires in 2020 and provides for an extension of an additional ten years. During the years ended December 31, 2006, 2005 and 2004, the Trust recognized royalty expense of $1,187, $1,181 and $1,245, respectively, related to this agreement which is included in cost of revenues in the accompanying statements of operations. The royalty expenses recognized above include 50% of royalty expenses to RGS for each of the years ended December 31, 2006, 2005 and 2004.

F-14

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

10.      COMMITMENTS AND CONTINGENCIES

Ridgewood Providence and several of its affiliates have an agreement with a power marketer for which they are committed to sell a portion of their RPS Attributes derived from their electric generation. The agreement provides such power marketer with six separate annual options to purchase such RPS Attributes from 2004 through 2009 at fixed prices, as defined. If Ridgewood Providence and its affiliates fail to supply the required number of RPS Attributes, penalties may be imposed. In accordance with the terms of the agreement, if the power marketer elects to exercise an annual option and Ridgewood Providence and its affiliates produce no renewable attributes for such option year, Ridgewood Providence and its affiliates face a maximum penalty, which is adjusted annually for the change in the consumer price index, among other things, of approximately $3,300, measured using current factors, for that option year and any other year in which an option has been exercised and no renewable attributes have been produced. Pursuant to the agreement, Ridgewood Providence and Indeck Maine are liable for 8% and 70% of the total penalty, respectively, but may be liable up to 100% in the event of the default of its affiliates. In the fourth quarters of 2007 and 2006, the power marketer notified Ridgewood Providence and its affiliates that it has elected to purchase the output for 2008 and 2007, respectively, as specified in the agreement. In 2004, Ridgewood Providence incurred a penalty of approximately $4 for the shortfall in production of RPS Attributes. In 2006 and 2005, Ridgewood Providence satisfied and delivered RPS Attributes as prescribed in the agreements and therefore no penalties were incurred.

As part of the RPS Attribute agreements, Ridgewood Providence has assigned and pledged its receivables derived from a portion of its renewable attribute revenue to the power marketer as well as deposited $300 with the power marketer during 2004. In addition to the current security deposit, Ridgewood Providence deposited an additional $105 with the power marketer in 2005. The affiliates of Ridgewood Providence that are parties to the agreement have also deposited amounts with the power marketer in proportion to their obligations under the agreement.

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.

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.

11.       TRANSACTIONS WITH MANAGING SHAREHOLDER AND AFFILIATES

The Trust operates pursuant to the terms of a management agreement (“Management Agreement”). Under the terms of the 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 3% of the Trusts’ prior year net asset value which equals $535, $447 and $476 for the years ended December 31, 2006, 2005 and 2004, 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.

For the years ended December 31, 2006, 2005 and 2004, the Trust accrued interest expense of $62, $55 and $52, respectively, on accrued but unpaid management fees. The interest accrued has been waived by the Managing Shareholder and recorded as capital contribution in the period waived.

The shareholders of the Trust other than the Managing Shareholder were allocated 99% of each contribution and the Managing Shareholder was allocated 1% so that the amount of the contribution allocated offset the amount of the expense initially accrued. For the years ended December 31, 2006 2005 and 2004, the Trust made management fee payments to the Managing Shareholder of $257, $481 and $429, respectively.  In the fourth quarter of 2006, the Managing Shareholder forgave $278 of 2006 unpaid accrued management fees and $381 of prior years unpaid accrued management fees which were recorded as deemed capital contributions.

F-15

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

Under the Management Agreement with the Managing Shareholder, 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 Trust. 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, 2006, 2005 and 2004, RPM charged the projects approximately $1,533, $1,358 and $1,169, respectively, for overhead items allocated in proportion to the amount invested in projects managed. In addition, for the years ended December 31, 2006, 2005, and 2004 RPM charged the projects approximately $6,447, $6,970 and $7,097, respectively, for all of the direct operating and non-operating expenses incurred. These charges may not be indicative of costs incurred if the Trust were not operated by RPM.

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 $38, $13 and $14 for each of the three years ended December 31, 2006, 2005 and 2004, 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.

RRP owns 2.0331 Investor Shares of the Trust. The Trust granted the Managing Shareholder a single Management Share representing the Managing Shareholder’s management rights and rights to distributions of cash flow.

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 Funds that it manages. As part of the agreement, the Trust agreed to limitations on its ability to incur indebtedness and liens, and to provide guarantees. The Managing Shareholder and Wachovia Bank agreed to extend the Managing Shareholder’s line of credit through May 31, 2008.

The Trust records short-term payables to and receivables from other affiliates in the ordinary course of business. The amounts payable to and receivable from the other affiliates do not bear interest. At December 31, 2006 and 2005, the Trust had outstanding payables and receivables as follows:

	December 31,				December 31,
	2006		2005		2006		2005
	Due from				Due to
RPM	$	-	$	-	$	211	$	204
RRP		-		-		-		384
Trust III		19		-		-		355
Maine Hydro		21		60		-		-
Indeck Maine		-		20		74		-
Other affiliates		19		15		-		-
Total	$	59	$	95	$	285	$	943

F-16

Ridgewood Electric Power Trust IV

Notes to Consolidated Financial Statements

(dollar amounts in thousands, except per share data)

12.         SELECTED UNAUDITED QUARTERLY FINANCIAL DATA

	2006 Quarters
	1st		2nd		3rd		4th
Revenues	$	3,012	$	2,986	$	2,923	$	3,116
Gross profit		848		649		768		573
Income from operations		647		470		605		418
Net income		948		393		891		915
Net income per Investor Share		1,968		816		1,850		1,899
	2005 Quarters
	1st		2nd		3rd		4th
Revenues	$	3,117	$	2,960	$	2,996	$	3,188
Gross profit		915		620		834		513
Income from operations		736		415		654		314
Net income		103		857		1,715		1,541
Net income per Investor Share		214		1,779		3,560		3,199

F-17

EX-10.2

Exhibit 10.2

AGREEMENT dated as of November 6, 1987 by and between Northeast Landfill Power Co., a Massachusetts corporation (“Seller”), and New England Power Company, (“NEP”), a Massachusetts corporation.

ARTICLE I.       BASIC UNDERSTANDINGS

Seller intends to construct, operate and maintain three landfill gas-fired electric generation projects at landfills located in Worcester, MA, and Johnston, Rhode Island (RI) (collectively, the “Facilities” and singularly the “Facility”).  The total projected capacity of the Facilities is approximately twelve thousand kilowatts (12,000 KW).

Subject to the following terms and conditions, Seller agrees to sell and deliver, and NEP agrees to purchase and receive, the entire NEP Entitlement, as defined below, in each of the Facilities.

ARTICLE II.      DEFINITIONS

Whenever used in this Agreement, the following terms shall have the following meanings:

“Affiliate of NEP” shall mean any company that is a subsidiary of the New England Electric System.

“Commencement Date of Operation” shall mean 12:01 a.m. on the first day of the month following the date Seller designates, in writing, as the initial date of commercial operation of the Facilities, which shall not precede the latter to occur of (i) completion of successful acceptance testing of the Johnston Facility for purposes of financing and project operation or (ii) the initial date on which Seller generates at least five megawatts (5 MW) of electricity at the Johnston Facility continuously for a period of eight (8) consecutive hours.

“Good Utility Practice(s)” shall mean the practices, methods and acts (including but not limited to the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry) that, at a particular time, in the exercise of reasonable judgment in light of the facts known or that should have been known at the time a decision was made, would have been expected to accomplish the desired result in a manner consistent with law, regulation, reliability, safety, environmental protection, economy and expedition. With respect to each of the Facilities, Good Utility Practice(s) include but are not limited to taking reasonable steps to ensure that:

(l) adequate materials, resources and supplies, including landfill gas, are available to meet the Facility’s needs;

(2) sufficient operating personnel are available and are adequately experienced and trained and licensed as necessary to operate the Facility properly and efficiently and are capable of responding to emergency conditions relating to the operation of the Facility whether caused by events on or off the site of the Facility;

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(3) preventative, routine and non-routine maintenance and repairs are performed on a basis that ensures reliable long-term and safe operation of the Facility, and are performed by knowledgeable, trained and experienced personnel utilizing proper equipment and tools;

(4) appropriate monitoring and testing is done to ensure equipment at the Facility is functioning as designed and to provide assurance that equipment will function properly under both normal and emergency conditions; and

(5) equipment is not operated at the Facility in a reckless manner, or in a manner unsafe to workers, the general public or the environment or without regard to defined limitations such as rate of refuse decomposition and gas production, air intrusion, safety inspection requirements, operating voltage, current, frequency, rotational speed, polarity, synchronization, and control system limits.

“NEP Entitlement” shall mean one hundred percent (100%) of the Net Capability and Net Electric Output of each of the Facilities unless Seller exercises its option to contract with another utility for the sale of a percentage of the Net Capability and the Net Electric Output of the Facilities under Article IV, below. If Seller exercises such option “NEP Entitlement” shall mean the percentage of the Facilities’ Net Capability and Net Electric Output not contracted for sale to another utility.

“NEP’s System” shall mean the electrical system of NEP and/or the electrical system of any Affiliate of NEP.

“NEPEX” shall mean the New England Power Exchange.

“NEPOOL” shall mean the New England Power Pool.

“NEPOOL Agreement” shall mean the New England Power Pool Agreement dated as of September 1, 1971, as amended.

“Net Capability” shall mean, with respect to each of the Facilities, the maximum dependable load-carrying ability of the Facility, exclusive of capacity required for the Facility’s use, expressed in kilowatts, as determined by tests conducted in accordance with the NEPOOL Agreement, including appropriate NEPOOL Criteria, Rules and Standards and Operating Procedures.

“Net Electric Output” shall mean, with respect to each of the Facilities, the total amount of electricity generated by the Facility less kilowatthours consumed for the Facility’s use.

“Off-Peak Periods” shall mean all hours not falling within On-Peak Periods.

“On-Peak Periods” shall mean all hours from 7:00 a.m. to 11:00 p.m. Monday through Friday, excluding legal holidays designated in writing by NEP. At Seller’s request, NEP shall provide to Seller a list of designated legal holidays prior to the beginning of each calendar year.

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“Prime Rate” shall mean the prime (or comparable) rate announced from time to time as its prime rate by the Bank of Boston, which rate may differ from the rate offered to its most substantial and creditworthy customers.

“Rate X” shall mean NEP’s short term avoided energy cost calculated by NEP in accordance with the methodology described in Appendix A, attached hereto and incorporated herein by reference, such calculation to be provided to Seller on a timely basis for review.

ARTICLE III.       TERM

It shall be a condition precedent to the effectiveness of this Agreement that (i) the requirements of 220 C.M.R. 8.01 et. seq., for the effectiveness of the Agreement have been fulfilled without a finding by the Massachusetts Department of Public Utilities (“DPU”) that this Agreement, or any one or more of its provisions is contrary to the public interest, or (ii) a court or governmental authority of requisite jurisdiction has determined that the DPU lacks jurisdiction over NEP’s purchase of the NEP Entitlement.

The term of this Agreement shall extend for a period ending thirty (30) years after the Commencement Date of Operation; provided, however, that this Agreement shall terminate on the twentieth (20th) anniversary of the Commencement Date of Operation if NEP gives Seller not less than one-hundred and eighty (180) days prior written notice of such termination unless Seller agrees prior to such twentieth (20th) anniversary to amend article VI B, below, to provide that the price to be paid by NEP subsequent to such twentieth (20th) anniversary for monthly quantities of electricity delivered hereunder shall be a price per kilowatthour equal to Rate X.

Notwithstanding the preceding paragraph, if (a) Seller has not secured exclusive rights, for a term at least equal to the term of this Agreement, to purchase the landfill gas produced at each of the currently permitted landfill sites on which the Facilities will be located within ninety (90) days of the effective date of this Agreement, (b) construction of the initial gas collection system for the Johnston Facility has not been substantially completed within one (1) year of the effective date of this Agreement, or (c) the Commencement Date of Operation has not occurred prior to December 31, 1989, NEP may thereafter terminate this Agreement by providing Seller thirty (30) days’ written notice within 60 days of (a), (b), or (c), above, as appropriate.

NEP shall have the option to purchase the Net Capability and the Net Electric Output of each or any of the Facilities following expiration or termination of this Agreement, other than for breach by NEP, upon substantially the same terms and purchase price as that offered by Seller to any third party, which option shall be held open for forty-five (45) days after Seller’s presentation of the terms of such offer to NEP.  NEP’s option to purchase such Net Capability and Net Electric Output of each or any of the Facilities shall survive expiration or termination of this Agreement and shall terminate only upon agreement by a third party to purchase such Net Capability and Net Electric Output upon substantially the same terms and purchase price most recently offered to NEP, but not accepted by NEP, within forty-five (45) days of Seller’s presentation of such offer to NEP. For purposes of this paragraph, a purchase price that is substantially the same as that offered to any third party shall equal the purchase price offered to any such third party reduced by all costs that would be incurred by Seller and/or such third party in connection with the transmission of the particular Facility’s Net Electric Output from the Facility to such third party.

3

ARTICLE IV.       OPTIONAL CONTRACT SALE

Seller shall have the option, exercisable on or before January 1, 1988, to contract with another utility for the sale of up to fifty percent (50%) of the Net Capability and the Net Electric Output of the Facilities for a term commencing with the Commencement Date of operation and extending for an uninterrupted period not to exceed twenty (20) years, provided that the percentage of the Net Capability and Net Electric Output so sold (the “Contract Percentage”) is fixed throughout such term (any such contract shall be hereinafter referred to as the “Optional Contract.”)

If Seller exercises such option, then NEP shall have the right, exercisable by written notice given to Seller not less than ninety (90) days prior to the expiration of the term of the Optional Contract, to elect to purchase the Contract Percentage from Seller under the terms and conditions of this Agreement from the Optional Contract’s expiration date through the expiration date of this Agreement but at a price per kilowatthour delivered equal to the average of (i) the price calculated in accordance with Article VI B (the “Contract Price”) and (ii) Rate X as determined from time to time.

If NEP does not so elect, then Seller shall have the right, exercisable by written notice given to NEP not less than sixty (60) days prior to the expiration of the term of the Optional Contract, to elect to sell the Contract Percentage to NEP (and if Seller so elects, NEP shall purchase and receive the Contract percentage) under the terms and conditions of this Agreement from the Optional Contract’s expiration date through the expiration date of this Agreement but at a price per kilowatthour delivered equal to the lesser of Rate X or the Contract Price, both as determined from time to time. If Seller does not so elect, Seller shall have the right to sell the Contract Percentage to another electric utility.

ARTICLE V.         TERMS OF SALE

Seller agrees that the Facilities shall be designed, constructed, operated and maintained such that they reasonably may be expected (i) to have a monthly average Net Electric Output not exceeding twelve thousand kilowatts (12,000 KW) per hour and (ii) to produce collectively a constant Net Electric Output for a period of not less than thirty (30) years. During the design and construction of the Facilities, Seller shall provide NEP with such information as NEP may request to determine whether the Facilities are being so designed and constructed.

Seller shall choose an architect/engineer firm (“AE Firm”) for the design, or for the review of the design if such design is provided by Sellers vendor(s), of each of the Facilities, which selection shall be subject to approval by NEP.  NEP hereby approves the selection of Hayden-Wegman as the AE Firm, and NEP shall not unreasonably withhold approval of any other AE Firm selected by seller. If NEP fails to approve or disapprove Seller AE Firm selection within thirty (30) days of a presentation by the proposed AE Firm to NEP of its design capabilities, NEP shall be deemed to have approved the selection for all purposes of this Agreement. NEP and Seller shall mutually choose a qualified independent engineering firm (“I.E. Firm”) to evaluate the design of each of the Facilities at Seller’s expense. The scope of the I.E. Firm’s design evaluation shall be subject to Seller’s review and NEP’s review and approval. The I.E. Firm’s design evaluation of each Facility shall be provided to NEP in writing prior to commencement of the construction of the Facility. Unless NEP and Seller agree otherwise in writing, Seller shall cause the AE Firm to make all changes in the Facility’s design that the I.E. Firm determines are necessary to meet the requirements of the preceding paragraph and Good Utility Practice. Seller shall cause each of the Facilities to be constructed in accordance with the resulting design. Seller shall insure that all equipment used in each of the Facilities shall be new and unused, good quality utility grade, suitable for the intended service and shall meet the requirements of applicable codes and standards.

