American DG Energy 10K/A 2009 Annual report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

For the fiscal year ended December 31, 2009

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

Commission file number 001-34493

AMERICAN DG ENERGY INC.

(Exact name of Registrant as specified in its charter)

Delaware	04-3569304
(State of incorporation or organization)	(IRS Employer Identification No.)

45 First Avenue
Waltham, Massachusetts	02451
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s Telephone Number, Including Area Code: (781) 622-1120

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $0.001 par value	NYSE Amex

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ¨ No x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

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 the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or an amendment to this Form 10-K. x

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

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer ¨	Smaller reporting company x
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

As of June 30, 2009, the aggregate market value of the voting shares of the registrant held by non-affiliates on the OTC Bulletin Board was approximately $41,397,788 based on a closing price per share of $2.75. For purposes of this calculation, an aggregate of 20,717,659 shares of common stock held directly or by affiliates of the directors and officers of the registrant have been included in the number of shares held by affiliates.

As of March 31, 2010 the registrant’s shares of common stock outstanding were: 44,088,964.

EXPLANATORY NOTE

This Amendment No. 1, or this Amendment, to our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, or the Annual Report, is being filed in response to certain comments made by the staff of the Securities and Exchange Commission, or the SEC. In response to such comments, we have amended the following items:

Item 1. “Business” is being amended and restated in its entirely;

Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Sercurities—Recent Sales of Unregistered Securities” is being amended and restated in its entirety;

Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” is being amended and restated in its entirety;

Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations for the Years Ended December 31, 2009 and December 31, 2008” is being amended and restated in its entirety;

Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” is being amended and restated in its entirety;

Item 9A(T). “Controls and Procedures—Management’s Evaluation of Disclosure Controls and Procedures” is being amended and restated in its entirety;

Item 10. “Directors, Executive Officers and Corporate Governance—Executive Officers and Directors” is being amended to restate the biography of the company’s Chief Financial Officer, Anthony S. Loumidis;

Item 10. “Directors, Executive Officers and Corporate Governance—Executive Officers and Directors—Director Nomination Process” is being amended and restated in its entirety;

Item 10. “Directors, Executive Officers and Corporate Governance—Executive Officers and Directors—Board Leadership Structure” is being amended and restated in its entirety;

Item 11. “Executive Compensation” is being amended to restate the Summary Compensation Table in order to revise footnote three to the table;

Item 11. “Executive Compensation—Employment Contracts and Termination of Employment and Change-in-Control Arrangements” is being amended and restated in its entirety;

Item 15. “Exhibits and Financial Statement Schedules” is being amended, but not restated, only to the extent necessary to correct the exhibit numbers of the items previously referenced in our Annual Report as Exhibits 10.1, 10.2, 10.3 and 10.4; and

Our Consolidated Financial Statements and all notes thereto are being amended and restated in their entirety.

Unless otherwise stated, all financial data and other information presented in this Amendment is as of December 31, 2009 and has not been updated.

Except as stated herein, this Amendment does not reflect events occurring after the filing of the Annual Report on March 31, 2010, or the Original Filing, and no attempt has been made in this Amendment to modify or update other disclosures as presented in the Original Filing. Accordingly, this Amendment should be read in conjunction with our filings with the SEC subsequent to the filing of the Original Filing. Additionally, the portions of Items 10 and 11 not amended hereby have not been modified, and such items of our Annual Report remain incorporated by reference to our Definitive Proxy Statement on Schedule 14A, filed with the SEC on April 30, 2010.

In addition, we are filing or furnishing, as indicated in this Amendment, as exhibits certain currently dated certifications and a currently dated consent of Caturano and Company, INC.

This Amendment is limited in scope to the items described above and does not amend, update, or change any other items or disclosures contained in the Annual Report. Accordingly, all other items and sections that remain unaffected are omitted in this filing. As used herein and in our other documents filed with the SEC, all references to our Annual Report are deemed to include this Amendment.

Item 1. Business.

General

American DG Energy Inc., or the company, we, our or us, distributes, owns and operates clean, on-site energy systems that produce electricity, hot water, heat and cooling. Our business model is to own the equipment that we install at customers’ facilities and to sell the energy produced by these systems to the customers on a long-term contractual basis. We call this business the American DG Energy “On-Site Utility”.

We offer natural gas powered cogeneration systems that are highly reliable and energy efficient. Our cogeneration systems produce electricity from an internal combustion engine driving a generator, while the heat from the engine and exhaust is recovered and typically used to produce heat and hot water for use at the site. We also distribute and operate water chiller systems for building cooling applications that operate in a similar manner, except that the engine’s power drives a large air-conditioning compressor while recovering heat for hot water. Cogeneration systems reduce the amount of electricity that the customer must purchase from the local utility and produce valuable heat and hot water for the site to use as required. By simultaneously providing electricity, hot water and heat, cogeneration systems also have a significant, positive impact on the environment by reducing the carbon or CO2 produced by offsetting the traditional energy supplied by the electric grid and conventional hot water boilers.

Distributed Generation of electricity, or DG, often referred to as cogeneration systems, or combined heat and power systems, or CHP, is an attractive option for reducing energy costs and increasing the reliability of available energy. DG has been successfully implemented by others in large industrial installations over 10 Megawatts, or MW, where the market has been growing for several years, and is increasingly being accepted in smaller size units because of technology improvements, increased energy costs and better DG economics. We believe that our target market (users of up to 1 MW) has been barely penetrated and that the reduced reliability of the utility grid, increasing cost pressures experienced by energy users, advances in new, low cost technologies and DG-favorable legislation and regulation at the state and federal level will drive our near-term growth and penetration into our target market. The company maintains a website at www.americandg.com, but our website address included in this Annual Report is a textual reference only and the information in the website is not incorporated by reference into this Annual Report.

The company was incorporated as a Delaware corporation on July 24, 2001 to install, own, operate and maintain complete DG systems, or energy systems, and other complementary systems at customer sites and sell electricity, hot water, heat and cooling energy under long-term contracts at prices guaranteed to the customer to be below conventional utility rates. As of December 31, 2009, we had installed energy systems, representing approximately 4,210 kilowatts, or kW, 33.5 million British thermal units, or MMBtu’s, of heat and hot water and 2,200 tons of cooling. kW is a measure of electricity generated, MMBtu is a measure of heat generated and a ton is a measure of cooling generated. Due to the high efficiency CHP systems, the Environmental Protection Agency, or EPA, has recognized them as a means to improve the environment. We have estimated that our currently installed energy systems running at 100% capacity have the potential to produce approximately 23,000 metric tons of carbon equivalents, less than typical separate heat and power systems, resulting in emissions reductions equivalent to planting 4,710 acres of forest or removing the emissions of 3,780 automobiles.