4

Prior to the later to occur of the Commencement Date of Operation or January 1, 1989, Seller shall sell and deliver and NEP shall purchase and receive the NEP Entitlement in each of the Facilities when and if available at the price specified in ARTICLE VI A, below. Thereafter, Seller shall sell and deliver, and NEP shall purchase and receive, the NEP Entitlement in each of the Facilities at the price specified in ARTICLE VI B, below. NEP agrees to accept delivery of the NEP Entitlement in each of the Facilities. NEP shall not, however, be liable for any damages arising from its inability to accept delivery of any electricity that each or any of the Facilities are otherwise capable of generating if NEP uses all reasonable efforts to promptly restore such ability. Seller shall install and maintain in a safe manner, and in accordance with Good Utility Practice and applicable regulations, all of its equipment and facilities connected to NEP’s System. If at any time the operation of each or any of the Facilities endanger the safety of NEP’s personnel, or interferes with the safe and reliable operation of NEP’s System, NEP may discontinue purchases from Seller and disconnect from such Facility until such condition has been corrected. Unless an emergency exists, or the risk of one is imminent, NEP shall give Seller reasonable notice of its intention to disconnect from each or any of the Facilities and to discontinue purchases from Seller, and where practical, allow suitable time for Seller to remove the interfering condition. NEP shall reasonably cooperate with Seller in Seller’s efforts to remove such interfering condition. Any costs incurred by NEP in so cooperating shall be at Seller’s expense. NEP’s judgments with regard to discontinuance of purchases or disconnection of each or any of the Facilities under this paragraph shall be made in accordance with Good Utility Practice.

Seller shall cause, at Seller’s expense, the AE Firm, equipment vendor or such other party as may be chosen by Seller and approved by NEP which approval will not be unreasonably withheld, to prepare a plan and schedule for annual ongoing maintenance and spare parts inventory as well as a plan for less frequent major overhaul work on each of the Facilities’ generators, gas collection systems, and auxiliary equipment. Such plan shall be subject to NEP’s approval, which shall not be unreasonably withheld and shall conform to the recommendations of the equipment vendors and the AE Firm. Seller shall provide such plan to NEP prior to the Commencement Date of Operation. Subject to the following paragraph, Seller shall perform maintenance of each of the Facilities in accordance with such plan.

Seller shall cause, at Seller’s expense, an independent engineering firm (“I.E. O&M”) selected by Seller and approved by NEP (which approval shall not be unreasonably withheld) to conduct a review of each of the Facilities’ operation and maintenance practices after the second and before the third anniversary of the Commencement Date of Operation, and, unless the parties otherwise agree, every five years thereafter.  In addition, such a review shall be conducted at NEP’s written request in any year following a two calendar year period in which, for each of the two calendar years, the Net Electric Output of the Johnston Facility is less than ninety percent (90%) of the Johnston “KWHr Production (1000 KWH)” set forth in Appendix B, attached hereto and incorporated herein by reference. Seller shall cause the I. E. O&M to issue a written report describing the extent to which the maintenance plan and schedule described in the preceding paragraph is being followed, a description of and a statement of the reasons for any justified departure from such schedule or plan, a description of any deficiencies in the Facility’s operation and maintenance practices, and its recommendations, if any, for improving future operation and maintenance practices. Seller shall implement any recommendations made by the I.E. O&M that the I.E. O&M determines are necessary to meet Good Utility Practice unless Seller and NEP mutually agree otherwise. Seller shall keep and make available adequate maintenance logs for use by the I. E. O&M and/or NEP for the purpose of this review.

5

Seller agrees to operate the Facilities in parallel with NEP System and to deliver the NEP Entitlement in each of the Facilities to NEP at the delivery points and voltage levels specified in ARTICLE VIII, below. Unless otherwise requested by NEP, Seller shall operate each of the Facilities at a unity power factor or in an over excited condition at the point of delivery to NEP, subject to the response tine of control equipment to transient conditions on NEP System. If Seller fails to operate each or any of the Facilities at a unity power factor or in an over excited condition, NEP may install, at Seller’s expense, capacitors or other electric equipment necessary to ensure that such Facility can be so operated. NEP shall have the right on a short—term emergency basis to request that Seller operate each or any of the Facilities at any excitation level within the range of the particular Facility’s capability as determined from the equipment manufacturer’s recommendations. Seller agrees to use all reasonable efforts to comply with any such request from NEP.

At NEP’s sole option, NEP shall have the right to claim credit for (i) all or a portion of each or any emission to the air from each or any of the Facilities and the associated equivalent Btu heat input or (ii) the equivalent Btu heat input to each or any of the Facilities, that can be associated, per statutes, laws, regulations, ordinances, government standards and/or government regulations, with generation at the particular Facility. If NEP exercises such option, NEP shall reimburse Seller for all incremental expenses incurred by Seller and associated with such credits, beyond those required for the particular Facility to meet applicable environmental regulations. In no case shall NEP claim a credit at any time if it would cause the Facility to be in violation of the Facility’s applicable all quality emissions limit or any other applicable laws or regulations and NEP shall have no liability in the event the Facility fails to meet applicable environmental regulations.

If the Federal Energy Regulatory Commission (FERC) determines that each or any of the Facilities is not a Qualifying Facility pursuant to 18 C.F.R. Part 292, or each or any of the Facilities otherwise becomes subject to Section 205 of the Federal Power Act or any similar federal requirement, Seller shall file, within sixty (60) days of such event, a rate with FERC requiring payments for electricity generated by such Facility(ies) and sold by Seller to NEP to be based on Seller’s reasonable costs of generating electricity but in no event at a rate higher than the applicable rates specified in Article VI hereof, effective as of the date of such event.

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During the term of this Agreement, Seller agrees that Seller shall not permit landfill gas purchased by it at each or any of the landfills on which the Facilities are located, or waste heat and/or steam generated by each or any of the Facilities, to be sold or used for any purpose other than generating electricity, unless required by regulatory f authorities, without NEP prior written approval which approval shall be granted if Seller demonstrates to NEP’s satisfaction that such sale or use would not adversely affect the present or future level of electricity production at the particular Facility over the remaining tern of this Agreement.

Seller agrees that during the term -of this Agreement it will not sell or otherwise dispose of its interest in each or any of the Facilities without first obtaining NEP’s written consent, which consent shall not be unreasonably withheld.

Commencing as of the Commencement Date of Operation, Seller shall:

(1)           Operate the electric generating unit(s) at each of the Facilities to the maximum extent feasible consistent with Good Utility Practice; Sell shall provide NEP with such information at NEP may reasonably request to determine whether each of the Facilities is being so operated and maintained.

(2)           Operate and maintain each of the Facilities in accordance with Good Utility Practice; Seller shall provide NEP with such information as NEP may reasonably request to determine whether the Facilities are being so operated and maintained.

(3)           Provide NEP prior to the first day of January of each year, or at NEP’s reasonable request, an estimate of the amount of electricity to be generated at each of the Facilities for each of the following twelve (12) months beginning January 1, or the first day of the month following NEP’s request;

(4)           Provide NEP, or its designee, prior to the first day of each month, a schedule of the anticipated generation of electricity at each of the Facilities for such month;

(5)           At NEP’s request, provide NEP, or its designee, prior to 9:00 a.m. of each day, a schedule of the anticipated generation of electricity at each of the Facilities for the next day;

(6)           Use all reasonable efforts to maximize delivery of electricity from each of the Facilities during On-Peak Periods;

(7)           Conduct scheduled maintenance of each of the Facilities during reasonable periods designated by NEP.  NEP shall designate such periods for each calendar year in writing during the preceding December, but not less than ninety (90) days prior to the beginning of a period so designated;

(8)           Cooperate with NEP in the arrangement and conduct of any tests required under the NEPOOL Agreement to determine the Net Capability of each of the Facilities and in operating each of the Facilities in conformity with any applicable requirements of NEPEX and/or its satellite dispatching center, including providing such operating and/or design information to NEP or its designee as NEP may request; and

(9)           Provide NEP such supporting information related to billing as NEP may reasonably request.

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The estimates and schedules provided by Seller under Clauses (3), (4) and (5), above, shall be prepared in good faith, based on landfill gas availability and other conditions anticipated at the time such estimates and schedules are made, but shall not be binding on Seller.  Seller shall, however, promptly inform NEP whenever it appears that actual generation at each or any of the facilities will vary more than ten percent (10%) from the most recent estimates or schedules provided under Clause (3), (4), or (5), above.

The parties recognize that emergencies, accidents, other unusual conditions and events of force majeure as defined in Article XIV, may necessitate a departure from scheduled generation. Seller, however, agrees to use all reasonable efforts to promptly resume scheduled generation.

ARTICLE VI.       PRICE AND BILLING

A.           Prior to July 1, 1988, NEP shall pay Seller monthly for quantities of electricity delivered for sale to NEP hereunder, as determined in accordance with ARTICLE VIII, a price in cents per kilowatthour equal to ninety percent (90%) of Rate X. Commencing on July 1, 1988, and extending until the later to occur of January 1, 1989 or the Commencement Date of Operation, NEP shall pay Seller monthly for quantities of such electricity, a price in cents per kilowatthour equal to four and eight-tenths cents ($.048) per kilowatthour delivered during On-Peak Periods and two and eight-tenth cents ($.028) per kilowatthour delivered during Off-Peak Periods.

B.           Commencing on the later to occur of January 1, 1989 or the Commencement Date of Operation, NEP shall pay Seller monthly for quantities of electricity delivered for sale to NEP hereunder, as determined in accordance with ARTICLE VIII, a price in cents per kilowatthour calculated in accordance with the following formula:

P =           [Q + (R x S)] x U

                       T

Where “P” is the total price in cents per kilowatthour;

“Q” is three and one-half cents (3.5¢) per kilowatthour for electricity delivered during On-Peak Periods and one and one-half cents (1.5¢) per kilowatthour for electricity delivered during Off-Peak Periods, respectively.  NEP may, at its option, upon thirty (30) days written notice to Seller, increase or decrease “Q” for On-Peak Periods and increase or decrease “Q” for Off-Peak Periods; provided, however, that the average value of “Q” for On-Peak Periods and Off—Peak Periods, weighted by the number of hours in the On-Peak and Oft-Peak Periods, shall equal the average value of “Q” for On-Peak Periods and Off-Peak Periods, weighted by the number of hours in the On-Peak and Off-Peak Periods, prior to such revision;

“R is three cents (3¢) per kilowatthour;

8

“S” is 1.00 through December 31, 1989 and in each calendar year thereafter “S” is the Consumer Price Index for Urban Wage Earners and Clerical Workers, unadjusted for seasonal variations, all items indexed for Boston, Massachusetts, as published in the Bureau of Labor Statistics’ CPI Detailed Report (the “CPI Index”) for November of the preceding Calendar Year; provided, however, that if a CPI Index is not published for November, “S” shall be the CPI Index for the first preceding month for which a CPI Index is published;

“T” is 1.00 through December 31, 1989 and in each calendar year thereafter “T” is the CPI Index for November of 1988; provided, however, that if a CPI Index is not published for November of 1988 “T” shall be the CPI Index for the first preceding month for which a CPI Index is published; and

“U” is 1.00 through December 31 of the first full calendar year in which the amount paid by NEP under this ARTICLE VI B for the monthly quantities of electricity delivered hereunder during the calendar year is less than the total amount that would have been paid by NEP for the monthly quantities of electricity delivered hereunder during the calendar year had the price established under this ARTICLE VI B been equal to Rate X as in effect during the calendar year (the “Crossover Year”); and in each month thereafter “U” shall be the lesser of 1.00 or an amount calculated in accordance with the following formula:

U = .5 + (.5 x K)

       L

Where “K” is the quantity of electricity in kilowatthours delivered during the preceding calendar year; and

“L” is:

(i) Until December 31 of the year in which the “Aggregate Differential” as defined in Article VII B, below, is reduced to zero (0), the average quantity of electricity delivered during the Crossover Year and the prior four full calendar years. If fewer than four full calendar years have elapsed from the Commencement Date of Operation to the beginning of the Crossover Year, “L” shall be determined using the average quantity of electricity delivered for all full calendar years from the Commencement date of Operation to the end of the Crossover Year; and

(ii) Thereafter, the “Total Kwhr Production” for the preceding calendar year specified in Appendix B hereto multiplied by the highest Net Capability of the Facilities determined in any year following the Commencement Date of Operation divided by twelve thousand kilowatts (12,000 kw).

9

If a CP Index referred to in “S” above has not been published at the time that such information is required for billing, the value of “P” shall remain unchanged until such publication, at which time a retroactive billing adjustment shall be made.

In the event of any future modification of the basis upon which the CPI Index is calculated, “T” shall be adjusted to be on a consistent basis with “S”.

If publication of the CPI Index is discontinued during the term of this Agreement, the parties agree to meet and mutually agree upon an alternative, but substantially equivalent, method of adjusting the value of “R”, above, in determining the price to be paid by NEP under this Paragraph B.

If the CPI Index employed in calculating the price to be paid by NEP during any month is subsequently revised, then such price shall be recalculated using the revised information and the bills and payments for such month shall be retroactively adjusted to reflect such recalculated price.

Notwithstanding the preceding provisions of this ARTICLE VI B, if Seller delivers a quantity of electricity during the On-Peak Period or Off-Peak Period in any month that exceeds an amount equal to the product of (i) one (1) minus the Contract Percentage (if any) (expressed as a decimal) times (ii) twelve thousand kilowatts (12,000 KW) multiplied by the number of On-Peak hours or Off-Peak hours during the month, respectively (the “Maximum Participation Level”), then NEP shall not be required to pay Seller for any quantity of electricity delivered to NEP in excess of the Maximum Participation Level in the respective On-Peak or Off-Peak Period.

C.           Bills for all amounts due under this ARTICLE VI shall be tendered to NEP monthly. A separate bill shall be rendered for electricity delivered to NEP from each of the Facilities. At NEP’s request, each bill shall contain a breakdown of the amount billed expressed in terms of the fuel-related and non-fuel-related cost to NEP of electricity purchased hereunder.. The breakdown shall be presented on both a cents per kilowatthour basis and a total bill basis. The fuel-related cost to NEP shall be deemed to be equal to a percentage of NEP’s avoided fuel cost per kilowatthour to be specified by NEP and the non-fuel-related cost to NEP shall be deemed to equal the balance. In no event shall any such breakdown of the amount billed result in any increase or reduction in the price payable by NEP to Seller under this ARTICLE VI.  If NEP requests such a breakdown, NEP shall provide Seller with its avoided fuel cost calculation for each month on or before the fifth business day of the following month. No such breakdown shall be construed as indicative, of the cost of fuel or any other expenses incurred by Seller in generating electricity for sale to NEP.

Seller may in writing direct that NEP make payment of bills rendered by Seller hereunder to a third party such as a trust agent for disbursement. If all or any part of any bill shall remain unpaid for more than thirty (3) days after NEP’s receipt of such bill, interest at a rate per annum equal to the Prime Rate shall thereafter accrue and be payable to Seller either (i) on such unpaid amount, or (ii) in the event the amount of the bill is disputed, on the unpaid amount finally determined to be due and payable. NEP may dispute all or any part of any bill by mailing to Seller written notice thereof, stating the reason for such dispute, within thirty (30) days of receipt of such bill and by paying to Seller any amount not in dispute. Both parties shall exercise good faith in resolving any such dispute in a timely manner.

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ARTICLE VII.   DEFAULT/TERMINATION/SECURITY/COMPLETION
SECURITY AND MILESTONES

A.           Events of Default.  The occurrence of any one or more of the following shall constitute an “Event of Default” hereunder:

(1)           If, except to the extent permitted under ARTICLE VI C, above, with regard to amounts in dispute, NEP shall fail to make any payment required pursuant to ARTICLE VI, above, and such failure continues for a period of forty-five (45) days after written notice thereof from Seller;

(2)           If (i) Seller shall fail in any material respect to comply with, observe, perform or shall default in any material respect upon any covenant, warranty or obligation under this Agreement and such failure materially adversely affects the NEP Entitlement in the Facilities, Seller’s ability to furnish to NEP the NEP Entitlement in the Facilities or NEP’s ability to take and receive such NEP Entitlement during the term of this Agreement, and (ii) after written notice thereof from NEP, such failure shall continue for a period of forty-five (45) days, or, if such failure cannot reasonably be cured within such forty-five (45) day period, such further period as shall reasonably be required to effect such cure, provided that Seller commences within such forty-five (45) day period to effect such cure and at all times thereafter proceeds diligently to complete such cure as quickly as reasonably possible;

(3)           If (i) there shall be filed by or against Seller a petition initiating proceedings under the Bankruptcy Code and such proceedings shall not be dismissed within forty-five (45) days or (ii) if Seller shall be in default under the terms of any obligation or agreement secured by any lien(s) and/or security interest(s) on or in Seller’s properties and assets at the Facilities (including, without limitation, any leasehold interest in or possessory interest in the Facilities and any licenses or other rights to use, manage and/or occupy the Facilities, as applicable) and the holder of such lien(s) and/or security interest(s) shall give notice of intention to accelerate and thereafter to commence action to foreclose or otherwise realize on the properties and assets of Seller securing such obligation and/or agreement (hereinafter “Default Notice”) and Seller does not cure such default on or before the expiration of any grace period or waiver applicable to such obligation or agreement; provided, however, that any occurrence set forth in this clause (3) shall not constitute an Event of Default if within forty-five (45) days of the initiation of such proceedings or the giving of such Default Notice Seller instructs NEP in writing to reduce each monthly payment otherwise due Seller from NEP under Article VI, above, during the period that such proceedings remain outstanding or such default remains uncured by an amount equal to the amount by which the Aggregate Differential, as defined in ARTICLE VII B, below, would otherwise have increased over the amount determined for the preceding month. If Seller so instructs NEP, and if such proceedings are subsequently terminated or such default is subsequently cured and Seller reaffirms its intention to perform its obligations hereunder and provides adequate assurance of its ability to perform such obligations, then, within thirty (30) days of NEP receipt of written notice from Seller of the termination of such proceedings or the cure of such default, NEP agrees to pay Seller any aggregate amount by which each of NEP monthly payments have been reduced in accordance with this clause (3) plus interest accrued on each such monthly reduction commencing as of the date of such reduction at a rate per annum equal to the Prime Rate in effect on the first business day of each month;

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(4)           If Seller fails to make a required monthly deposit into the Escrow Account as provided in ARTICLE VII C, below, or if Seller fails to deposit with NEP the Irrevocable Letter of Credit as provided in ARTICLE VII D, below;

(5)           If Seller grants a security interest in the Escrow Account established in accordance with ARTICLE VII C, below, to any party other than NEP; and

(6)           If, prior to December 31, 1996, the currently permitted landfill site on which the Johnston Facility is located does not receive for disposal municipal and commercial solid waste at an average rate of either (i) at least five hundred (500) tons per day over any consecutive two (2) month period, or (ii) at least one thousand (1000) tons per day over any consecutive twelve (12) month period; provided, however, that any occurrence set forth in this clause (6) shall not constitute an Event of Default if within forty-five (45) days of such occurrence Seller instructs NEP in writing to reduce each monthly payment otherwise due Seller from NEP under ARTICLE VI, above, during the period such default remains uncured by an amount equal to the amount by which the Aggregate Differential, as defined in ARTICLE VII B, below, would otherwise have increased over the amount determined for the preceding month. If Seller so instructs NEP. and such default is subsequently cured or if Seller demonstrates to NEP reasonable satisfaction that the Facilities can be expected to generate a Net Electric Output during the balance of this Agreement at a level equal to the projected “Total kWhr Production” specified in Appendix B hereto over the balance of this Agreement times the highest Net Capability of the Facilities determined in any year following the Commencement Date of Operation divided by twelve thousand kilowatts (12,000 kW), then, within thirty (30) days NEP agrees to pay Seller any aggregate amount by which each of NEP’s monthly payments have been reduced in accordance with this clause (6) plus interest accrued on each such monthly reduction commencing as of the date of such reduction at a rate per annum equal to the Prime Rate in effect on the first business day of each month.

Seller shall notify NEP immediately upon the occurrence of an event described in Clause (3)(i), Clause (3)(ii), Clause (5), or Clause (6), above.

The enumeration of Events of Default hereunder shall not be construed to limit or exclude the right of the parties hereto to seek remedies at law or in equity or damages for the breach of any other term, condition, covenant, warranty or obligation hereunder.

B.           Termination.  If an Event of Default shall occur and be continuing, the non—defaulting party may, by notice in writing, terminate this Agreement as of the date of such notice.

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In the event of the termination of this Agreement by NEP pursuant to this ARTICLE VII B, Seller acknowledges and agrees that NEP will suffer direct damages as a result of such termination and that such direct damages are not susceptible of easy determination, but shall in all events be at least equal to the Aggregate Differential, as hereinafter defined, and Seller agrees to pay NEP (as liquidated damages, and not as a penalty) an amount equal to the Aggregate Differential, if any, as of the date of such termination, plus interest thereafter accrued at a rate per annum equal to the Prime Rate.

Notwithstanding any other provision of this Agreement to the contrary, neither the determination of the Aggregate Differential nor seller’s agreement to pay the Aggregate Differential to NEP as liquidated damages shall be construed to limit or affect NEP’s right to assert and prove further direct damages in the event of Seller’s breach of or NEP’s termination of this Agreement, but not direct damages relating to past or future power supply unless Seller breaches ARTICLE V of this Agreement by voluntarily selling or otherwise disposing of its interest in each or any of the Facilities.

For purposes of this Agreement, the term “Aggregate Differential” shall mean an amount determined each month following July 1, 1988 in accordance with the following formula:

A = (B + [[(W x U) — V] x C]] x (1 + F)

Where “A” is the Aggregate Differential for the month;

“B” is the prior month’s Aggregate Differential;

“C is the quantity of electricity delivered hereunder, as determined in accordance with ARTICLE VIII, for the month, expressed in kilowatthours; 

“W” is equal to the following amounts per kilowatthour delivered:

1988             $.0380                 1998               $.0677                 2008                 $.0882

1989               .0550                 1999                 .0694                 2009                   .0907

1990               .0562                 2000                 .0712                 2010                   .0934

1991               .0574                 2001                 .0730                 2011                   .0961

1992               .0587                 2002                 .0750                 2012                   .0989

1993               .0601                 2003                 .0770                 2013                   .1019

1994               .0615                 2004                 .0790                 2014                   .1050

1995               .0630                 2005                 .0812                 2015                   .1082

1996               .0645                 2006                 .0834                 2016                   .1115

1997               .0661                 2007                 .0858                 2017                   .1150

“U” is as calculated in Article VI B.

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“V” is equal to the following amounts per kilowatthour delivered:

1989               .0371                 1999                 .0972                 2009                   .1389

1990               .0390                 2000                 .1001                 2010                   .1450

1991               .0464                 2001                 .1037                 2011                   .1515

1992               .0512                 2002                 .1075                 2012                   .1585

1993               .0555                 2003                 .1109                 2013                   .1659.

1994               .0598                 2004                 .1147                 2014                   .1738

1995               .0844                 2005                 .1189                 2015                   .1823

1996               .0891                 2006                 .1233                 2016                   .1915

1997               .0917                 2007                 .1279                 2017                   .2015

; and

“F” is .0075

C.           Security.

To secure the payment by Seller to NEP of the Aggregate  Differential, as provided in ARTICLE VII B above, Seller shall establish, on or prior to July 1, 1988, an interest bearing escrow account (the “Escrow Account”) with a banking institution acceptable to NEP (the “Escrow Agent”). The Escrow Account shall be established for the benefit of NEP. Seller hereby grants to NEP a security interest in the Escrow Account to secure such payment.

Subject only to Seller’s approved financing, fuel, operation and maintenance obligations as detailed in Appendix C, attached hereto and incorporated herein by reference, each month following July 1, 1988 Seller shall deposit into the Escrow Account an amount equal to five percent (5%) of the total amount paid by NEP to Seller for electricity delivered to NEP under ARTICLE VI of this Agreement during the preceding month; provided, however, that if Seller exercises its option to enter into an Optional Contract under ARTICLE IV, above, the amount to be so deposited during the term of the Optional Contract shall be increased to seven percent (7%) of the total amount paid by NEP to Seller for electricity delivered to NEP under ARTICLE VI of this Agreement during the preceding month. If Seller has insufficient funds in any month to make such deposit due to Seller’s approved financing, fuel, operation and maintenance obligations, then Seller shall provide NEP with written notice of the basis for Seller’s inability to make its required deposits and Seller shall make up the shortfall, together with interest accrued at a rate per annum equal to the Prime Rate, in the first month(s) in which Seller has sufficient funds to both make its required monthly deposit into the Escrow Account and to make up or to reduce such shortfall. Seller’s obligation to make deposits under this ARTICLE VII C shall continue and interest shall accrue until the Aggregate Differential is less than the amount in the Escrow Account, at which time Seller shall have the right to discontinue making such deposits and Seller may withdraw from, and NEP consents to the withdrawal from, the Escrow Account any amount by which the balance in the Escrow Account exceeds the Aggregate Differential from time to time. Such withdrawals may be made at any time but not more often than monthly. Withdrawals shall be made only by a direction to the Escrow Agent made in writing jointly by Seller and NEP. If a balance exists in the Escrow Account at the expiration or termination of this Agreement, such balance shall be paid to NEP. Notwithstanding the foregoing, Seller may at any time and from time to time withdraw any part or all of the balance of the Escrow Account after providing NEP with one or more irrevocable letters of credit issued by a banking or other financial institution reasonably acceptable to NEP (the “Issuer”), and otherwise in accordance with this paragraph. Such irrevocable letter(s) of credit shall be in a total amount equal to the amount to be withdrawn from the Escrow Account by Seller, plus compound interest on the principal amount to be withdrawn, at the then effective rate of interest on the Escrow Account balance, for the initial term of the letter(s) of credit. The letter(s) shall be payable to, and for deposit in, the Escrow Account on the twentieth banking day before the expiration of such letter(s). An irrevocable letter of credit as described herein shall be presented to NEP for its approval as to form at least ten (10) days prior to the effective date thereof, such approval not to be unreasonably withheld, and shall be made effective prior to the corresponding withdrawal of funds by Seller pursuant to this paragraph.

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Any fees charged by the Escrow Agent to maintain the Escrow Account shall be paid directly by Seller and shall not be deducted from the Escrow Account.

D.           Completion Milestones and Security.  NEP is relying on the future availability of the NEP Entitlement in the Facilities to meet the needs of its customers. Seller shall within ten days of the effective date of this Agreement provide NEP with a written development plan that outlines preoperational milestones. The plan shall include, at a minimum, milestone dates for financial closing, permitting (including, without limitation, zoning, air quality, water quality, waste handling), construction start date, and Commencement Date of Operation. Seller shall provide NEP with a quarterly status report on its progress in meeting each of the milestones in its development plan until the Commencement Date of Operation. In addition, Seller shall provide-NEP with immediate written notice of any occurrences of which it is aware that are likely to substantially delay construction start date or the Commencement Date of Operation of the Facilities. Seller shall immediately notify NEP in writing if, and at such time that, it decides to discontinue its efforts to construct the Facilities. If its reason for such decision is the denial of a site or environmental permit required by law for the construction of the Facilities, Seller shall identify for NEP the permit that has been denied and provide NEP with documentation of such denial.

Seller shall, within ten days of the effective date of this Agreement, deposit with NEP an Irrevocable Letter of Credit in the initial amount of $12,000, which amount shall be increased to $120,000 on the earlier to occur of (i) the date on which Seller closes on its financing or lease for the electric generating equipment at the Johnston Facility or (ii) the first anniversary date of the effective date of this Agreement, drawn on a bank or other financial institution reasonably acceptable to NEP (the “Issuer”).  Such Irrevocable Letter of credit shall designate NEP as beneficiary with authority to draw drafts on the Issuer as follows:

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Upon Presentation by NEP of a

Signed Statement Over a

Signature Described as

Amount Payable to NEP                                      “Authorized” that:                                                                

(i) $12,000 “On or prior to twelve months after the effective date of its power purchase agreement with New England Power Company, Northeast Landfill Power Company notified New England Power Company in writing of its decision to discontinue its efforts to construct the Johnston Facility contemplated in such power purchase agreement.”

Or, alternatively,

“Subsequent to twelve months after the effective date of its power purchase agreement with New England Power Company, Northeast Landfill Power Company notified New England Power Company in writing of its decision to discontinue its efforts to construct the Johnston Facility contemplated in such power purchase agreement due to the denial of a site or environmental permit required by law for construction of such Facility.”

(ii) $120,000 “Subsequent to twelve months following the effective date of its power purchase agreement with New England Power Company, Northeast Lanfill Power Company notified New England Power Company in writing of its decision to discontinue its efforts to construct the Johnston Facility contemplated by such power purchase agreement for reasons other than the denial of a site or environmental permit required by law for construction of such Facilities.”

(iii) $120,000 “As of December 31, 1989, the ‘Commencement Date of Operation’ of the Facilities, as defined in the power purchase agreement between Northeast Landfill Power Company and New England Power Company, has not occurred.”

Seller and NEP agree that the Irrevocable Letter of Credit shall not be exercised except as specified above. If Seller issues a notice in writing to NEP as provided in clause (i) or (ii), above, or following the date specified in clause (iii), above, NEP shall have ninety (90) days within which to draw drafts on the Irrevocable Letter of Credit. IF NEP fails to draw such drafts, it shall be deemed to have waived all rights that are provided it under this ARTICLE VII D.

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As soon as reasonably practicable following (i) NEP’s receipt of the payment specified in Clauses (i), (ii), or (iii), above or (ii) the Commencement Date of Operation, the Irrevocable Letter of Credit shall expire, and NEP shall return it to Seller.

Seller acknowledges and agrees that NEP will suffer direct damages as the result of any decision by Seller to discontinue the construction of the Johnston Facility, or the delay beyond December 31, 1989 of the Commencement Date of Operation of the Facilities and that such direct damages shall in all events be at least equal to the amounts specified above as payable to NEP under the Irrevocable Letter of Credit in connection with such event, and Seller agrees that such amounts shall be payable to NEP as provided above as liquidated damages, and not as a penalty.

ARTICLE VIII.   DELIVERY AND MEASUREMENT OF ELECTRICITY

The Net Electric Output generated by each of the Facilities shall be delivered to NEP at points of interconnection between NEP’s System and Seller’s systems in the form of three-phase sixty-hertz alternating current at a voltage determined by mutual agreement of the parties. Momentary voltage fluctuations shall be permitted, provided that they neither disturb service provided by NEP or any affiliate of NEP to its customers nor hinder NEP or any affiliate of NEP in maintaining proper voltage conditions. The location of the interconnection points for each Facility shall be determined prior to the commencement of the Facility’s construction by mutual agreement of the parties.

NEP shall, at Seller’s expense, provide, own, and maintain metering, telemetering and communication equipment at each of the Facilities for measuring and reporting electricity delivered to NEP and the status of switching equipment. Seller shall provide suitable space at each of the Facilities for installation of the metering, telemetering and communication equipment at no cost to NEP The metering equipment shall comply with Good Utility Practice and shall be capable of recording var flow and of segregating electricity delivered during On-Peak Periods arid Off-Peak Periods.

NEP agrees to cause its interconnection and transmission facilities to be operated and maintained in accordance with Good Utility Practice so as to permit the delivery to NEP’s System of each of the Facilities’ Net Electric Output.

Meters shall be read by Seller on the first business day of each month. The quantity of electricity delivered for sale to NEP during the preceding month shall be determined by multiplying such readings by the NEP Entitlement (expressed as a decimal). Daily meter readings and log sheets shall be recorded. If NEP so requests, one (1) copy shall be mailed to NEP each day from each of the Facilities.