We believe that our primary near-term opportunity for DG energy and equipment sales is where commercial electricity rates exceed $0.12 per kW hour, or kWh, which is predominantly in the Northeast and California. Attractive DG economics are currently attainable in applications that include hospitals, nursing homes, multi-tenant residential housing, hotels, schools and colleges, recreational facilities, food processing plants, dairies and other light industrial facilities. Two CHP market analysis reports sponsored by the Energy Information Administration, or EIA, in 2000 detailed the prospective CHP market in the commercial and institutional sectors1 and in the industrial sectors2. These data sets were used to estimate the CHP market potential in the 100 kW to 1 MW size range for the hospitality, healthcare, institutional, recreational and light industrial facilities in California, Connecticut, Massachusetts, New Hampshire, New Jersey and New York, which are the states where commercial electricity rates exceed $0.12 per kWh. Based on those rates, those states define our market and comprise over 163,000 sites totaling 12.2 million kW of prospective DG capacity. This is the equivalent of an $11.7 billion annual electricity market plus a $7.3 billion heat and hot water energy market, for a combined market potential of $19 billion. The data used to calculate the company’s market potential are derived from the reports cited above, however the calucation of the total market potential is estimated by the company.

1 See The Market and Technical Potential for Combined Heat and Power in the Commercial/Institutional Sector; Prepared for the Energy Information Administration; Prepared by ONSITE SYCOM Energy Corporation; January 2000.

2 See The Market and Technical Potential for Combined Heat and Power in the Industrial Sector; Prepared for the Energy Information Administration; Prepared by ONSITE SYCOM Energy Corporation; January 2000.

We believe that the largest number of potential DG users in the U.S. require less than 1 MW of electric power and less than 1,200 tons of cooling capacity. We are able to design our systems to suit a particular customer’s needs because of our ability to place multiple units at a site. This approach is part of what allows our products and services to meet changing power and cooling demands throughout the day (also from season-to-season) and greatly improves efficiency through a customer’s varying high and low power requirements.

American DG Energy purchases energy equipment from various suppliers. The primary type of equipment used is a natural gas-powered, reciprocating engine provided by Tecogen Inc., or Tecogen. Tecogen is a leading manufacturer of natural gas, engine-driven commercial and industrial cooling and cogeneration systems suitable for a variety of applications, including hospitals, nursing homes and schools. A CHP system simultaneously produces two types of energy – heat and electricity – from a single fuel source, often natural gas. The two key components of a CHP system are an internal combustion reciprocating engine and an electric generator. The internal combustion reciprocating engine is provided to Tecogen by General Motors. The clean natural gas fired engine spins a generator to produce electricity. The natural byproduct of the working engine is heat. The heat is captured and used to supply space heating, heating domestic hot water, laundry hot water or to provide heat for swimming pools and spas.

As power sources that use alternative energy technologies mature to the point that they are both reliable and economical, we will consider employing them to supply energy for our customers. We regularly assess the technical, economic, and reliability issues associated with systems that use solar, micro-turbine or fuel cell technologies to generate power.

Background and Market

The delivery of energy services to commercial and residential customers in the U.S. has evolved over many decades into an inefficient and increasingly unreliable structure. Power for lighting, air conditioning, refrigeration, communications and computing demands comes almost exclusively from centralized power plants serving users through a complex grid of transmission and distribution lines and substations. Even with continuous improvements in central station generation and transmission technologies, today’s power industry is only about 33% efficient3, meaning that it discharges to the environment roughly twice as much heat as the amount of electrical energy delivered to end-users. Since coal accounts for more than half of all electric power generation, these inefficiencies are a major contributor to rising atmospheric CO2 emissions. As countermeasures are sought to limit global warming, pressures against coal will favor the deployment of alternative energy technologies.

On-site boilers and furnaces burning either natural gas or petroleum distillate fuels produce most thermal energy for space heating and hot water services. This separation of thermal and electrical energy supply services has persisted despite a general recognition that CHP can be significantly more energy efficient than central generation of electricity by itself. Except in large-scale industrial applications (e.g., paper and chemical manufacturing), cogeneration has not attained general acceptance. This was due, in part, to the long-established monopoly-like structure of the regulated utility industry. Also, the technologies previously available for small on-site cogeneration systems were incapable of delivering the reliability, cost and environmental performance necessary to displace or even substantially modify the established power industry structure.

The competitive balance began to change with the passage of the Public Utility Regulatory Policy Act of 1978, a federal statute that has opened the door to gradual deregulation of the energy market by the individual states. In 1979, the accident at Three Mile Island effectively halted the massive program of nuclear power plant construction that had been a centerpiece of the electric generating strategy among U.S. utilities for two decades. Several factors caused utilities’ capital spending to fall drastically, including well publicized cost overruns at nuclear plants, an end to guaranteed financial returns on costly new facilities, and growing uncertainty over which power plant technologies to pursue. Recently, investors have become increasingly reluctant to support the risks of the long-term construction projects required for new conventional generating and distribution facilities.

Because of these factors, electricity reserve margins have declined, and the reliability of service has begun to deteriorate, particularly in regions of high economic growth. Widespread acceptance of computing and communications technologies by consumers and commercial users has further increased the demand for electricity, while also creating new requirements for very high power quality and reliability. At the same time, technological advances in emission control, microprocessors and internet technologies have sharply altered the competitive balance between centralized and DG. These fundamental shifts in economics and requirements are key to the emerging opportunity for DG equipment and services.

3 See Energy Information Administration, Voluntary Reporting of Greenhouse Gases, 2004, Section 2, Reducing Emissions from Electric Power, Efficiency Projects: Definitions and Terminology, page 20.

The Role of DG

DG, or cogeneration, is the production of two sources or two types of energy (electricity or cooling and heat) from a single energy source (natural gas). We use technology that utilizes a low-cost, mass-produced, internal combustion engine from General Motors, used primarily in light trucks and sport utility vehicles that is modified to run on natural gas. The engine spins either a standard generator to produce electricity, or a conventional compressor to produce cooling. For heating, since the working engine generates heat, we capture the byproduct heat with a heat exchanger and utilize the heat for facility applications in the form of space heating and hot water for buildings or industrial facilities. This process is very similar to an automobile, where the engine provides the motion to the automobile and the byproduct heat is used to keep the passengers warm during the winter months. For refrigeration or cooling, standard available equipment uses an electric motor to spin a conventional compressor to make cooling. We replace the electric motor with the same modified engine that runs on natural gas to spin the compressor to run a refrigeration cycle and produce cooling.

DG refers to the application of small-scale energy production systems, including electricity generators, at locations in close proximity to the end-use loads that they serve. Integrated energy systems, operating at user sites but interconnected to existing electric distribution networks, can reduce demand on the nation’s utility grid, increase energy efficiency, avoid the waste inherent in long distance wire and cable transmission of electricity, reduce air pollution and greenhouse gas emissions, and protect against power outages, while, in most cases, significantly lowering utility costs for power users and building operators.

Until recently, many DG technologies have not been a feasible alternative to traditional energy sources because of economic, technological and regulatory considerations. Even now, many “alternative energy” technologies (such as solar, wind, fuel cells and micro-turbines) have not been sufficiently developed and proven to economically meet the demands of commercial users or the ability to be connected to the existing utility grid.

We supply cogeneration systems that are capable of meeting the demands of commercial users and that can be connected to the existing utility grid. Specific advantages of the company’s on-site DG of multiple energy services, compared with traditional centralized generation and distribution of electricity alone, include the following:

Greatly increased overall energy efficiency (typically over 80% versus less than 33% for the existing power grid).

Rapid adaptation to changing demand requirements (e.g., weeks, not years to add new generating capacity where and when it is needed).

Ability to by-pass transmission line and substation bottlenecks in congested service areas.

Avoidance of site and right-of-way issues affecting large-scale power generation and distribution projects.

Clean operation, in the case of natural gas fired reciprocating engines using microprocessor combustion controls and low-cost exhaust catalyst technology developed for automobiles, producing exhaust emissions well below the world’s strictest regional environmental standards (e.g., southern California).

Rapid economic paybacks for equipment investments, often three to five years when compared to existing utility costs and technologies.

Relative insensitivity to fuel prices due to high overall efficiencies achieved with cogeneration of electricity and thermal energy services, including the use of waste heat to operate absorption type air conditioning systems (displacing electric-powered cooling capacity at times of peak summer demand).

Reduced vulnerability of multiple de-centralized small-scale generating units compared to the risk of major outages from natural disasters or terrorist attacks against large central-station power plants and long distance transmission lines.

Ability to remotely monitor, control and dispatch energy services on a real-time basis using advanced switchgear, software, microprocessor and internet modalities. Through our on-site energy products and services, energy users are able to optimize, in real time, the mix of centralized and distributed electricity-generating resources.

The disadvantages of the company’s on-site DG are:

Cogeneration is a mechanical process and our equipment is susceptible to downtime or failure.

The base-rate of an electric utility is determined by a certain number of subscribers. DG at a significant scale will reduce the number of subscribers and therefore it may increase the base-rate for the electric utility for its customer base.

By committing to our long-term agreements, a customer may be forfeiting the opportunity to use more efficient technology that may become available in the future.

Also, DG systems possess significant positive environmental impact. The EPA has created a Combined Heat and Power Partnership to promote the benefits of DG systems. The company is a member of this Partnership. The following statement is found on the EPA web site.

“Combined heat and power systems offer considerable environmental benefits when compared with purchased electricity and onsite-generated heat. By capturing and utilizing heat that would otherwise be wasted from the production of electricity, CHP systems require less fuel than equivalent separate heat and power systems to produce the same amount of energy. Because less fuel is combusted, greenhouse gas emissions, such as carbon dioxide (CO2), as well as criteria air pollutants like nitrogen oxides (NOx) and sulfur dioxide (SO2), are reduced.”

The DG Market Opportunity

We believe that our primary near-term opportunity for DG energy and equipment sales is where commercial electricity rates exceed $0.12 per kW hour, or kWh, which is predominantly in the Northeast and California. Attractive DG economics are currently attainable in applications that include hospitals, nursing homes, multi-tenant residential housing, hotels, schools and colleges, recreational facilities, food processing plants, dairies and other light industrial facilities. Two CHP market analysis reports sponsored by the Energy Information Administration, or EIA, in 2000 detailed the prospective CHP market in the commercial and institutional sectors4 and in the industrial sectors5. These data sets were used to estimate the CHP market potential in the 100 kW to 1 MW size range for the hospitality, healthcare, institutional, recreational and light industrial facilities in California, Connecticut, Massachusetts, New Hampshire, New Jersey and New York, which are the states where commercial electricity rates exceed $0.12 per kWh. Based on those rates, those states define our market and comprise over 163,000 sites totaling 12.2 million kW of prospective DG capacity. This is the equivalent of an $11.7 billion annual electricity market plus a $7.3 billion heat and hot water energy market, for a combined market potential of $19 billion. The data used to calculate the company’s market potential are derived from the aforementioned reports, however the calucation of the total market potential is estimated by the company.

Business Model

We are a DG onsite energy company that sells energy in the form of electricity, heat, hot water and air conditioning under long-term contracts with commercial, institutional and light industrial customers. We install our systems at no cost to our customers and retain ownership of the system. Because our systems operate at over 80% efficiency (versus less than 33% for the existing power grid), we are able to sell the energy produced by these systems to our customers at prices below their existing cost of electricity (or air conditioning), heat and hot water. Our cogeneration systems consist of natural gas-powered internal combustion engines that drive an electrical generator to produce electricity and that capture the engine heat to produce space heating and hot water. Our energy systems also can be configured to drive a compressor that produces air conditioning and that also captures the engine heat. As of December 31, 2009, we had 62 energy systems operational.

To date, each of our installations runs in conjunction with the electric utility grid and requires standard interconnection approval from the local utility. Our customers use both our energy system and the electric utility grid for their electricity requirements. We typically supply the first 20% to 60% of the building’s electricity requirements while the remaining electricity is supplied by the electric utility grid. Our customers are contractually bound to use the energy we supply.

To date, the price that we have charged our customers is set in our customer contracts at a discount to the price of the building’s local electric utility. For the 20% to 60% portion of the customer’s electricity that we supply, the customer realizes immediate savings on its electric bill. In addition to electricity, we sell our customers the heat and hot water at the same price they were previously paying or at a discount equivalent to their discount from us on electricity. Our air conditioning systems are also priced at a discount so that the customer realizes overall cost savings from the installation.

4 See The Market and Technical Potential for Combined Heat and Power in the Commercial/Institutional Sector; Prepared for the Energy Information Administration; Prepared by ONSITE SYCOM Energy Corporation; January 2000.