All metering equipment associated with the Facilities shall be routinely tested in accordance with Good Utility Practice, at Seller’s expense. Such routine tests shall be conducted not more often than annually. Either party may at any time require an additional test of the metering equipment, provided that the requesting party shall pay the cost of such test. If, at any time, any metering equipment is found to be inaccurate by more than two percent (2%), NEP shall cause such metering equipment to be made accurate or replaced if necessary at Seller’s expense, and meter readings for the period of inaccuracy shall be adjusted so far as the same can be reasonably ascertained, but no adjustment prior to the beginning of the preceding month shall be made by agreement of the parties. The test shall be made in such manner as may be mutually and reasonably agreed upon by the parties. Each party shall comply with any reasonable request of the other concerning the sealing of meters, the presence of a representative of the other party when the seals are broken and the tests are made, and other matters affecting the accuracy of the measurement of electricity delivered from the Facilities. Copies of the test reports shall be made available to both parties. If either party believes that there has been a meter failure or stoppage, it shall immediately notify the other.

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ARTICLE IX.   CONSTRUCTION OF INTERCONNECTION FACILITIES

The interconnection facilities associated with each of the Facilities shall be constructed at Seller’s expense. NEP reserves to itself and its affiliates the construction and ownership of all necessary modifications to its system attributable to the interconnection of each of the Facilities. Seller agrees to pay NEP in advance for all costs that NEP reasonably estimates will be incurred in connection with such activities. NEP shall prepare its estimate in good faith and in accordance with Good Utility Practice. Upon completion of construction, NEP shall prepare a breakdown of all costs incurred in connection with such activities and the parties agree to make a final adjustment to correct for any overpayment or underpayment. NEP represents that in making the interconnections, it will use standard equipment customarily employed by NEP for its own system, all in accordance with Good Utility Practice.

Seller shall be responsible for construction of all other interconnection facilities associated with each of the Facilities. As soon as reasonably practicable, Seller shall furnish, for review and approval by NEP, specifications for such facilities, which approval shall not be unreasonably withheld. Responsibility for making the final interconnection between the systems is reserved exclusively to NEP or its affiliates. Prior to making such interconnections with each of the Facilities, NEP shall have the right to require Seller to provide satisfactory documentation that the Facility and the interconnection facilities constructed by Seller comply with all applicable safety and electrical codes. NEP agrees to exercise good faith in undertaking such interconnections in a timely manner.

ARTICLE X.   ACCESS TO FACILITIES

Properly accredited representatives of NEP or an Affiliate of NEP shall at all reasonable times have access to each of the Facilities to make inspections and obtain information required in connection with this Agreement. While at a Facility, such representatives shall observe such reasonable safety precautions as may be required by Seller and shall conduct themselves in a manner that will not interfere with the operation of the Facility.

ARTICLE XI.   NOTICES: REPRESENTATIVES OF THE PARTIES

Any notice, demand or request required or authorized by this Agreement to be given by one party to the other party shall be in writing. It shall either be personally delivered or mailed, by registered or certified mail, postage prepaid, to the representative of the other party designated in this ARTICLE. Any such notice, demand or request so delivered or mailed shall be deemed to be given when so delivered or mailed.

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Notices and other communications by Seller to NEP shall be addressed to:

Manager, Alternate Energy Projects

New England Power Service Company

25 Research Drive

Westborough, MA  01582

Notices, payments and other communications by NEP to Seller shall be addressed to:

Northeast Landfill Power Company

672 Jerusalem Road

Cohasset, Massachusetts 02025

Attn:   Gordon L. Dean
                                            President

Either party may change its representative by written notice to the other.

The parties’ representatives designated above shall have full authority to act for their respective principals in all technical matters relating to the performance of this Agreement. However, they shall not have authority to amend, modify, or waive any provision of this Agreement.

ARTICLE XII.   INSURANCE, LIABILITY, INDEMNIFICATION, AND
RELATIONSHIP OF PARTIES

A.           Seller shall, at its own expense, acquire and maintain. or cause Seller’s agent to acquire and maintain, throughout the term of this Agreement the following minimum insurance coverages as adjusted for inflation, as long as such coverages or reasonably similar coverages are available on reasonable commercial terms:

(i) Statutory coverage for Worker’s Compensation, and Basic Employers’ Liability Coverage with a limit no less than $500,000;

(ii) Comprehensive General Liability Coverage including Operations, Contractual Liability and Broad Form Property Damage Liability, written with limits no less than;

Bodily Injury — $3 million per occurrence

Property Damage — $1 million per occurrence

or $3 million

Combined Single Limit;

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(iii) Comprehensive Automobile Liability Coverage, including all owned, non—owned, and hired vehicles, written with limits no less than:
Bodily Injury -       $1 million per person/       $2 million per accident   Property Damage -     $500,000 per occurrence;

(iv) All Risk Property Coverage and Boiler and Machinery Coverage against damage to each of the Facilities in an amount not less than the full replacement cost of the Facility (to restore the Facility to its condition prior to the casualty loss) and subject to a reasonable deductible.

Such policies shall be endorsed to require that:

(1) complete copies of each inspection or other report required by or performed for the insurer shall be provided to NEP within thirty (30) days of its completion,

(2) the coverage afforded shall not be canceled or reduced without at least ninety (90) days prior written notice to NEP, and

(3) the insurance proceeds shall be applied to repair of the Facility unless Seller and NEP agree otherwise; and

(v) Business Interruption Insurance as is reasonably available under reasonable commercial terms providing funds to cover all of Seller’s costs to the extent that they would not be eliminated or reduced by the failure of each or any of the Facilities to operate (including but not limited to rent or mortgage payments, interest and principal payments on loans or bonds and salaries and wages) or a period of at least twelve (12) months after a reasonable deductible period.

Minimum insurance coverages required by this Article XII A shall be increased every five years to the nearest $100,000 based on experienced inflation.

The insurance policies specified in Clause (ii) and (iii), above, shall be endorsed naming NEP, its employees, agents, and affiliates as additional insureds with respect to any and all third party bodily injury and/or property damage claims arising from Sellers performance of this Agreement and shall require sixty (60) days written notice to be given to NEP of cancellation and/or material change in any of the policies.

Evidence of insurance for the coverages specified herein shall be provided to NEP prior to the Commencement Date of Operation. During the term of this Agreement, Seller, upon NEP’s reasonable request, shall furnish NEP with certified copies of the insurance policies described in this Article XII A.

The insurance coverages described in Clause (i) through (iii), above, shall be primary to any other coverage available to NEP or to NEP’s affiliates and shall not be deemed to limit Seller’s liability under this Agreement, except to the extent any amounts are paid by such insurance.

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B.           Notwithstanding any other provision of this Agreement to the contrary, neither NEP nor Seller, nor their respective officers, directors, shareholders, partners, agents, employees, patent or affiliates, or their respective officers, directors, shareholders, partners, agents or employees shall be liable to the other party or its parent, subsidiaries, affiliates, officers, directors, shareholders, partners, agents, employees, successors or assigns, for claims for incidental, indirect or consequential damages connected with or resulting from performance or non-performance of this Agreement, including, without limitation, claims in the nature of lost revenues, income or profits irrespective of whether such claims are based upon warranty, negligence, strict liability, contract, operation of law or otherwise. Neither shall the parent or affiliates of NEP or Seller, nor their respective officers, directors, shareholders, partners, agents or employees, be liable for claims for direct damages connected with or resulting from performance or non-performance of this Agreement.

C.           Seller agrees to defend, indemnify and save NEP, its officers, directors, shareholders, partners, employees, agents and affiliates and their officers, directors, shareholders. partners, employees and agents harmless from and against any and all claims, suits, actions or causes of action for damage by reason of bodily injury, death or damage to property caused by Seller, its officers, directors, shareholder, partners, employees, agents or affiliates or caused by or sustained on its facilities, except to the extent caused by an act of negligence or willful misconduct by an officer, director, shareholder, partner, agent, employee or affiliate of NEP, its successors or assigns.

D.           NEP agrees to defend, indemnify and save Seller, its officers, directors, shareholders, partners, employees, agents and affiliates and their officers, directors, shareholders, partners, employees and agents harmless from and against any and all claims, suits, actions, or causes of action for damage by reason of bodily injury, death or damage to property caused by NEP, its officers, directors, shareholder, partners, employees, agents or affiliates or caused by or sustained on its facilities, except to the extent caused by an act of negligence or willful misconduct by an officer, director, shareholder, partner, agent, employee or affiliate of Seller, its successors or assigns.

E.           Nothing in this Agreement shall be construed as creating any relationship between the parties other than that of independent contractors for the sale and purchase of electricity generated by the Facilities.

ARTICLE XIII.   ASSIGNMENT

Neither party shall assign, pledge or otherwise transfer this Agreement or any right or obligation under this Agreement without first obtaining the other party’s written consent, which shall not be unreasonably withheld; except that Seller may assign its interests in this Agreement, in whole or in part, to a financial institution in connection with the construction and/or long term financing of the Facilities or modification thereof without NEP’s consent and NEP may assign its rights and obligations to any Affiliate of NEP within the New England Electric System without Seller’s consent.

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ARTICLE XIV.   FORCE MAJEURE

A.           The parties shall be excused from performing their respective obligations hereunder and shall not be liable in damages or otherwise, if and only to the extent that they are unable to so perform or are prevented from performing by an event of force majeure, including, without limitation, storm, flood, lightning, draught, earthquake, fire, explosion, equipment failure, civil disturbance, labor dispute, act of God or the public enemy, action of a court or public authority, or any other cause beyond their control, including, without limitation, shutdown of, or limited operation of, facilities due to breakdown or unscheduled repair or maintenance.

No event caused by or resulting from (i) Seller’s or NEP’s failure to operate and maintain their respective facilities in accordance with Good Utility Practice or (ii) the reduction of the landfill gas supply to the Facilities shall be deemed to be an event of force majeure under this ARTICLE XIV.

B.           If either party shall rely on the occurrence of an event or condition described in ARTICLE XIV A. above, as a basis for being excused from performance of its obligations under this Agreement, then the party relying on the event or condition shall (i) provide prompt notice to the other party of the occurrence of the event or condition giving an estimation of its expected duration and the probable impact on the performance of its obligations hereunder, (ii) exercise all reasonable efforts to continue to perform its obligations hereunder, (iii) expeditiously take action to correct or cure the event or condition excusing performance, (iv) exercise all reasonable efforts to mitigate or limit damages to the other party to the extent such action will not adversely affect its own interests, and (v) provide prompt notice to the other party of the cessation of the event or condition giving rise to its excuse from performance.

ARTICLE XV.   WAIVERS

The failure of either party to insist in any one or more instance(s) upon strict performance of any of the provisions of this Agreement or to take advantage of any of its rights under this Agreement shall not be construed as a general waiver of any such provision or the relinquishment of any such right, but the same shall continue and remain in full force and effect, except with respect to the particular instance or instances.

ARTICLE XVI.   REGULATION

This Agreement and all rights, obligations, and performances of the parties hereunder, are subject to all applicable state and Federal laws, and to all duly promulgated orders and other duly authorized action of any governmental authority having jurisdiction.

ARTICLE XVII.   INTERPRETATION,  DISPUTE  RESOLUTION

The interpretation and performance of this Agreement shall be in accordance with and controlled by the law of The Commonwealth of Massachusetts, the State or Federal Courts in which shall have exclusive original jurisdiction over cases and controversies arising hereunder.

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ARTICLE XVIII.   PRIOR AGREEMENT SUPERSEDED

This Agreement constitutes the entire agreement between the parties hereto relating to the subject matter hereof and supersedes all previous agreements, discussions, communications and correspondence with respect to the subject matter hereof.

ARTICLE XIX.   USE OF LANDFILLS

Seller represents and warrants that it will secure exclusive rights to purchase the landfill gas produced at each of the currently permitted landfill sites on which the Facilities will be located prior to the Commencement Date of Operation. Except as provided in Article IV and Article V above, neither Seller, nor its officers, directors, shareholders, partners, agents, employees, parent or affiliate, or their respective officers, directors, shareholders, partners, agents or employees, shall directly or indirectly, sell such landfill gas to others, assign to others or waive its rights to such landfill gas, or use such landfill gas to generate electricity for sale.

ARTICLE XX.   SEVERABILITY

If any provision or provisions of this Agreement shall be held invalid, illegal, or unenforceable, the validity, legality, and enforceability of the remaining provisions shall in no way be affected or impaired thereby.

ARTICLE XXI.   MODIFICATIONS

No modification to this Agreement shall be binding on either party unless it shall be in writing and signed by both  parties.

ARTICLE XXII.   COUNTERPARTS

This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written.

NEW ENGLAND POWER COMPANY
By:	/s/ Joseph Harrington
Title:	Vice President

NORTHEAST LANDFILL POWER COMPANY
By:	/s/ Gordon L. Deane
Title:	President

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Page 1 of 2

APPENDIX A

NEP uses a computerized power cost estimation program to establish a relationship between its average and incremental fuel costs. The program computes the probable fuel costs annually, on a forward looking basis. Monthly load duration curves, fuel costs, scheduled unit outages, forced unit outage rates, and unit heat rates are considered in a hypothetical unit dispatch to meet NEP’s annual load on a month-by-month basis. From these data, a relationship between NEP's average and incremental fuel cost is established.

By way of example, a summary of the calculation of NEP’s 1986 annual factors is attached. Three computer runs were made. The first run used NEP’s 1986 estimated load duration curve. The second run was made adding a 100 MW increment of load to all on-peak and off-peak hours. The third run was made subtracting a 100 MW decrement of load from all on-peak and off-peak hours.

The first run provided NEP’s 1986 total fuel cost, which was divided by NEP 1986 energy output to yield its 1986 estimated average fuel cost per MWH. The on-peak incremental fuel cost was determined by dividing the cost of fuel for the sum of the 100 MW increment and the 100 MW decrement of load during the on-peak periods by the energy produced during said periods, to yield NEP’s on-peak incremental fuel cost.  This, in turn, yielded the 1986 on-peak factor. The same procedure, using off-peak components, was used to establish NEP’s 1956 off-peak factor.

Each month the 1986 factors are multiplied by NEP average fuel cost -- as filed with the Federal Energy Regulatory Commission -- to determine NEP’s on-peak and off-peak incremental fuel costs.

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Page 2 of 2

APPENDIX A

METHODOLOGY FOR CALCULATING

NEP’s 1986 ANNUAL FACTORS

DOLLARS

Estimate NEP 1986 total fuel cost with . . . .

(1) … no additional energy (“T”).

(2) … 100 MW of load added to all on-peak hours (“T_on + ”) and with

100 MW of load added to all off-peak hours (“T_off + ”).

(3) … 100 MW of load subtracted from all on-peak hours (“T_on - ”), and with 100 MW of load subtracted from all off-peak hours (“T_off - ”).

ENERGY

Estimate NEP’s 1986 energy production (“E”).

Energy added for on-peak increment/decrement (“E_on”).

Energy added for off-peak increment/decrement (“E_off”).