5 See The Market and Technical Potential for Combined Heat and Power in the Industrial Sector; Prepared for the Energy Information Administration; Prepared by ONSITE SYCOM Energy Corporation; January 2000.

Since we own and operate the energy systems and since our customers have no investment in the units, our customers benefit from no capital requirements and no operating responsibilities. We operate the energy systems so our customers require no staff and have no energy system responsibilities; they are bound, however, to pay for the energy supplied by the energy systems over the term of the agreement.

Energy and Products Portfolio

We provide a full range of CHP product and energy options. Our primary energy and products are listed below:

Energy Sales

Electricity

Thermal (Hot Water, Heat and Cooling)

Energy Producing Products

Cogeneration Packages

Chillers

Complementary Energy Equipment (e.g., boilers, etc.)

Alternative Energy Equipment (e.g., solar, fuel cells, etc.)

Turnkey Installation Energy Producing Products with Incentives

Other Revenue Opportunities

Energy Sales

For customers seeking an alternative to the outright purchase of CHP equipment, we will install, maintain, finance, own and operate complete on-site CHP systems that supply, on a long-term, contractual basis, electricity and other energy services. We sell the energy to customers at a guaranteed discount rate to the rates charged by conventional utility suppliers. Customers are billed monthly. Our customers benefit from a reduction in their current energy bills without the capital costs and risks associated with owning and operating a cogeneration or chiller system. Also, by outsourcing the management and financing of on-site energy facilities to us, they can reap the economic advantages of DG without the need for retaining specialized in-house staff with skills unrelated to their core business. Customers benefit from our On-Site Utility in a number of ways:

Guaranteed lower price for energy

Only pay for the energy they use

No capital costs for equipment, engineering and installation

No equipment operating costs for fuel and maintenance

Immediate cash flow improvement

Significant green impact by the reduction of carbon produced

No staffing, operations and equipment responsibility

Our customers pay us for energy produced on site at a rate that is a certain percentage below the rate at which the utility companies provide them electrical and natural gas services. We measure the actual amount of electrical and thermal energy produced, and charge our customers accordingly. We agree to install, operate, maintain and repair our energy systems at our sole cost and expense. We also agree to obtain any necessary permits or regulatory approvals at our sole expense. Our agreements are generally for a term of 15 years, renewable for two additional five years terms upon the mutual agreement of the parties.

In regions where high electricity rates prevail, such as the Northeast, monthly payments for CHP energy services can yield attractive paybacks (e.g. often 3-5 years) on our investments in On-Site Utility projects. The price of natural gas has a minor effect on the financial returns obtained from our energy service contracts because the value of hot water and other thermal services produced from the recovered heat generated by the internal combustion engine in our on-site DG system will increase in proportion to higher fuel costs. This recovered energy, which comprises up to 60 % of the total heating value of fuel supplied to our CHP equipment, displaces fuel that would otherwise be burned in conventional boilers. Each of our customer sites becomes a profit center. The example below presents the energy supplied by two 75 kW cogeneration units and the economics of a typical energy service contract where we supply 80% of the site’s heat and hot water and 45% of the site’s electricity. Our customers range from hotels to nursing homes and apartment buildings and they usually require two energy systems or more. The savings calculations in the example are based on many variables, such as the customer’s base electricity charge per kWh, the kW used at the site, the operating time of the equipment, the customer’s base gas price per 1 million BTU, or British Thermal Units, the net heat recovery of our equipment, the efficiency of the customer’s boiler, the electric demand savings rate and the discount to the customer, which may range from 0% to 10%. The economics of a typical energy service contact assume the customer’s base electric rate per kWh at $0.14 and the customer’s gas price per 1 million BTU at $12.00. The example also reflects a 2% of expected annual increase in energy costs that should occur over a 15-year period:

	Annual		Term (15 years)
American DG Energy Revenue	$	284,000	$	4,908,000
American DG Energy Gross Margin	$	84,000	$	1,456,000
Customer Savings	$	32,000	$	545,000

The example reflects an American DG Energy investment of $345,000 with a payback in 4 years or a 25% internal rate of return. The example also reflects a 2% of expected annual increase in energy costs that should occur over the 15-year period.

Energy Producing Products

We typically offer cogeneration units sized to produce 75 kW to 100 kW of electricity and water chillers sized to produce 200 to 400 tons of cooling. For cogeneration, we prefer a modular design approach to allow us to group multiple units together to serve customers with considerably larger power requirements. Often, cogeneration units are conveniently dispersed within a large operation, such as a hospital or campus, serving multiple process heating systems that would otherwise be impractical to serve from a single large machine. The equipment we select often yield overall energy efficiencies in excess of 80% (from our equipment supplier’s specifications).

Many other DG technologies are challenged by technical, economic and reliability issues associated with systems that generate power using solar, micro-turbine or fuel cell technologies, which have not yet proven to be economical for typical customer needs. When alternative energy technologies mature to the point that they are both reliable and economical, we will employ them for the best-fit applications.

Service and Installation

Where appropriate, we utilize the best local service infrastructure for the equipment we deploy. We require long-term maintenance contracts and ongoing parts sales. Our centralized remote monitoring capability allows us to keep track of our equipment in the field. Our installations are performed by local contractors with experience in energy cogeneration systems.

For the occasional customers that want to own the CHP system themselves, we offer our “turn-key” option whereby we provide equipment, systems engineering, installation, interconnect approvals, on-site labor and startup services needed to bring the complete CHP system on-line. For some customers, we are also paid a fee to operate the systems and may receive a portion of the savings generated from the equipment.

Other Funding and Revenue Opportunities

American DG Energy is able to participate in the demand response market and receive payments due to the availability of our energy systems. Demand response programs provide payments for either the reduction of electricity usage or the increase in electricity production during periods of peak usage throughout a utility territory. We have also received grants and incentives from state organizations and natural gas companies for our installed energy systems.

Sales and Marketing

Our On-Site Utility services are sold directly to end-users by our in-house marketing team and by established sales agents and representatives. We offer standardized packages of energy, equipment and services suited to the needs of property owners and operators in healthcare, hospitality, large residential, athletic facilities and certain industrial sites. This includes national accounts and other customer groups having a common set of energy requirements at multiple locations.

Our energy offering is translated into direct financial gain for our clients, and is best appreciated by senior management. These clients recognize the gain in cash flow, the increase in net income and the preservation of capital we offer. As such, our energy sales are focused on reaching these decision makers. Additionally, we have benefited with increased sales and maintenance support through our joint venture, called American DG NY LLC, or ADGNY, with AES-NJ Cogen Co., or AES-NJ, an established developer of small cogeneration systems.