$/MWH

1986 Estimated Average Fuel Cost = T = $413,198 x 10³ = $21.20/MWH

       E        19,490    GWH

1986 Estimated On-Peak Incremental Cost =

T_on+ - T_on-   = $431,218 – 396,370 = $43.04/MWH

2 E_on                                 2 x 404.8

1986 Estimated Off-Peak Incremental Cost =

T_off+ - T_off-   = $428,321 – 398.9 = $31.17/MWH

2 E_off                                           2 x 471.2

On-Peak Factor =                  43.04                     =           2.03

21 .20

Off-Peak Factor =                 31.17                      =          1.47

21.20

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APPENDIX B

EXHIBIT 1:   PROJECTED OPERATING CAPACITY AND PRODUCTION
Worcester, MA, Johnston, RI and Billerica, MA  Landfill Gas-to-Energy Projects

Cash Flow Year  Calendar Year	1 1987	2 1988	3 1989	4 1999	5 1991	6 1992	7 1993	8 1994	9 1995	10 1996	11 1997	12 1998	13 1999	14 2000	15 2001
WORCESTER
Operating Capacity (in kW)	3,810	3,576	3,357	3,152	2,940	2,700	2,499	2,235	1,960	1,755	1,537	900	900	950	790
kWhr Production (1000 kWhrs)	14,105	20,195	26,469	24,051	23,179	21,916	19,701	17,622	15,453	13,057	12,116	7,726	7,726	7,553	6,271
BILLERICA
Operating Capacity (in kW)	2,940	2,852	2,659	2,497	2,344	1,960	1,960	1,770	1,574	900	900	900	902	759	0
kWhr Production (1000 kWhrs)	7,297	22,331	20,963	19,602	10,482	15,453	15,453	13,957	12,411	7,726	7,726	7,726	7,113	5,902	0
JOHNSTON
Operating Capacity (in kW)	2,800	5,600	5,600	5,600	6,580	7,560	7,560	7,560	8,540	9,520	9,519	10,032	10,174	10,415	10,863
kWhr Production (1000 kWhrs)	5,212	44,150	44,150	44,150	51,077	59,603	59,603	59,603	67,329	75,056	75,051	79,070	80,211	82,114	85,651
TOTALS
Total Operating Capacity	9,550	12,009	11,616	11,249	11,064	12,300	12,019	11,565	12,074	12,255	12,036	11,972	12,056	12,132	11,661
Total kWhr Production (1000 kWhrs)	26,694	94,676	91,582	88,604	95,538	96,972	94,757	91,102	95,195	96,619	94,896	94,543	95,050	95,650	91,932

Cash Flow Year  Calendar Year	16 2002	17 2003	18 2004	19 2005	20 2006	21 2007	22 2008	23 2009	24 2010	25 2011	26 2012	27 2013	28 2014	29 2015	30 2016
WORCESTER
Operating Capacity (in kW)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
kWhr Production (1000 kWhrs)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
BILLERICA
Operating Capacity (in kW)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
kWhr Production (1000 kWhrs)	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
Johnston
Operating Capacity (in kW)	11,107	11,366	11,400	11,400	11,400	11,366	11,107	10,054	10,607	10,367	9,941	9,733	9,491	9,274	9,063
kWhr Production (1000 kWhrs)	87,564	89,610	90,508	90,500	90,500	89,610	87,364	85,571	83,629	81,735	78,375	76,577	74,824	75,116	71,452
TOTALS
Total Operating Capacity	11,107	11,366	11,400	11,400	11,400	11,366	11,107	10,054	10,607	10,367	9,941	9,733	9,491	9,274	9,063
Total kWhr Production (1000 kWhrs)	87,564	89,610	90,508	90,500	90,500	89,610	87,364	85,571	83,629	81,735	78,375	76,577	74,824	75,116	71,452

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Page 1 of 2

APPENDIX C

APPROVED FINANCING, FUEL. & OPERATING EXPENSES

SENIOR TO ESCROW ACCOUNT

The following monthly expenses of Northeast Landfill Power Company shall be senior to the funding of the Escrow Account required under the provisions of Article VII (C).

1.           Financing Costs -- As provided in the loan agreement(s) and/or lease agreement(s) between Seller and project lender(s) and/or lessor(s) and summarized as follows:

(to be completed by Seller and approved by NEP, which approval shall not be unreasonably withheld, prior to Commencement Date of Operation)

2.           Contract Operation & Maintenance Expenses -- As provided in the operation and maintenance agreement(s) between Seller and its contract operator(s) and summarized below:

(to be completed by Seller and approved by NEP, which approval shall not be unreasonably withheld, prior to Commencement Date of Operation)

3.           Fuel Cost/Royalty -- The minimum gas purchase price as provided in the gas sales agreements between Seller and the Northeast Landfill Gas Company plus any rents or royalties due the landfill owner by Seller but not in excess of a monthly limit determined in accordance with the following formula:

ML           = ($10,000  x S)  +  A  +  B  +  C

T

Where “ML” is the monthly limit:

“S” is as defined in ARTICLE VI B of this Agreement;

“T” is as defined in ARTICLE VI B of this Agreement;

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Page 2

“A” is 12.5% of Seller’s revenues under this Agreement derived from electricity produced at the Billerica Facility;

“B” is 17.5% of Seller’s revenues under this Agreement derived from electricity produced at the Worcester Facility; and

“C” is 15% of Seller’s revenues under this Agreement derived from electricity produced at the Johnston Facility.

4.           Insurance & Local Taxes -- The actual cost of insuring the project as required by Project Lenders(s), lessor(s), or this Agreement plus the cost of local excise, property, or other taxes assessed against the project, but not federal income taxes.

In addition, if, under the provisions of ARTICLE VII A (3) or (6), Seller instructs NEP to reduce the monthly payments otherwise due Seller from NEP under ARTICLE VI in order to avoid the occurrence of an Event of Default, then all reasonable expenses incurred by Seller in efforts to cure the circumstances underlying the potential Event of Default or to otherwise provide assurance to NEP of Seller’s ability to perform its obligations under this Agreement shall be senior to the funding of the Escrow Account required under the provisions of ARTICLE VII C.

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Amendment to Power Purchase Agreement

This Amendment (‘Amendment”), dated as of December 1, 1989, amends the Agreement dated as of November 6, 1987, between New England Power Company (“NEP”) and Northeast Landfill Power Company (“NLP”), as assigned by NEP to Massachusetts Electric Company (“MEC”) by assignment dated November 18, 1987, as reassigned by MEC to NEP by reassignment dated February 12, 1988, and as assigned by NLP to Northeast Landfill Power Joint Venture, an Illinois partnership (“Seller”) by assignment dated as of March 31, 1989 (the “Power Purchase Agreement”).

Basic Understandings

Seller is about to obtain its financing for construction of the Facility pursuant to a certain Loan Agreement (“Loan Agreement”), dated as of August 2, 1989 by and between State Street Bank and Trust Company (the “Bank”) and Seller. Before financing can be obtained from the Bank, the Power Purchase Agreement needs to be amended to address certain issues that need clarification.

Accordingly, the parties agree to amend the Power Purchase Agreement as follows:

Section 1.               Rights of the Bank Upon Seller’s Default

(a)           The Bank has the right (but not the obligation) to cure any default on behalf of Seller and exercise, to the extent expressly permitted by the Borrower’s Collateral Assignment and Security Agreement (as such terms are defined in the Loan Agreement), any rights of Seller under the Power Purchase Agreement within the cure periods specified in the Power Purchase Agreement.

29

(b)           NEP will send copies of any default notices under the Power Purchase Agreement to the Bank, at the following address:

State Street Bank and Trust Company

225 Franklin Street

Boston, MA. 02101

Attention: Project Finance Department

(c)           NEP shall incur no liability for inadvertent failure to send default notices to the Bank, but any time limit specified in the Power Purchase Agreement for curing an Event of Default shall not begin to run for the Bank until the Bank receives a copy of the notice.

(d)           NEP will not exercise any of its rights and remedies with respect to default before the expiration of the Bank’s cure period (as specified above).

Section 2                 Assignments by the Bank

If there is an Event of Default under the Loan Agreement, the Bank may (i) exercise Seller’s rights under the Power Purchase Agreement, or (ii) assign or sublease any or all of Seller’s rights, title and interest in, to and under the Power Purchase Agreement to any third party (or parties), as long as such third party:

(a) assumes all of the obligations of Seller under the Power Purchase Agreement (including any accrued liability in respect of the Aggregate Differential); and

(b) is at least as experienced and capable of owning and operating (or causing the operation of) the Facility as Seller.

30

Section 3.  Definition of “Facility” 

As of the Commencement Date of Operation, the landfill gas electric generation project at the landfill located in Johnston, Rhode Island will be the only project which will be initially providing electricity to NEP under the Power Purchase Agreement.  Therefore, the Power Purchase Agreement is amended so that the terms “Facilities” and “Facility” shall each mean the landfill gas-fired electric generation project at the landfill located in Johnston, Rhode Island; provided, however, that if and when the proposed landfill gas-fired electric generation project at the landfill located in Worcester, Massachusetts becomes operational, then the term “Facilities” shall mean both the landfill gas-fired electric generation projects located at landfills in Johnston, Rhode Island and Worcester, Massachusetts and the term “Faci1ity” shall mean either of such projects.

Section 4.                        Waiver of Termination Right

NEP waives any right it may otherwise have and agrees not to terminate the Power Purchase Agreement pursuant to the third paragraph of Article III; provided that the “Commencement Date of Operation” occurs before July 1, 1990.

Section 5.                        Substitution of the word “Account”

The first word in the last line of the first paragraph of Article VII C is amended by deleting the word “Agreement” and substituting the word “Account”.

Section 6.                       Changing the “Commencement Date of Operation”

The definition of “Commencement Date of Operation” is amended by deleting the third paragraph of Article II of the Power Purchase Agreement and by substituting therefor the following sentence: “Commencement Date of Operation” shall mean the later to occur of (i) substantial completion of Phase 1 at the Johnston Facility as per Seller’s construction contract for the Johnston Facility, or (ii) the initial date on which Seller generates at least five megawatts (5MW) of electricity at the Johnston Facility continuously for a period of eight (8) consecutive hours.

31

Section 7.                      Substitution of Appendix C

Appendix C to the Power Purchase Agreement is deleted and a new Appendix C (attached to this Amendment as Exhibit A) is substituted in its place.

Section 8.                      Insurance Proceeds

Pursuant to Article XII A (iv) (3) of the Power Purchase Agreement, the insurance proceeds shall be applied during the term of the Loan Agreement between Seller and the Bank in accordance with Sections 5.9(a)(iii) and 5.9(d) of the Loan Agreement.
Section 9.                      Interconnection Facilities

If NEP does not complete construction of the interconnection facilities associated with Seller’s Facility on or before December 15, 1989, the December 31, 1989 deadline specified for the Commencement Date of Operation in Article VII D., paragraph (iii) on page 20, will be extended by the number of days beyond December 15, 1989 that the interconnection was completed.

The parties have caused their authorized representatives to execute this Amendment on the date(s) set forth below, which Amendment may be signed in counterparts so that each party may retain a signed original. All counterparts will constitute one agreement binding on each of the parties.

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NEW ENGLAND POWER COMPANY
By:	/s/ Joseph Harrington
Title:		Vice President
Date:		12/1/89
NORTHEAST LANDFILL POWER JOINT VENTURE
By:	Northeast Landfill Power Company, a general partner
By:	/s/ Gordon L. Deane
	Gordon L. Deane
Title:		President
Date:		12/2/89

33

EXHIBIT A

APPENDIX C

PART I                    Cash Flow Priorities

The Borrower will use its Cash Flow, and will only make payments and distributions to any Person, in accordance with the priority of payments set forth below on a monthly basis:

(a)           first, principal, interest, fees and expenses due to the Bank pursuant to the terms of the Loan Agreement or any of the Collateral Documents (as such term is defined in the Loan Agreement);

(b)           second, senior operating expenses incurred in the ordinary course of business (other than item (c) below) which are due to RISWMC under the Landfill Gas Lease Agreement, the Town under the Taxes Agreement, payments for insurance, legal and accounting fees incurred in the ordinary course of Borrower’s business, and base gas payments due to GASCO under the Sublease Agreement, all in the preceding order;

(c)           third, senior operating expenses incurred in the ordinary course of business which are due to WPI under the Operating Agreement (other than bonus and penalty payments and other subordinated payments);

(d)           fourth, payments required to be made to the Escrow Account under the Power Purchase Agreement (this Escrow Account will be funded separately);

(e)           fifth, payments to Borrower’s debt reserve account and thereafter to Borrower’s maintenance reserve account at the Bank pursuant to Section 5.12 of the Loan Agreement to the extent the debt reserve account has been drawn upon to make the payments described in item (a) or the maintenance reserve account has been drawn upon to make the payments described in items (b) and (c) above;

(f)           sixth, payments for management fees due to NLP and HW Landfill under the Management Agreements;

(g)           seventh, payments for the initial funding of the Borrower’s debt reserve account and thereafter for the initial funding of the Borrower’s maintenance reserve account, with the Bank, each in accordance with Section 5.12 of the Loan Agreement.

(h)           eighth, additional and excess gas payments due to Gasco under the Sublease Agreement;

(i)           ninth, bonus payments or previously subordinated payments due to WPI under the Operating Agreement;

The balance of Cash Flow after payments described in subparagraphs (a) through (i) above is referred to as “Cash Flow Available for Distribution” which shall be used in accordance with Section 5.27 of the Loan Agreement.

34

PART II                   Special Withdrawals From the Escrow Account

As agreed to by the parties, the Escrow Account will be separately funded by direct payments by NEP of 5% of monthly revenues due to Seller. If, however, after a monthly payment of 5% has been made, it is determined that there were not enough revenues from the remaining 95% of the revenues due to Seller to cover the items described in (a), (b), and (c) of Part I above, NEP and Seller agree to the following:

(i) Seller shall send a written notice to NEP, stating that there were insufficient revenues to cover the items to be funded in subparagraph (a), (b) and (c) of Part I of this Appendix C (“Shortfall”).

(ii) With the notice, Seller shall include documentation of how much in additional funds is needed to cover the Shortfall for the month.

(iii) If Seller’s documentation is accurate, NEP and Seller will send a joint notice to the Escrow Agent, requesting a withdrawal from the Escrow Account equal to (i) the amount needed to cover the Shortfall for the month, or (ii) the total of the month’s 5% payment, whichever amount is less. The Escrow Agent will be directed to make payment of the withdrawal into an account designated by Seller.

The special withdrawals described above only may be made to cover the Shortfall for a particular month. Shortfalls may not be accumulated from month to month in cases where the total of the month’s 5% payment to the Escrow Account does not cover the entire month’s Shortfall.

Part III                      Definitions

For the purpose of this Appendix C, the following terms shall have the following meanings:

“Cash Flow” means for a particular fiscal period of the Borrower, revenues received by the Borrower in the ordinary course of business from its operation of the electrical generation facility at the Johnston landfill and from Gasco pursuant to the terms of the Sublease Agreement (but excluding extraordinary payments contemplated by Section 2.9(a)(i) and (a)(ii) of the Loan Agreement).

“Gasco” means Central Gas Limited Partnership, an Illinois limited partnership, and its successors.

“H-W” means Hayden-Wegman, Inc., a New York corporation, and its successors.

“HW Landfill” means HW Landfill Gas, Inc., a Delaware corporation and its successors.

“Landfill Gas Lease Agreement” means the Landfill Gas Lease Agreement dated May 1, 1987 between RISWMC and H-W, as supplemented by the Supplemental Agreement, dated May 1, 1987, between RISWMC and H-W, as amended by the Amendment to Supplement, dated July 28, 1988, between RISWMC and H-W, as assigned by H-W to the Borrower by Assignment, dated as of March 31, 1989, and as amended by the Amendment dated as of March 31, 1989 between RISWMC and H-W and consented to by RISWMC as of March 31, 1989.

35

“Management Agreements” means the Management Agreement between the Borrower and NLP and the Management Agreement between the Borrower and H-W Landfill, each to be entered into prior to the initial construction borrowing under the Loan Agreement in the form approved in writing by the Bank, providing for the management of the Borrower.

“Operating Agreement” has the meaning set forth in Section 3.2(1) of the Loan Agreement, or any substitution thereof if approved in writing by the Bank pursuant hereto.

“Person” means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including with limitation a government or political subdivision or an agency or instrumentality thereof.

“RISWMC” means Rhode Island Solid Waste Management corporation, a corporation created by the State of Rhode Island.

“Sublease Agreement” means the Landfill Gas Contract and Sublease Agreement dated as of March 31, 1989 between the Borrower and Gasco pertaining to the Johnston facility.

“Taxes Agreement” means the Agreement dated May 1, 1987 by and among the Town, RISWMC and H-W for Payment in Lieu of Taxes for the landfill gas collection and processing project, as will be assigned to the Borrower by assignment prior to the initial construction borrowing under the Loan Agreement.

“Town” means the Town of Johnston, Rhode Island, a political subdivision of the State of Rhode Island.

“WPI” means Waukesha Pearce Industries, Inc., a Texaco corporation, and its successors.

36

SECOND AMENDMENT TO POWER PURCHASE AGREEMENT

This Amendment (“Amendment”), dated as of October 31, 1991 amends the Agreement dated as of November 6, 1987, between New England Power Company (“NEP”) and Northeast Landfill Power Company (“NLP”), as assigned by NEP to Massachusetts Electric Company (“MEC”) by assignment dated November 18, 1987, as reassigned by MEC to NEP by reassignment dated February 12, 1988, as assigned by NLP to Northeast Landfill Power Joint Venture, an Illinois partnership (“Seller”), by assignment dated as of March 31, 1989 and as amended by an Amendment to Power Purchase Agreement dated December 1, 1989 (the “Power Purchase Agreement”).