The company is continually expanding its sales efforts by developing joint marketing initiatives with key suppliers to our target industries. Particularly important are our collaborative programs with natural gas utility companies. Since the economic viability of any CHP project is critically dependent upon effective utilization of recovered heat, the insight of the gas supplier to the customer energy profile is particularly effective in prospecting the most cost-effective DG sites in any region.

DG is enjoying growing support among state utility regulators seeking to increase the reliability of electricity supply with cost effective environmentally responsible demand-side resources. New York, New Jersey, Connecticut and Massachusetts are among the states that encourage DG through inter-connecting standards, incentives and/or supply planning. Unlike large central station power plants, DG investments can be made in small increments and with lead-times as short as just a few months.

The U.S. government has been developing and refining various funding opportunities related to its economic recovery or stimulus initiatives. While the final decision has not been determined as of the date of this Annual Report, it appears that “shovel ready” projects related to energy and the environment will hold great prominence. Also, there appears to be interest in upgrading government buildings. The company’s CHP systems would fit very well with any of these programs. Other than funding opportunities related to the economic recovery or stimulus initiatives, there does not appear to be any new government regulations that will affect the company.

Competition

We believe that the main competition for our DG products is the established electric utility infrastructure. DG is beginning to gain acceptance in regions where energy customers are dissatisfied with the cost and reliability of traditional electricity service. These end-users, together with growing support from state legislatures and regulators, are creating a favorable climate for the growth of DG that is overcoming the objections of established utility providers. In our target markets, we compete with large utility companies such as Consolidated Edison in New York City and Westchester County, Long Island Power Authority in Long Island, New York, Public Service Gas and Electric in New Jersey, and NSTAR and National Grid in Massachusetts. Those companies are much larger than us in terms of revenues, assets and resources. We aim to compete with large utility companies by selling electricity to the same commercial building customers. We sell directly to each building customer, but typically only supply 30%-50% of the electricity needs of the building. The remaining portion is supplied by the electric utility. We aim to compete with electric utilities by selling its electricity at a lower price. However, there is no assurance we will be able to provide electricity at a lower price.

Engine manufacturers sell DG units that range in size from a few kW’s to many MW’s in size. Those manufacturers are predominantly greater than 1 MW and include Caterpillar, Cummins, and Waukesha. In many cases, we view these companies as potential suppliers of equipment and not as competitors. For example, we are currently installing a Waukesha unit at a customer site.

The alternative energy market is emerging rapidly. Many companies are developing alternative and renewable energy sources including solar power, wind power, fuel cells and micro-turbines. Some of the companies in this sector include General Electric, BP, Shell, Sun Edison and Evergreen Solar (in the solar energy space); Plug Power and Fuel Cell Energy (in the fuel cell space); and Capstone, Ingersoll Rand and Elliott Turbomachinery (in the micro-turbine space). The effect of these developing technologies on our business is difficult to predict; however, when their technologies become more viable for our target markets, we may be able to adopt their technologies into our business model.

There are a number of energy service companies that offer related services. These companies include Siemens, Honeywell and Johnson Controls. In general, these companies seek large, diverse projects for electric demand reduction for campuses that include building lighting and controls, and electricity (in rare occasions) or cooling. Because of their overhead structures, these companies often solicit large projects and stay away from individual properties. Since we focus on smaller projects for energy supply, we are well suited to work in tandem with these companies when the opportunity arises.

There are also a few local emerging cogeneration developers and contractors that are attempting to offer services similar to ours. To be successful, they will need to have the proper experience in equipment and technology, installation contracting, equipment maintenance and operation, site economic evaluation, project financing and energy sales plus the capability to cover a broad region.

Material Contracts

In January 2006, the company entered into the 2006 Facilities, Support Services and Business Agreement, or the Agreement, with Tecogen, to provide the company with certain office and business support services for a period of one year, renewable annually by mutual agreement. The company also shares personnel support services with Tecogen. The company is allocated its share of the cost of the personnel support services based upon the amount of time spent by such support personnel while working on the company’s behalf. To the extent Tecogen is able to do so under its current plans and policies, Tecogen includes the company and its employees in several of its insurance and benefit programs. The costs of these programs are charged to the company on an actual cost basis. Under this agreement, the company receives pricing based on a volume discount if it purchases cogeneration and chiller products from Tecogen. For certain sites, the company hires Tecogen to service its Tecogen chiller and cogeneration products. Under the current Agreement, as amended, Tecogen provides the company with office space and utilities at a monthly rate of $5,526.

We have sales representation rights to Tecogen’s products and services. In New England, we have exclusive sales representation rights to their cogeneration products. We have granted Tecogen sales representation rights to our On-Site Utility energy service in California.

Government Regulation

We are not subject to extensive government regulation. We are required to file for local construction permits (electrical, mechanical and the like) and utility interconnects, and we must make various local and state filings related to environmental emissions.

Employees

As of December 31, 2009, we employed thirteen active full-time employees and two part-time employees. We believe that our relationship with our employees is satisfactory. None of our employees are represented by a collective bargaining agreement.

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Recent Sales of Unregistered Securities

Set forth below is information regarding common stock issued, warrants issued and stock options granted by the company during fiscal years 2007 through 2009. Also included is the consideration, if any, we received and information relating to the section of the Securities Act of 1933, as amended, or the Securities Act, or rule of the SEC, under which exemption from registration was claimed.

Common Stock and Warrants

On March 8, 2007, the company raised $3,004,505 in a private placement of 4,292,150 shares of common stock at a price of $0.70 per share. The private placement was done exclusively by 10 accredited investors, representing 16.5% of the total shares then outstanding. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Rule 506 of Regulation D.

On April 30, 2007, the company raised $1,120,000 in a private placement of 1,600,000 shares of common stock at a price of $0.70 per share. The private placement was done exclusively by 4 accredited investors, representing 5.2% of the total shares then outstanding. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Rule 506 of Regulation D.

On June 30, 2007, the company issued to a consultant 100,000 shares of common stock through an option exercise at $0.07 per share, representing 0.3% of the total shares then outstanding. The consultant was an accredited investor, and such transaction was exempt from registration under the Securities Act under Section 4(2).

On October 2, 2007, a holder of the company’s 8% Convertible Debenture elected to convert $50,000 of the outstanding principal amount of the debenture into 59,524 shares of common stock. The investor was an accredited investor, and such transaction was exempt from registration under the Securities Act under Section 4(2).