Basic Understandings

Seller is about to obtain its term financing for the Facility pursuant to a certain Note Purchase Agreement (“Note Purchase Agreement”), dated as of October 1, 1991 by and among Northwestern National Life Insurance Company, Northern Life Insurance Company and The North Atlantic Life Insurance Company of America (the “Purchasers”) and Seller. Before financing can be obtained from the Purchasers, the Power Purchase Agreement needs to be amended to address certain issues that need clarification.

Accordingly, the parties agree to amend the Power Purchase Agreement as follows:

Section 1.                Rights of the Purchasers Upon Seller’s Default

(a)           The Purchasers have the right (but not the obligation) to cure any default on behalf of Seller and exercise, to the extent expressly permitted by the Project Agreements Assignment and the Security Agreement (as such terms are defined in the Note Purchase Agreement), any rights of Seller under the Power Purchase Agreement within the cure periods specified in the Power Purchase Agreement.

(b)           NEP will send copies of any default notices under the Power Purchase Agreement to the Purchasers, at the following address:

c/o Washington Square Capital, Inc.

Northstar West, Suite 1500

625 Marquette Avenue South

Minneapolis, Minnesota 55402

Attention: James V. Wittich

(c)           NEP shall incur no liability for inadvertent failure to send default notices to the Purchasers, but any time limit specified in the Power Purchase Agreement for curing an Event of Default shall not begin to run for the Purchasers until the Purchasers receive a copy of the notice.

(d)           NEP will not exercise any of its rights and remedies with respect to default before the expiration of the Purchaser’s cure period (as specified above).

37

Section 2.                Assignments by the Purchasers

If there is an Event of Default under the Note Purchase Agreement, the Purchasers may (i) exercise Sellers rights under the Power Purchase Agreement, or (ii) assign or sublease any or all of Seller’s rights, title and interest in, to and under the Power Purchase Agreement and the Facilities to any third party (or parties), as long as such third party:

(a) assumes all of the obligations of Seller under the Power Purchase Agreement (including any accrued liability in respect of the Aggregate Differential); and

(b) is at least as experienced and capable of owning and operating (or causing the operation of) the Facility as Seller.

Section 3.                Substitution of Appendix C

Appendix C to the Power Purchase Agreement is deleted and a new Appendix C (attached to this Amendment as Exhibit A) is substituted in its place.

Section 4.                Insurance Proceeds

Pursuant to Article XII A (iv)(3) of the Power Purchase Agreement, the parties agree that the insurance proceeds shall be applied during the term of the Note Purchase Agreement between Seller and the Purchasers in accordance with paragraph 9 of the Note Purchase Agreement.

Section 5.                Effect on Prior Amendment

This Amendment supersedes the provisions of Sections 1, 2, 7 and 8 of the Amendment to Power Purchase Agreement dated as of December 1, 1989 (the “Prior Amendment”), which Sections shall be of no further force or effect.  All other provisions of the Prior Amendment shall remain in full force and effect with no other modifications or waiver.

The parties have caused their authorized representatives to execute this Amendment on the date(s) set forth below, which Amendment may be signed in counterparts so that each party may retain a signed original. All counterparts will constitute one agreement binding on each of the parties.

38

NEW ENGLAND POWER COMPANY
By:	/s/ Joseph Harrington
Title:		Vice President
Date:		October 31, 1991
NORTHEAST LANDFILL POWER JOINT VENTURE, an Illinois general partnership
By:		Northeast Landfill Power
		Company, a Massachussetts
		corporation and general
		partner
By:	/s/ Gordon L. Deane
Title:		President
Date:		October 31, 1991
And by:		Johnston Natural Power Corporation, a Delaware Corporation and general Partner
By:	/s/ Jerry Jones
Title:		President
Date:		October 31, 1991

39

EXHIBIT A TO SECOND

AMENDMENT TO POWER

PURCHASE AGREEMENT

APPENDIX C

PART I                    Cash Flow Priorities

The Seller will use its Cash Flow, and will only make payments and distributions to any Person, in accordance with the priority of payments set forth below on a monthly basis:

(a)            first, principal, interest, fees and expenses due to the Purchasers pursuant to the terms of the Note Purchase Agreement or any of the Note Documents (as such term is defined in the Note Purchase Agreement);

(b)           second, senior operating expenses incurred in the ordinary course of business (other than item (c) below) which are due to RISWMC under the Landfill Gas Lease Agreement, the Town under the Taxes Agreement, payments for insurance, legal and accounting fees incurred in the ordinary course of Seller’s business, and base gas payments due to GASCO under the Sublease Agreement, all in the preceding order;

(c)            third, senior operating expenses incurred in the ordinary course of business which are due to WPI under the O&M Agreement (other than bonus and penalty payments and other subordinated payments);

(d)            fourth, payments requited to be made to the Escrow Account under the Power Purchase Agreement (this Escrow Account will be funded separately); and

(e)            fifth, the balance of Cash Flow after payments described in subparagraphs (a) through (d) above shall be applied in compliance with the Note Purchase Agreement.

PART II                  Special Withdrawals From the Escrow Account

As agreed to by the parties, the Escrow Account will be separately funded by direct payments by NEP of 5% of monthly revenues due to Seller. If, however, after a monthly payment of 5% has been made, it is determined that there were not enough revenues from the remaining 95% of the revenues due to Seller to cover the items described in (a), (b), and (c) of Part I above, NEP and Seller agree to the following:

(i) Seller shall send a written notice to NEP, stating that there were insufficient revenues to cover the items to be funded in subparagraph (a), (b) and (c) of Part I of this Appendix C (“Shortfall”).

(ii) With the notice, Seller shall include documentation of how much in additional funds is need to cover the Shortfall for the month.

(iii) If Seller’s documentation is accurate, NEP and Seller will send a joint notice to the Escrow Agent, requesting a withdrawal from the Escrow

40

Account equal to (i) the amount needed to cover the Shortfall for the month, or (ii) the total of the months 5% payment, whichever amount is less. The Escrow Agent will be directed to make payment of the withdrawal into an account designated by Seller.

The special withdrawals described above only may be made to cover the Shortfall for a particular month. Shortfalls may not be accumulated from month to month in cases where the total of the month’s 5% payment to the Escrow Account does not cover the entire month’s Shortfall.

Part III                     Definitions

For the purpose of this Appendix C, the following terms shall have the following meanings:

“Cash Flow” means for a particular fiscal period of the Seller, revenues received by the Seller in the ordinary course of business from its operation of the electrical generation facility at the Johnston landfill and from Gasco pursuant to the terms of the Sublease Agreement.

“Gasco” means Central Gas Limited Partnership, an Illinois limited partnership, and its successors.

“H-W” means Hayden-Wegman, Inc., a New York corporation, and its successors.

“JNPC” means Johnston Natural Power Corporation, a Delaware corporation (f/n/a HW Landfill Gas, Inc.), and its successors.

“Landfill Gas Lease Agreement” means the Landfill Gas Lease Agreement dated May 1, 1987 between RISWMC and H-W, as supplemented by the Supplemental Agreement, dated May 1, 1987, between RISWMC and H-W, as amended by the Amendment to Supplement, dated July 28, 1988, between RISWMC and H-W, as assigned by H-W to the Seller by Assignment, dated as of March 31, 1989, as amended by the Amendment dated as of March 31, 1989 between RISWMC and H-WS and consented to by RISWMC as of March 31, 1989, and as amended by the Amendment dated as of October 31, 1991 between RISWMC and Seller.

“Management Agreements” means the Management Agreement between the Seller and NLPC dated October 31, 1989, and the Management Agreement between the Seller and JNPC dated October 31, 1989, providing for the management of the Borrower.

“NLPC” means Northeast Landfill Power Company, a Massachusetts corporation, and its successors.

“O&M Agreement” has the meaning set forth in the Note Purchase Agreement.

“Person” means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including with limitation a government or political subdivision or an agency or instrumentality thereof.

41

“RISWMC” means Rhode Island Solid Waste Management corporation, a corporation created by the State of Rhode Island.

“Sublease Agreement” means the Landfill Gas Contract and Sublease Agreement dated as of March 31, 1989 between the Seller and Gasco pertaining to the Johnston facility.

“Taxes Agreement” means the Agreement dated May 1, 1987 by and among the Town, RISWMC and H-W for Payment in Lieu of Taxes for the landfill gas collection and processing project, as assigned to the Seller by assignment dated   March 31, 1989 .

“Town” means the Town of Johnston, Rhode Island, a political subdivision of the State of Rhode Island.

“WPI” means Waukesha-Pearce Industries, Inc., a Texas corporation, and its successors.

429 9R

42 

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

Subsidiary	Jurisdiction of Organization
Ridgewood  Providence Power Partners, L.P.	Delaware
Ridgewood Pump Services IV Partners, L.P.	Delaware
Indeck Maine Energy, L.L.C.	Illinois
Ridgewood Maine Hydro Power Partners, L.P.	Delaware

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Randall D. Holmes, certify that:

1. I have reviewed this annual report on Form 10-K of Ridgewood Electric Power Trust IV;

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 14, 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 IV;

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 14, 2007

EX-32

Exhibit 32

CERTIFICATION 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 IV (the “Trust”) for the fiscal year ended December 31, 2006, 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
Dated:	December 14, 2007

/s/ Jeffrey H. Strasberg
Name:	Jeffrey H. Strasberg
Title:	Executive Vice President and
	Chief Financial Officer
Dated:	December 14, 2007

EX-99.1

Exhibit 99.1

FINANCIAL STATEMENTS AND

REPORT OF INDEPENDENT CERTIFIED

PUBLIC ACCOUNTANTS

INDECK MAINE ENERGY, LLC

December 31, 2006 and 2005

C O N T E N T S

		Page
Report of Independent Certified Public Accountants		3
Financial Statements
	Balance Sheets	4
	Statement of Operations and Changes in Members’ Deficit	5
	Statements of Cash Flows	6
	Notes to Financial Statements	7 - 18

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

The Members

Indeck Maine Energy, LLC

We have audited the accompanying balance sheets of Indeck Maine Energy, LLC (an Illinois limited liability company) as of December 31, 2006 and 2005, and the related statements of operations and changes in members’ deficit and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America as established by the American Institute of Certified Public Accountants.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Indeck Maine Energy, LLC as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Edison, New Jersey

August 6, 2007

- 3 -

Indeck Maine Energy, LLC

BALANCE SHEETS

December 31,

(in thousands)

ASSETS	2006			2005
Current assets
Cash and cash equivalents	$	3,685		$	3,714
Trade receivables		3,831			5,473
Due from affiliates		137			-
Inventory		1,125			1,753
Prepaid expenses		39			43
Total current assets		8,817			10,983
Property, plant and equipment, net		8,808			6,577
Security deposits		2,542			2,559
Other assets		118			193
Total assets	$	20,285		$	20,312
LIABILITIES AND MEMBERS’ DEFICIT
Current liabilities
Accounts payable and accrued expenses	$	871		$	706
Due to affiliates		896			1,502
Management fees payable		800			700
Term loan payable - current portion		1,100			1,100
Note payable - current portion		48			45
Total current liabilities		3,715			4,053
Term loan payable - long-term portion		623			1,823
Note payable - long-term portion		165			213
Notes payable to members		16,301			16,301
Interest payable to members		3,135			3,403
Total liabilities		23,939			25,793
Commitments and contingencies
Total members’ deficit		(3,654	)		(5,481	)
Total liabilities and members’ deficit	$	20,285		$	20,312

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

- 4 -

Indeck Maine Energy, LLC

STATEMENTS OF OPERATIONS AND

CHANGES IN MEMBERS’ DEFICIT

Year ended December 31,

(in thousands)

	2006			2005			2004
Power generation revenue	$	18,921		$	21,536		$	8,605
Renewable attribute revenue		14,618			12,283			6,179
Total revenues		33,539			33,819			14,784
Cost of revenues		29,921			26,870			16,542
Gross profit (loss)		3,618			6,949			(1,758	)
General and administrative expenses		364			544			394
Income (loss) from operations		3,254			6,405			(2,152	)
Other (expense) income
Other income		12			-			-
Interest income		342			87			9
Interest expense		(1,781	)		(1,550	)		(811	)
Other expense, net		(1,427	)		(1,463	)		(802	)
Net income (loss)		1,827			4,942			(2,954	)
Members’ deficit, beginning		(5,481	)		(10,423	)		(7,469	)
Members’ deficit, ending	$	(3,654	)	$	(5,481	)	$	(10,423	)

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

- 5 -

Indeck Maine Energy, LLC

STATEMENTS OF CASH FLOWS

Year ended December 31,

(in thousands)

	2006			2005			2004
Cash flows from operating activities
Net income (loss)	$	1,827		$	4,942		$	(2,954	)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities
Depreciation		500			324			261
Loss on disposal of vehicle		(34	)		-			-
Noncash interest payable to members		1,615			1,355			683
Changes in operating assets and liabilities
Restricted cash		-			-			(2	)
Trade receivables		1,642			(2,920	)		(2,305	)
Inventory		628			(1,422	)		(271	)
Prepaid expenses		4			44			(74	)
Security deposits		17			(709	)		(1,690	)
Other assets		75			75			(268	)
Accounts payable and accrued expenses		165			192			(76	)
Due to/from affiliates, net		(743	)		(676	)		1,412
Management fees payable		100			100			100
Total adjustments		3,969			(3,637	)		(2,230	)
Net cash provided by (used in) operating activities		5,796			1,305			(5,184	)
Cash flows from investing activities
Capital expenditures		(2,697	)		(2,834	)		(693	)
Cash flows from financing activities
Proceeds from notes payable to members		-			4,000			4,000
Repayment of interest payable to members		(1,883	)		-			-
Repayment of note payable		(45	)		-			-
Repayment of term loan payable, net of restricted cash
applied of $1,777 in 2005		(1,200	)		(1,300	)		-
Proceeds from term loan, net of restricted cash of $1,775		-			-			4,225
Net cash (used in) provided by financing activities		(3,128	)		2,700			8,225
Net (decrease) increase in cash and cash equivalents		(29	)		1,171			2,348
Cash and cash equivalents, beginning of year		3,714			2,543			195
Cash and cash equivalents, end of year	$	3,685		$	3,714		$	2,543
Supplemental disclosure of cash flow information:
Cash paid during the year for interest	$	2,049		$	268		$	111
Supplemental disclosure of noncash investing and financing activities:
Equipment acquired under finance agreement	$	-		$	259		$	-

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

- 6 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS

December 31, 2006 and 2005

NOTE A - DESCRIPTION OF BUSINESS

Indeck Maine Energy, LLC (the “Company”) is an Illinois limited liability company formed on April 1, 1997 by Indeck Energy Services, Inc. (“IES”) for the purpose of acquiring, operating and managing two 24.5 megawatt wood-fired electric generation facilities (the “Facilities”) located in Maine.  The Facilities were acquired on June 10, 1997 and the operations will be dissolved by 2097.  On June 11, 1997, Ridgewood Maine, LLC (“Ridgewood”), which is owned equally by Ridgewood Electric Power Trust IV and Ridgewood Electric Power Trust V, purchased a 50% membership interest in the Company from IES for $14 million.

In accordance with the Operating Agreement, fiscal year allocations are to be made to the members as follows:

1.     Allocation of Profits and Losses

Profits shall be allocated to IES until the cumulative amount of profits allocated is equal to the cumulative amount of distributions made or to be made to each member pursuant to the distribution provisions of the Operating Agreement.

Second, losses, and all remaining profits shall be allocated to Ridgewood.  Also, all depreciation shall be allocated to Ridgewood.

Losses and depreciation allocated to IES in accordance with the Operating Agreement may not exceed the amount that would cause IES to have an Adjusted Capital Account Deficit, as defined, at the end of such year.  All losses and depreciation in excess of this limitation shall be allocated to Ridgewood which will not be subject to this limitation, in proportion to and to the extent of its positive Capital Account Balances, as defined.

Also, if in any fiscal year a member receives an adjustment, allocation or distribution as described in the Operating Agreement, and such allocation or distribution causes or increases an Adjusted Capital Account Deficit for such fiscal year, such member shall be allocated items of income and gain in an amount and manner sufficient to eliminate such Adjusted Capital Account Deficit as quickly as possible.