From December 2003 through December 2005, the company raised $2,236,500 through a private placement of common stock and warrants by issuing 3,195,000 shares of common stock and 3,195,000 warrants, at a price of $0.70 per share. Each warrant represents the right to purchase one share of common stock for a period of three years from the date the warrant was issued. The warrant holders started exercising their warrants in 2006. From February 2008 through December 2008, the company raised $707,000 through the exercise of 1,010,000 warrants at a price of $0.70 per share; such warrants were exercised exclusively by 17 accredited investors, representing 3.1% of the total shares then outstanding. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Section 4(2).

In May 2008, two holders of the company’s 8% Convertible Debentures elected to convert $150,000 of the outstanding principal amount of such debentures into 178,572 shares of common stock. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Section 4(2).

On February 24, 2009, the company sold a warrant to purchase shares of the company’s common stock to an accredited investor, for a purchase price of $10,500. The warrant, which expires on February 24, 2012, gives the investor the right but not the obligation to purchase 50,000 shares of the company’s common stock at an exercise price per share of $3.00. The investor was an accredited investor, and such transaction was exempt from registration under the Securities Act under Section 4(2).

On April 23, 2009, the company raised $2,260,000 in a private placement of 1,076,190 shares of common stock at a price of $2.10 per share. The private placement was done exclusively by 5 accredited investors, representing 3.1% of the total shares then outstanding. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Rule 506 of Regulation D.

On July 24, 2009, the company raised $3,492,650 in a private placement of 1,663,167 shares of common stock at a price of $2.10 per share. The company also granted the investors the right to purchase additional shares of common stock at a purchase price of $3.10 per share by December 18, 2009, which as of December 31, 2009, have expired unexercised. The private placement was done exclusively by 22 accredited investors, representing 4.7% of the total shares then outstanding. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Rule 506 of Regulation D.

On October 1, 2009, the company signed an investor relations consulting agreement with Hayden IR for a period of twelve months. In connection with that agreement the company granted Hayden IR a warrant to purchase 12,000 shares of the company’s common stock at an exercise price per share of $2.98, with one-third vesting on October 1, 2009, one-third vesting on February 1, 2010, and one-third vesting on June 1, 2010, provided that at any such vesting date the agreement is still in effect and Hayden IR has provided all required services to the company. The warrants carry a cashless exercise provision and expire on May 30, 2013. The company received no other consideration from the issuance of the warrants. The investor was an accredited investor, and such transaction was exempt from registration under the Securities Act under Section 4(2).

On October 14, 2009, the company raised $525,000 in a private placement of 250,000 shares of common stock at a price of $2.10 per share. The company also granted the investor the right to purchase additional shares of common stock at a purchase price of $3.10 per share by December 18, 2009, which as of December 31, 2009, have expired unexercised. The private placement was done exclusively by an accredited investor, representing 0.7% of the total shares then outstanding. The investor was an accredited investor, and such transaction was exempt from registration under the Securities Act under Section 4(2).

Restricted Stock Grants

On February 20, 2007, the company made restricted stock grants to employees, directors and consultants by permitting them to purchase an aggregate of 737,000 shares of common stock, representing 2.4% of the total shares then outstanding at a price of $0.001 per share. Prior to this transaction the company had 30,309,400 shares of common stock outstanding. Such transaction was exempt from registration under the Securities Act under Section 4(2).

In December 2008, the company made a restricted stock grant to one employee by permitting him to purchase an aggregate of 40,000 shares of common stock, representing 0.1% of the total shares then outstanding at a price of $0.001 per share. Those shares have a vesting schedule of four years. Such transaction was exempt from registration under the Securities Act under Section 4(2).

Stock Options

In 2007 the company granted nonqualified options to purchase 1,156,000 shares of the common stock to 7 employees at $0.90 per share. Of those shares 1,130,000 have a vesting schedule of 10 years and 26,000 shares have a vesting schedule of 4 years. The grant of such options was exempt from registration under Rule 701 under the Securities Act.

In December 2008, the company granted nonqualified options to purchase 100,000 shares of the common stock to one employee at $1.95 per share. Those options have a vesting schedule of 4 years and expire in 10 years. The grant of such options was exempt from registration under Rule 701 under the Securities Act.

In February 2009, the company granted nonqualified options to purchase 13,000 shares of the common stock to three employees at $1.82 per share. Those options have a vesting schedule of 4 years and expire in 5 years. The grant of such options was exempt from registration under Rule 701 under the Securities Act.

In July 2009, the company granted nonqualified options to purchase 6,000 shares of the common stock to one employee at $2.95 per share. Those options have a vesting schedule of 4 years and expire in 5 years. The grant of such options was exempt from registration under Rule 701 under the Securities Act.

No underwriters were involved in the foregoing sales of securities. All purchasers of shares of our convertible debentures and warrants described above represented to us in connection with their purchase that they were accredited investors and made customary investment representations. All of the foregoing securities are deemed restricted securities for purposes of the Securities Act.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. Management believes the following critical accounting policies involve more significant judgments and estimates used in the preparation of our consolidated financial statements.

Partnerships, Joint Ventures and Entities under Common Control

Certain contracts are executed jointly through partnerships and joint ventures with unrelated third parties. The company consolidates all joint ventures and partnerships in which it owns, directly or indirectly, 50% or more of the membership interests. All significant intercompany accounts and transactions are eliminated. Noncontrolling interest in net assets and earnings or losses of consolidated entities are reflected in the caption “Noncontrolling interest” in the accompanying consolidated financial statements. Noncontrolling interest adjusts the consolidated results of operations to reflect only the company’s share of the earnings or losses of the consolidated entities. Upon dilution of ownership below 50%, the accounting method is adjusted to the equity or cost method of accounting, as appropriate.

The company evaluates the applicability of the FASB guidance on variable interest entities to partnerships and joint ventures at the inception of its participation to ensure its accounting is in accordance with the appropriate standards. The company has contractual interests in Tecogen and determined that Tecogen was a Variable Interest Entity, as defined by the applicable guidance; however, the company was not considered the primary beneficiary and does not have any exposure to loss as a result of its involvement with Tecogen. Therefore, Tecogen was not consolidated in our consolidated financial statements through December 31, 2009. See “Note 7 - Related Parties” for further discussion.

The company has a variable interest in Tecogen through its contractual interests in that entity; however, the company is not the primary beneficiary and does not have any exposure to loss as a result of its involvement with Tecogen. See “Note 7 - Related Parties” footnote to the company’s consolidated financial statement for discussion of the company’s involvement with Tecogen.