The Operating Agreement authorizes Ridgewood, as the Tax Matters Member, to divide other allocations of profits, losses and other items of income, gain, loss and deduction among the members in any reasonable manner so as to prevent the allocations from distorting the manner in which they were intended.

- 7 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE A (continued)

2.     Distributions of Net Cash Flow From Operations

First, the Company shall distribute to Ridgewood 100% of Net Cash Flow From Operations, as defined, until Ridgewood has received the full amount of any unpaid portion of Ridgewood’s Priority Return From Operations, as defined, for any preceding fiscal year.

Ridgewood’s Priority Return From Operations is an amount equal to 18% per annum of $14 million, increased by the amount of any additional contribution made by Ridgewood and reduced by the amount of distributions to Ridgewood of Net Cash Flow From Capital Events, as defined.

Second, the Company shall distribute to Ridgewood 100% of Net Cash Flow From Operations until Ridgewood has received Ridgewood’s Priority Return From Operations for the current fiscal year.  As of December 31, 2006, Ridgewood’s Priority Return From Operations is approximately $23.9 million.

Third, the Company shall distribute 100% of Net Cash Flow From Operations to IES, in accordance with its interest until it has collectively received an amount equal to the amount distributed to Ridgewood during the current fiscal year.

Fourth, the Company shall thereafter distribute any remaining balance of Net Cash Flow From Operations 25% to Ridgewood and 75% to IES, until such time as Ridgewood has received aggregate distributions equal to Ridgewood’s Initial Capital Contribution, as defined.  At such time, the distribution percentages shall be allocated 50% to Ridgewood and 50% to IES.

There were no distributions of Net Cash Flow From Operations during the years ended December 31, 2006, 2005 and 2004.

3.     Distributions of Net Cash Flow From Capital Events

The Company shall distribute Net Cash Flow From Capital Events, as defined, with 50% paid to Ridgewood and 50% paid to IES.  Net Cash Flow from Capital Events is defined as any cash received from any source other than Net Cash Flow From Operations.

There were no distributions of Net Cash Flow From Capital events during the years ended December 31, 2006, 2005 and 2004.

- 8 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1.     Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities.  On an ongoing basis, the Company evaluates its estimates, including bad debts, recoverable value of property, plant and equipment and recordable liabilities for litigation and other contingencies.  The Company 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.

2.     Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities when purchased of three months or less as cash and cash equivalents.  Cash balances with banks as of December 31, 2006 and 2005, exceed insured limits by approximately $3,482,000 and $3,511,000, respectively.

3.     Trade Receivables

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

4.     Revenue Recognition

Power generation revenue is recorded in the month of delivery, based on the actual volume sold at daily market rates through an Independent System Operator (“ISO”).  Renewable attribute revenue is derived from the sale of renewable portfolio standard attributes (“RPS Attributes”). As discussed in Note H, qualified renewable electric generation facilities produce RPS Attributes when they generate electricity.  Renewable attribute revenue is recorded in the month in which the attributes are produced, as the Company has substantially completed its obligations for entitled benefits, represented by the underlying generation of power within specific environmental requirements.

- 9 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE B (continued)

5.     Inventory

Inventory, consisting of wood, is stated at the lower of cost or market value, with cost being determined using the first-in, first-out method.

6.     Impairment of Long-Lived Assets

The Company evaluates long-lived assets, such as property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  The determination of whether an impairment has occurred is made by comparing the carrying value of an asset to the estimated undiscounted cash flows attributable to that asset.  If an impairment has occurred, the impairment loss recognized is the amount by which the carrying value exceeds the estimated fair value of the asset, which is based on the estimated discounted future cash flows.

7.     Property, Plant and Equipment

Property, plant and equipment, consisting of land, power generation facilities, equipment and construction in progress, are stated at cost.  Renewals and betterments that increase the useful lives of the assets are capitalized.  Repair and maintenance expenditures are expensed as incurred.

The Company uses the straight-line method of depreciation over the estimated useful life of the assets:

Power generation facilities	20 years
Equipment	5 years

8.     Significant Customers

During 2006, 2005 and 2004, the Company’s two largest customers accounted for 56% and 34%, 63% and 27%, and 57% and 42% of total revenues, respectively.

9.     Income Taxes

No provision is made for income taxes in the accompanying financial statements as the income or loss of the Company is passed through and included in the income tax returns of the members.

- 10 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE B (continued)

 10.     New Accounting Standards and Disclosures

SFAS No. 157

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements.”  SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosures about fair value measurements.  The Company will adopt SFAS No. 157 in the first quarter of 2008 and is still evaluating the effect, if any, on its financial position or results of operations.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”  SFAS No. 159 provides the option to report certain financial assets and liabilities at fair value, with the intent to mitigate volatility in financial reporting that can occur when related assets and liabilities are recorded on different bases.  The Company will adopt SFAS No. 159 in the first quarter of 2008 and is still evaluating the effect, if any, on its financial position or results of operations.

NOTE C - PROPERTY, PLANT AND EQUIPMENT

For the years ended December 31, 2006 and 2005, property, plant and equipment at cost and accumulated depreciation were:

	2006			2005
	(in thousands)
Land	$	158		$	158
Power generation facilities		10,542			8,012
Equipment		211			271
Construction in progress		227			-
		11,138			8,441
Less accumulated depreciation		(2,330	)		(1,864	)
	$	8,808		$	6,577

- 11 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE C (continued)

For the years ended December 31, 2006, 2005 and 2004, the Company recorded depreciation expense of approximately $500,000, $324,000 and $261,000, respectively, which is included in cost of revenues.

NOTE D - LONG-TERM DEBT

On August 6, 2004, the Company entered into a $6,000,000 Mortgage Loan Agreement with Commerce Bank/North (“Commerce”).  Pursuant to the terms of the agreement, the Company received approximately $4,225,000 with the remaining $1,775,000 placed in a restricted reserve account with Commerce.  The loan requires the payment of interest only during the period September 1, 2004 through November 30, 2004.  Interest for this period was based on a variable rate equal to the prime rate plus 1%.  On December 1, 2004, the loan converted to a term loan bearing interest, which is payable monthly, at 6.27% per annum, which was based on the five-year treasury bill rate as of November 24, 2004 plus 275 basis points.  Monthly principal payments of $100,000 commenced on January 1, 2005 and will continue through December 1, 2009.  The loan is secured by the Company’s assets, with the exception of receivables on renewable attribute revenue.

On January 25, 2005, the Company and Commerce agreed to amend the commercial loan.  Pursuant to the amendment, the restricted reserve funds, which amounted to approximately $1,777,000 at December 31, 2004 and were part of the $6,000,000 loan, were applied to the outstanding loan balance without incurring a prepayment penalty.  As a result of this prepayment, the loan will now mature on July 1, 2008.  All other terms of the original agreement remain unchanged.

On August 28, 2006, the Company and Commerce amended the mortgage loan note and subordination agreement whereby the Company was permitted to make payments of up to $2,500,000 to its members in 2006 towards outstanding obligations.    On December 18, 2006, the Company paid approximately $1,883,000 of interest on the subordinated notes payable to its members and paid approximately $617,000 to Ridgewood Power Management LLC (“Ridgewood Management”) for reimbursement of working capital advances.

- 12 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE D (continued)

Following is a summary of term loan payable as of December 31, 2006 and 2005:

	Year ended December 31,
	2006			2005
	(in thousands)
Term loan payable	$	1,723		$	2,923
Less current portion		(1,100	)		(1,100	)
Total long-term portion	$	623		$	1,823

Remaining scheduled repayments of term loan payable as of December 31, 2006 are as follows:

Year ended December 31,	(in thousands)
2007	$	1,100
2008		623
	$	1,723

In December 2005, the Company entered into an agreement to finance equipment for the West Enfield facility.  The promissory note bears interest at the rate of 6.40% per annum.  Monthly installments of approximately $5,000, including interest, commenced in January 2006 and will continue through December 2010.  The loan is collateralized by the equipment.

Following is a summary of the note payable as of December 31, 2006:

	Year ended December 31,
	2006			2005
	(in thousands)
Note payable	$	213		$	258
Less current portion		(48	)		(45	)
Total long-term portion	$	165		$	213

- 13 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE D (continued)

Remaining scheduled repayments of the note payable as of December 31, 2006 are as follows:

Year ended December 31,	(in thousands)
2007	$	48
2008		52
2009		55
2010		58
	$	213

NOTE E - NOTES PAYABLE TO MEMBERS

Notes payable to members consist of the following as of December 31, 2006 and 2005:

	2006		2005
	(in thousands)
Note payable to IES; interest at 5% per annum	$	4,150	$	4,150
Note payable to IES; interest at 12% per annum		2,000		2,000
Note payable to IES; interest at 18% per annum		2,000		2,000
Note payable to Ridgewood; interest at 5% per annum		4,151		4,151
Note payable to Ridgewood; interest at 12% per annum		2,000		2,000
Note payable to Ridgewood; interest at 18% per annum		2,000		2,000
	$	16,301	$	16,301

The notes to members, which are payable on demand, are subordinate to the Commerce term loan.  Accrued interest on the notes payable to members, which is also subordinated to the term loan, is classified as interest payable to members.  As a part of the subordination agreement, the members have agreed that prior to the payment in full of the Commerce loan and termination of all obligations of Commerce, the members shall not, without prior written consent of Commerce, accelerate the maturity of all or any portion of the subordinated debt and related interest, or take any action towards collection of all or any portion of the subordinated debt or enforcement of any rights, powers or remedies under the subordinated debt documents.  On August 28, 2006, the Company and Commerce amended the mortgage loan note (see Note D) and subordination agreement whereby the Company was permitted to pay approximately $1,883,000 of interest on the subordinated notes payable to its members.

- 14 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE E (continued)

Interest payable to members at December 31, 2006 and 2005 is as follows:

	December 31,
	2006		2005
	(in thousands)
IES	$	1,567	$	1,701
Ridgewood		1,568		1,702
	$	3,135	$	3,403

NOTE F - RELATED PARTY TRANSACTIONS

The Company is required to pay certain members of the board of managers a fee for management services of $100,000 per year.  Additional management fees of up to $200,000 per year may be payable contingent upon achieving positive Net Cash Flow from Operations and Capital Events, as defined, and are subordinated to Ridgewood’s Priority Return from Operations, as defined.  For the years ended December 31, 2006, 2005, and 2004, management fees of $100,000 for each of the years are included in cost of revenues.  As of December 31, 2006 and 2005, the Company has management fees payable of $800,000 and $700,000, respectively.

Under an Operating Agreement with Ridgewood Electric Power Trust IV and Ridgewood Electric Power Trust V (collectively, the “Trusts”), Ridgewood Management, an entity related to the managing shareholder of the Trusts through common ownership, provides management, purchasing, engineering, planning and administrative services to the Company.  Ridgewood Management charges the Company at its cost for these services and for the allocable amount of certain overhead items.  Allocations of costs are on the basis of identifiable direct costs, time records or in proportion to amounts invested in projects managed by Ridgewood Management.  During the years ended December 31, 2006, 2005 and 2004, Ridgewood Management charged the Company approximately $684,000, $486,000 and $358,000, respectively, for overhead items allocated in proportion to the amount invested in projects managed.  Ridgewood Management also charged the Company for all of the remaining direct operating and nonoperating expenses incurred during the periods.  Additionally, the Company records noninterest-bearing advances from and due to other affiliates in the ordinary course of business.  At December 31, 2006 and 2005, the Company had outstanding payables and receivables, with the following affiliates:

- 15 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE F (continued)

	Due from				Due to
	2006		2005		2006		2005
	(in thousands)
Ridgewood Management	$	-	$	-	$	896	$	1,432
Ridgewood Providence Power Partners		74		-		-		20
Ridgewood Providence Expansion		63		-		-		50
	$	137	$	-	$	896	$	1,502

NOTE G - FAIR VALUE OF FINANCIAL INSTRUMENTS

At December 31, 2006 and 2005, the carrying value of the Company’s cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, management fee payable and notes payable to members approximates their fair value.  The fair value of the term loan payable, calculated using current rates for loans with similar maturities, does not differ materially from its carrying value.

NOTE H - APPROVAL OF QUALIFICATION

In 1997, Massachusetts enacted the Electric Restructuring Act of 1997 (the “Restructuring Act”).  Among other things, the Restructuring Act requires that all retail electricity suppliers in Massachusetts (i.e., those entities supplying electric energy to retail end-use customers in Massachusetts) purchase a minimum percentage of their electricity supplies from qualified new renewable generation units powered by one of several renewable fuels, such as solar, biomass or landfill.  Beginning in 2003, each such retail supplier must obtain at least one (1%) percent of its supply from qualified new renewable generation units.  Each year thereafter, the requirement increases one-half of one percentage point until 2009, when the requirement equals four (4%) percent of each retail supplier’s sales in that year.  Subsequent to 2009, the increase in the percentage requirement will be determined and set by the Massachusetts Division of Energy Resources (“DOER”).

- 16 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE H (continued)

On July 8, 2002, the Company received a “Statement of Qualification” from the DOER pursuant to the renewable portfolio standards (“RPS”) adopted by Massachusetts.  Since the Company has been qualified, it may sell to retail electric suppliers the RPS Attributes associated with its electrical energy.  Retail electric suppliers need to purchase RPS Attributes associated with renewable energy and not necessarily the energy itself.  Thus, electrical energy and RPS Attributes are separable products and need not be sold or purchased as a bundled product.  Retail electric suppliers in Massachusetts will then use the purchase of such RPS Attributes to demonstrate compliance with the Restructuring Act and RPS Regulations.

NOTE I - COMMITMENTS AND CONTINGENCIES

The Company and several of its affiliates have an agreement with a power marketer for which they are committed to sell RPS Attributes derived from their electric generation.  The agreement provides such power marketer with six separate annual options to purchase such attributes from 2004 through 2009 at fixed prices, as defined.  If the Company and its affiliates fail to supply the required number of attributes, penalties may be imposed.  In accordance with the terms of the agreement, if the power marketer elects to exercise an annual option and the Company and its affiliates produce no attributes for such option year, the Company and its affiliates face a maximum penalty, which is adjusted annually for the change in the consumer price index, among other things, of approximately $3,283,000, measured using current factors, for that option year and any other year in which an option has been exercised and no attributes have been produced.  Pursuant to the agreement, the Company is liable for 70% of the total penalty, but may be liable up to 100% in the event of the default of its affiliates.  In the fourth quarters of 2006 and 2005, the power marketer notified the Company and its affiliates that it has elected to purchase the output for 2007 and 2006, respectively, as specified in the agreement.  In 2006 and 2005, the Company satisfied and delivered the renewable attributes as prescribed in the agreement and, therefore, no penalties were incurred.

As part of the agreement, the Company has assigned and pledged its receivables from renewable attribute revenue to the power marketer as well as deposited $2,175,000 (included in security deposits in the financial statements) with the power marketer.  In addition, the Company’s affiliates have deposited $825,000 with the power marketer for a total deposit of $3,000,000 as of December 31, 2006.

- 17 -

Indeck Maine Energy, LLC

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006 and 2005

NOTE I (continued)

The Company 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 Company may be required to record additional litigation expense.

NOTE J - SUBSEQUENT EVENT

In July 2007, the Company entered into an agreement (“Agreement”) with a private utility located in Maine (“Utility”), to deliver power at fixed prices beginning September 1, 2007 through February 29, 2008.  The pricing under the Agreement provides for escalating prices over its term, which exceeds current spot market pricing.  In the event that power demands from the Utility exceed the Company’s ability to produce, the Company would be required to purchase power on the open market and such prices could exceed the rate charged to the Utility under the Agreement.  Management believes the likelihood of the Company incurring a material negative impact under this contract is remote.  In connection with the Agreement, Ridgewood Renewable Power supplied a letter of credit for $960,000 on behalf of the Company.

- 18 -

EX-99.2

Exhibit 99.2

FINANCIAL STATEMENTS AND REPORT OF

INDEPENDENT CERTIFIED

PUBLIC ACCOUNTANTS

RIDGEWOOD MAINE HYDRO PARTNERS, L.P.

December 31, 2006 and 2005

C O N T E N T S

		Page
Report of Independent Certified Public Accountants		3
Financial Statements
	Balance Sheets	4
	Statements of Income	5
	Statement of Changes in Partners’ Equity	6
	Statements of Cash Flows	7
	Notes to Financial Statements	8 - 16

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

The Partners

Ridgewood Maine Hydro Partners, L.P.

We have audited the accompanying balance sheets of Ridgewood Maine Hydro Partners, L.P. (a Delaware limited partnership) as of December 31, 2006 and 2005, and the related statements of income, changes in partners’ equity and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Partnership’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America as established by the American Institute of Certified Public Accountants.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Ridgewood Maine Hydro Partners, L.P. as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Edison, New Jersey

September 24, 2007

- 3 -

Ridgewood Maine Hydro Partners, L.P.

BALANCE SHEETS

December 31,

(in thousands)

ASSETS	2006		2005
Current assets
Cash	$	206	$	770
Due from affiliates		7		-
Trade receivables		1,210		960
Other current assets		25		34
Total current assets		1,448		1,764
Property, plant and equipment, net		2,658		1,397
Electricity sales agreements, net		1,983		2,687
Other assets		98		98
Total assets	$	6,187	$	5,946
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	591	$	177
Due to affiliates		302		401
Loans payable - current portion		7		28
Total current liabilities		900		606
Loans payable - noncurrent portion		5		12
Total liabilities		905		618
Commitments and contingencies
Partners’ equity		5,282		5,328
Total liabilities and partners’ equity	$	6,187	$	5,946

The accompanying notes are an integral part of these statements.

- 4 -

Ridgewood Maine Hydro Partners, L.P.

STATEMENTS OF INCOME

Year ended December 31,

(in thousands)

	2006			2005			2004
Power generation revenue	$	5,221		$	4,806		$	3,429
Cost of revenues		2,991			3,060			2,813
Gross profit		2,230			1,746			616
Operating expenses
General and administrative expenses		147			199			216
Impairment of electricity-generating assets		-			119			158
Impairment of electricity sales agreements		-			191			197
Total operating expenses		147			509			571
Income from operations		2,083			1,237			45
Other income (expense)
Interest (expense) income, net		(39	)		(5	)		(4	)
Other income		10			-			1,018
Total other (expense) income, net		(29	)		(5	)		1,014
Net income	$	2,054		$	1,232		$	1,059

The accompanying notes are an integral part of these statements.

- 5 -

Ridgewood Maine Hydro Partners, L.P.

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2004, 2005 and 2006

	Total
	partners’ equity
Partners’ equity, January 1, 2004	$	6,475
Cash distributions		(1,755	)
Net income		1,059
Partners’ equity, December 31, 2004		5,779
Cash distributions		(1,683	)
Net income		1,232
Partners’ equity, December 31, 2005		5,328
Cash distributions		(2,100	)
Net income		2,054
Partners’ equity, December 31, 2006	$	5,282

The accompanying notes are an integral part of this statement.

- 6 -

Ridgewood Maine Hydro Partners, L.P.

STATEMENTS OF CASH FLOWS

Year ended December 31,

(in thousands)

	2006			2005			2004
Cash flows from operating activities
Net income	$	2,054		$	1,232		$	1,059
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation and amortization		869			853			866
Impairment of electricity-generating assets		-			119			158
Impairment of electricity sales agreements		-			191			197
Changes in operating assets and liabilities
Trade receivables		(250	)		(224	)		42
Due to/from affiliates, net		(106	)		331			(406	)
Other current assets		9			(15	)		17
Other assets		-			(10	)		27
Accounts payable and accrued expenses		414			140			(245	)
Total adjustments		936			1,385			656
Net cash provided by operating activities		2,990			2,617			1,715
Cash flows from investing activities
Capital expenditures		(1,426	)		(174	)		(29	)
Cash flows from financing activities
Repayments of loan payable		(28	)		(67	)		(40	)
Cash distributions to partners		(2,100	)		(1,683	)		(1,755	)
Net cash used in financing activities		(2,128	)		(1,750	)		(1,795	)
Net (decrease) increase in cash		(564	)		693			(109	)
Cash, beginning of year		770			77			186
Cash, end of year	$	206		$	770		$	77
Supplemental disclosure of cash flow information:
Cash paid during the year for
Interest	$	41		$	5		$	4
Supplemental disclosure of noncash investing and
financing activities:
Vehicles acquired under finance agreement	$	-		$	-		$	148

The accompanying notes are an integral part of these statements.

- 7 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS

December 31, 2006

(dollar amounts in thousands)

NOTE A - DESCRIPTION OF BUSINESS

On August 15, 1996, Ridgewood Maine Hydro Partners, L.P. was formed as a Delaware limited partnership (“Partnership”).  Ridgewood Maine Hydro Corporation, a Delaware corporation (“RMHCorp”), is the sole general partner of the Partnership and is owned equally by Ridgewood Electric Power Trust IV (“Trust IV”) and Ridgewood Electric Power Trust V (“Trust V”), both Delaware business trusts (collectively, the “Trusts”).  The Trusts are equal limited partners in the Partnership and have a common Managing Shareholder, Ridgewood Renewable Power LLC (“RRP”).  The Partnership shall continue to exist until December 31, 2046 unless terminated sooner by certain provisions of the Partnership Agreement.

On December 23, 1996, in a merger transaction, the Partnership acquired 14 hydroelectric projects located in Maine (the “Maine Hydro Projects”) from CHI Energy, Inc. (CHI Energy, Inc. was subsequently acquired by and became a subsidiary of Enel North America, Inc.).  Maine Hydro Projects have electrical generating capacity of 11.3 megawatts and are operated under contract by Ridgewood Power Management LLC (“RPM”), an affiliate of RRP.  The electricity generated is sold under long-term electricity sales agreements.  All the electricity sales agreements to the Partnership are with either Central Maine Power Company (“CMP”) or Bangor Hydro-Electric Company (“BHC”).

NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1.    Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires the Partnership to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities.  On an ongoing basis, the Partnership evaluates its estimates, including bad debts, recoverable value of property, plant and equipment, electricity sales agreements and recordable liabilities for litigation and other contingencies.  The Partnership bases its estimates on historical experience, current and expected conditions and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates under different assumptions or conditions.

- 8 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE B (continued)

2.    Cash and Cash Equivalents

The Partnership considers all highly liquid investments with maturities when purchased of three months or less as cash and cash equivalents.  Cash balances with banks as of December 31, 2006 and 2005, exceed insured limits by approximately $105 and $668, respectively.  As of December 31, 2006 and 2005, there are no cash equivalents.

3.    Trade Receivables

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

4.    Revenue Recognition

Power generation revenue is recorded in the month of delivery, based on the estimated volumes sold to customers at rates stipulated in the related electricity sales agreement.  Adjustments are made to reflect actual volumes delivered when the actual volumetric information subsequently becomes available.  Final billings did not vary significantly from estimates during the years ended December 31, 2006, 2005 and 2004.

5.    Impairment of Long-Lived Assets and Intangibles

The Partnership evaluates the Company’s intangibles assets with definite lives and long-lived assets, such as property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  The determination of whether an impairment has occurred is made by comparing the carrying value of an asset to the estimated undiscounted cash flows attributable to that asset.  If an impairment has occurred, the impairment loss recognized is the amount by which the carrying value exceeds the estimated fair value of the asset, which is based on the estimated future cash flows discounted at the Company’s estimated cost of capital.

6.    Property, Plant and Equipment

Property, plant and equipment, consisting of hydroelectric generation facilities (“HEGFs”), equipment, vehicles and construction in progress, are stated at cost less accumulated depreciation.

- 9 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE B (continued)

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 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.

The Partnership uses the straight-line method of depreciation over the estimated useful lives of the assets:

HEGFs	30 – 50 years
Equipment	5 years
Vehicles	5 years

7.    Income Taxes

No provision is made for income taxes in the accompanying financial statements as the net income (loss) of the Partnership is passed through and included in the income tax returns of the respective partners.

8.    Reclassifications

Certain items in previously issued financial statements have been reclassified for comparative purposes.  This had no effect on net income.

9.    New Accounting Standards and Disclosures

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes,” an interpretation of SFAS No. 109, “Accounting for Income Taxes.”  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.  FIN 48 will be effective for the Partnership beginning January 1, 2007.  The Partnership does not believe that the adoption of FIN 48 will have a material impact on its financial statements.

- 10 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE B (continued)

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” to define fair value, establish a framework for measuring fair value in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and expand disclosures about fair value measurements.  SFAS No. 157 requires quantitative disclosures using a tabular format in all periods (interim and annual) and qualitative disclosures about the valuation techniques used to measure fair value in all annual periods.  SFAS No. 157 will be effective for the Partnership beginning January 1, 2008.  The Partnership is currently evaluating the impact of adopting SFAS No. 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”  SFAS No. 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value.  SFAS No. 159 will be effective for the Partnership on January 1, 2008.  The Partnership is currently evaluating the impact of adopting SFAS No. 159 on its financial statements.

NOTE C - IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES

The Partnership performed impairment assessments for each of the years ended December 31, 2005 and 2004, and noted that the carrying value exceeded the estimated fair value of the asset in 2005 and 2004.  As a result, the Partnership recorded impairments of property, plant and equipment of $119 and $158 and impairments of electricity sales agreements of $191 and $197 for the years ended December 31, 2005 and 2004, respectively.  For the year ended December 31, 2006, there were no triggering events and the Partnership did not perform an impairment assessment.

- 11 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE D - PROPERTY, PLANT AND EQUIPMENT

At December 31, 2006 and 2005, property, plant and equipment at cost and accumulated depreciation were:

	2006			2005
HEGFs	$	3,057		$	1,476
Equipment		71			76
Vehicles		152			147
Construction in progress		-			155
		3,280			1,854
Less accumulated depreciation		(622	)		(457	)
	$	2,658		$	1,397

For the years ended December 31, 2006, 2005 and 2004, the Partnership recorded depreciation expense of $165, $79 and $56, respectively, which is included in cost of revenues.

NOTE E - ELECTRICITY SALES AGREEMENTS

At December 31, 2006 and 2005, the gross and net amounts of intangible assets were:

	2006			2005
Electricity sales agreements - gross	$	11,514		$	11,514
Less accumulated amortization expense		(9,531	)		(8,827	)
Electricity sales agreements - net	$	1,983		$	2,687

A portion of the purchase price of the Maine Hydro Projects was assigned to the electricity sales agreements and is being amortized over the duration of the contracts (11 to 21 years) on a straight-line basis.  During the years ended December 31, 2006, 2005 and 2004, the Partnership recorded amortization expense of $704, $774 and $810, respectively, which is included in cost of revenues.

- 12 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE E (continued)

The Partnership expects to record amortization expense during the next five years as follows:

Year ended December 31,
2007	$	702
2008		541
2009		101
2010		101
2011		101

NOTE F - LOANS PAYABLE

During 2004, the Partnership entered into various loan agreements aggregating $148 at terms of two to four years and interest rates from 4.99% to 6.99% for the purchase of vehicles.  Payments of principal and interest are made monthly.  Following is the summary of the loans payable at December 31, 2006 and 2005:

	2006			2005
Loans payable	$	12		$	40
Less current portion		(7	)		(28	)
Total noncurrent portion	$	5		$	12

Remaining scheduled repayments of the loans payable at December 31, 2006 are as follows:

Year ended December 31,
2007	$	7
2008		5
	$	12

- 13 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE G - LEASE COMMITMENTS

The Partnership leases land on the sites of two of its projects under non-cancelable operating leases expiring in June 2078.  In the case of the Upper Barker project, both the expected life of the project and the term of the ground lease associated with the project extend for a significant period beyond the termination date of the Partnership.  Management believes that, prior to the termination of the Partnership, it will have ample opportunity to provide for the ownership of the project and the satisfaction of the lease obligation during the period following the termination of the Partnership.  Total annual payments are the greater of $18 adjusted annually by CPI or a percentage of the revenue generated from the hydroelectric project.  At December 31, 2006, the future minimum rental payments required under these leases are as follows:

Year ended December 31,
2007	$	18
2008		18
2009		18
2010		18
2011		18
Thereafter		1,225
	$	1,315

Rent expense pursuant to these agreements for the years ended December 31, 2006, 2005 and 2004 was $163, $168 and $80, respectively.

NOTE H - FAIR VALUE OF FINANCIAL INSTRUMENTS

At December 31, 2006 and 2005, the carrying value of the Partnership’s cash and cash equivalents, trade receivables, due to/from affiliates, accounts payable and accrued expenses and loans payable approximates their fair value.  The fair value of the letter of credit does not differ materially from its carrying value.

- 14 -

Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE I - MANAGEMENT AGREEMENT

Following their purchase by the Partnership, the Maine Hydro Projects were operated by a subsidiary of Enel North America, Inc. (“Enel Subsidiary”) under an Operation, Maintenance and Administrative Agreement (“OM&A Agreement”) dated December 23, 1996 and expiring on June 30, 2006.  Under the terms of the OM&A Agreement, the Enel Subsidiary agreed to provide certain services to the Partnership and the Partnership agreed to pay the Enel Subsidiary (i) a fixed fee for certain administration and management services, (ii) an amount for certain services at hourly rates for actual hours worked by the Enel Subsidiary employees and (iii) an amount equal to the out-of-pocket expenses incurred by the Enel Subsidiary in performing the services specified in the OM&A Agreement.

The fixed fee for administration and management services was adjusted on June 30 of each year for inflation.

In early 2004, a dispute arose with respect to the services performed by the Enel Subsidiary pursuant to the OM&A Agreement.  On April 30, 2004, the Partnership and the Enel Subsidiary agreed to a settlement of the dispute under which: (a) the OM&A Agreement was terminated effective April 30, 2004 without further obligation or liability, (b) the Enel Subsidiary agreed to pay $500 in damages to the Partnership, and (c) the Enel Subsidiary agreed to cancel $405 in outstanding amounts owed by the Partnership to the Enel Subsidiary at the time of the settlement.  In 2004, the Partnership recognized the $500 in damages and the $405 in cancelled liabilities as other income in the statements of operations.

NOTE J - RELATED PARTY TRANSACTIONS

Effective May 1, 2004, pursuant to an Operating Agreement with the Partnership (the “Operating Agreement”), RPM began to provide management, purchasing, engineering, planning and administrative services to the Partnership.  RPM charges the Partnership at its cost for these services and for the allocable amount of certain overhead items.  Allocations of costs are on the basis of identifiable direct costs, time records or in proportion to amounts invested in projects managed by RPM.  During the years ended December 31, 2006, 2005 and 2004, RPM charged the Partnership $375, $349 and $354, respectively (included in cost of revenues in the statements of income) for overhead items allocated in proportion to the amount invested in projects managed.  RPM also charged the Partnership for all direct operating and nonoperating expenses incurred during the periods under the term of the Operating Agreement.  These charges may not be indicative of costs incurred if the Partnership were not operated by RPM.

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Ridgewood Maine Hydro Partners, L.P.

NOTES TO FINANCIAL STATEMENTS (continued)

December 31, 2006

(dollar amounts in thousands)

NOTE J (continued)

Additionally, the Partnership records noninterest-bearing advances from and due to other affiliates in the ordinary course of business.  At December 31, 2006 and 2005, the Partnership had outstanding payables and receivables, with the following affiliates:

	Due from at				Due to at
	December 31,				December 31,
	2006		2005		2006		2005
RPM	$	-	$	-	$	279	$	284
Trust IV		-		-		23		73
Trust V		6		-		-		44
Other affiliates		1		-		-		-
	$	7	$	-	$	302	$	401

NOTE K - COMMITMENTS AND CONTINGENCIES

For the years ended December 31, 2006, 2005 and 2004, the Partnership sold all of its electrical output to two public utility companies, CMP and BHC, pursuant to long-term electricity sales agreements.  The Partnership has twelve contracts with CMP, of which one expires in July 2007 and eleven expire in December 2008.  Each has provisions for renewal or extension subject to agreement of both parties.  The Partnership has two electricity sales agreements with BHC, which expire in December 2014 and February 2017.  The Partnership is required to maintain a standby letter of credit in the amount of $99 under the long-term electricity sales agreements, which is provided under and collateralized by an RRP line of credit facility.

The Partnership 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 Partnership may be required to record additional litigation expense.

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