Related Party Transactions

The company purchases the majority of its cogeneration units from Tecogen Inc., or Tecogen, an affiliate company sharing similar ownership. In addition, Tecogen pays certain operating expenses, including benefits and payroll, on behalf of the company and the company leases office space from Tecogen. These costs were reimbursed by the company. Tecogen has a sublease agreement for the office building, which expires on March 31, 2014.

On February 15, 2007, the company loaned Peter Westerhoff, the non controlling interest partner in ADGNY, $20,000 by signing a two year loan agreement earning interest at 12% per annum. On April 1, 2007, the company loaned an additional $75,000 to the same non controlling partner by signing a two year note agreement earning interest at 12% per annum, and on May 16, 2007, the company loaned an additional $55,000 to the same partner by signing a two year note agreement under the same terms. On October 11, 2007, we extended to our non controlling interest partner a line of credit of $500,000. At December 31, 2008, $265,012 was outstanding and due to the company by the non-controlling interest partner in American DG New York, LLC under the outstanding agreements. In addition there was $31,446 due from GlenRose Instruments Inc., and $959 from Alexandros Partners LLC, for a total of $297,417, which is the amount recorded on the balance sheet as of December 31, 2008. All notes were classified in the Due from related party account in the December 31, 2008 balance sheet and were secured by the partner’s non controlling interest. Effective April 1, 2009 the company reached an agreement with the noncontrolling interest partner in ADGNY to purchase its interest in the Riverpoint location. As a result of this transaction, the company owns 100% of that location and the noncontrolling interest partners’ share of that location was applied to his outstanding debt to the company related to the above mentioned loan agreements and line of credit. Additionally, in 2009 ADGNY financed capital improvements at several projects, which per project agreements was the responsibility of the noncontrolling interest partner. This further reduced the noncontrolling interest partner’s noncontrolling interest in ADGNY. The result of these transactions appears as “Ownership changes to noncontrolling interests” in the amount of $405,714 in the accompanying consolidated statement of stockholder’s equity for the year ended December 31, 2009.

On October 22, 2009, the company signed a five-year exclusive distribution agreement with Ilios Dynamics, a subsidiary of Tecogen. Under terms of the agreement, the company has exclusive rights to incorporate Ilios Dynamics’ ultra high-efficiency heating products in its energy systems throughout the European Union and New England. The company also has non-exclusive rights to distribute Ilios Dynamics’ product in the remaining parts of the United States and the world in cases where the company retains ownership of the equipment for its On-Site Utility business.

During the quarter ended September 30, 2009, the non-controlling interest partner in ADGNY, a related party, purchased certain units and supporting equipment from the company for $370,400. That amount, as of December 31, 2009, was classified as “Due from related party” in the accompanying balance sheet. The cost of the units and supporting equipment was $208,225 and the company booked a profit of $162,175.

On December 17, 2009, the company entered into a revolving line of credit agreement, or the agreement, with John N. Hatsopoulos, the company’s Chief Executive Officer. Under the terms of the agreement, during the period extending to December 31, 2012, Mr. Hatsopoulos will lend to the company on a revolving line of credit basis a principal amount up to $5,000,000. All sums advanced pursuant to this agreement shall bear interest from the date each advance is made until paid in full at the Bank Prime Rate as quoted from time to time in the Wall Street Journal plus 1.5% per year. Interest shall be due and payable quarterly in arrears and prepayment of principal, together with accrued interest, may be made at any time without penalty. Also, under the terms of the agreement, the credit line from Mr. Hatsopoulos will be used solely in connection with the development and installation of current and new energy systems such as cogeneration systems and chillers and not for general corporate purposes including operational expenses such as payroll, maintenance, travel, entertainment, or sales and marketing. As of December 31, 2009, the company has not drawn funds on this line of credit.

The company’s Chief Financial Officer devotes approximately half of his business time to the affairs of GlenRose Instruments Inc., and 50% of his salary is reimbursed by GlenRose Instruments Inc. Also, the company’s Chief Executive Officer is the Chairman of the Board and a significant investor in GlenRose and does not receive a salary, bonus or any other compensation from GlenRose.

Property and Equipment and Depreciation and Amortization

Property and equipment are stated at cost. Depreciation and amortization are computed using the straight-line method at rates sufficient to write off the cost of the applicable assets over their estimated useful lives. Repairs and maintenance are expensed as incurred.

The company evaluates the recoverability of its long-lived assets by comparing the net book value of the assets to the estimated future undiscounted cash flows attributable to such assets. The useful life of the company’s energy systems is lesser of the economic life of the asset or the term of the underlying contract with the customer, typically 12 to 15 years. The company reviews the useful life of its energy systems on a quarterly basis or whenever events or changes in business circumstances indicate that the carrying value of the assets may not be fully recoverable or that the useful lives of the assets are no longer appropriate. If impairment is indicated, the asset is written down to its estimated fair value based on a discounted cash flow analysis. There have been no revisions to the useful lives of the company’s assets at June 30, 2010 and December 31, 2009, respectively, and the company has determined that its long-lived assets for those periods are recoverable.

The company receives rebates and incentives from various utility companies which are accounted for as a reduction in the book value of the assets. The rebates are payable from the utility to the company and are applied against the cost of construction, therefore reducing the book value of the installation. As a reduction of the facility construction costs, these rebates are treated as an investing activity in the statement of cash flows. When the rebates are a function of production of the DG unit, they are recorded as income over the period of production and treated in the statement of cash flows as an operating activity. The rebates the company receives from the utilities that apply to the cost of construction are one time rebates based on the installed cost, capacity and thermal efficiency of installed unit and are earned upon the installation and inspection by the utility and not related to or subject to adjustment based on the future operating performance of the installed unit. The rebate agreements with utilities are based on standard terms and conditions, the most significant being customer eligibility and post-installation work verification by a specific date. The only rebates that the company has recognized historically on the income statement are related to the company’s participation in demand response programs and are recognized only upon the occurrence of curtailed events of the applicable units. The cumulative amount of rebates applied to the cost of construction was $534,308 and $319,655 as of December 31, 2009 and 2008, respectively. The revenue recognized from demand response activity was $17,830 and $11,176 for the years ended December 31, 2009 and 2008, respectively.

The company operates on-site energy systems that produce electricity, hot water, heat and cooling. The energy systems are capable of meeting the demands of commercial users and can be connected to the existing utility grid. There is not always enough power generation available from the utilities to meet peak demand, and existing transmission lines cannot carry all of the electricity needed by consumers. The utility companies recognize that the energy systems we install lessen the demand on the grid. Therefore, they offer a one-time rebate/incentive payment to the company based on the kW size or the unit installed. That rebate/incentive is payable from the utility to the company upon commencement of operation at the facility and is applied against the cost of construction, therefore reducing the book value of the installation. As a reduction of our facility construction costs, this type of rebate is treated as an investing activity in the statement of cash flows. When the rebate/incentive is a function of production of the DG unit, it is recorded as income over the period of production and treated in the statement of cash flows as an operating activity.

Stock Based Compensation

Stock based compensation cost is measured at the grant date based on the estimated fair value of the award and is recognized as an expense in the statement of operations over the requisite service period. The fair value of stock options granted is estimated using the Black-Scholes option pricing valuation model. The company recognizes compensation on a straight-line basis for each separately vesting portion of the option award. Use of a valuation model requires management to make certain assumptions with respect to selected model inputs. Expected volatility is calculated based on the average volatility of 20 companies in the same industry as the company. The average expected life is estimated using the simplified method for “plain vanilla” options. The expected life in years is based on the “simplified” method. The simplified method determines the expected life in years based on the vesting period and contractual terms as set forth when the award is made. The company uses the simplified method for awards of stock-based compensation since it does not have the necessary historical exercise and forfeiture data to determine an expected life for stock options. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term which approximates the expected life assumed at the date of grant. When options are exercised the company normally issues new shares.

Revenue Recognition

Revenue from energy contracts is recognized when electricity, heat, and chilled water is produced by the cogeneration systems on-site. The company bills each month based on various meter readings installed at each site. The amount of energy produced by on-site energy systems is invoiced, as determined by a contractually defined formula. Under certain energy contracts, the customer directly acquires the fuel to power the systems and receives credit for that expense from the company. The credit is recorded as revenue and cost of fuel.

As a by-product of the energy business, in some cases, the customer may choose to have the company construct the system for them rather than have it owned by American DG Energy. In this case, the company accounts for revenue, or turnkey revenue, and costs using the percentage-of-completion method of accounting. Under the percentage-of-completion method of accounting, revenues are recognized by applying percentages of completion to the total estimated revenues for the respective contracts. Costs are recognized as incurred. The percentages of completion are determined by relating the actual cost of work performed to date to the current estimated total cost at completion of the respective contracts. When the estimate on a contract indicates a loss, the company’s policy is to record the entire expected loss, regardless of the percentage of completion. The excess of contract costs and profit recognized to date on the percentage-of-completion accounting method in excess of billings is recorded as unbilled revenue. Billings in excess of related costs and estimated earnings is recorded as deferred revenue.

Customers may buy out their long-term obligation under energy contracts and purchase the underlying equipment from the company. Any resulting gain on these transactions is recognized over the payment period in the accompanying consolidated statements of operations. Revenues from operation, including shared savings are recorded when provided and verified. Maintenance service revenue is recognized over the term of the agreement and is billed on a monthly basis in arrears.

Occasionally the company will enter into a sales arrangement with a customer to construct and sell an energy system and provide energy and maintenance services over the term of the contract. Based on the fact that the company sells each deliverable to other customers on a stand-alone basis, the company has determined that each deliverable has a stand-alone value. Additionally, there are no rights of return relative to the delivered items; therefore, each deliverable is considered a separate unit of accounting. Revenue is allocated to each element based upon its relative fair value which is determined based on the price of the deliverables when sold on a standalone basis. Revenue related to the construction of the energy system is recognized using the percentage-of-completion method as the unit is being constructed. Revenue from the sale of energy is recognized when electricity, heat, and chilled water is produced by the energy system, and revenue from maintenance services is recognized over the term of the maintenance agreement. The company had no such sales arrangements in fiscal year 2009.

Other revenue represents various types of ancillary activities for which the company engages from time to time such as demand response incentives, the sale of equipment, and feasibility studies.

Income Taxes

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves us estimating our actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation and certain accrued liabilities for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within our consolidated balance sheet. We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and to the extent we believe that recovery is not likely, we must establish a valuation allowance.

Significant management judgment is required in determining our provision for income taxes, our deferred tax assets and liabilities and any valuation allowance recorded against our deferred tax assets. As of December 31, 2009, there was no deferred income tax asset on our books. We recorded a valuation allowance of $4,224,000 against the entire gross deferred income tax asset due to uncertainties related to our ability to utilize our net operating loss carry forwards before they expire. The valuation allowance is based on our estimates of taxable income by jurisdiction in which we operate and the period over which our deferred tax assets will be recoverable. In the event that actual results differ from these estimates or we adjust these estimates in future periods, we may need to establish an additional valuation allowance which could materially impact our financial position and results of operations.

Reclassifications

All prior period information presented in this Amendment has been restated to separately present revenues of energy, and turnkey and other revenues. The reclassification had no effect on previously reported net loss, stockholder’s equity or cash flows.

Results of Operations for the Years Ended December 31, 2009 and December 31, 2008

Fiscal 2009 Compared with Fiscal 2008

Revenues

Revenues in 2009 were $5,763,827 compared to $6,579,437 for the same period in 2008, a decrease of $815,610 or 12.4%. The decrease in revenue was due to a decrease in our turn-key installation projects that in 2009 decreased to $1,130,839 compared to $1,434,932, for the same period in 2008, and our On-Site Utility energy revenues that in 2009 decreased to $4,632,988 compared to $5,144,505 for the same period in 2008, a decrease of 9.9%. The decrease in our turn-key installation projects revenue was caused by the construction of fewer projects. The decrease in our core On-Site Utility energy revenues was primarily caused by significantly lower natural gas prices in our existing markets which translated into lower hot water revenue.

Our energy revenue is impacted by, among other things: the number of energy systems operating over the period, the amount energy of produced by the energy systems (which are impacted by the energy needs of the customer, the local weather which may require the customer to require more or less energy, the maintenance needs of the energy systems, and the operating performance of the energy systems), and the price of electricity, natural gas and oil paid by our customers to their local utility that the company uses to then price our energy. Our energy agreements are typically long-term contracts (typically 12 to 15 years) and are billed monthly to our customers. Because of the foregoing factors, the revenue from our turn-key projects can substantially vary per period. While the company accepts turn-key installation projects, they are not considered our core business.

During 2009, we were operating 62 energy systems at 36 locations in the Northeast, representing 4,210 kW of installed electricity plus thermal energy, compared to 56 energy systems at 30 locations, representing 4,240 kW of installed electricity plus thermal energy for the same period in 2008. Our revenues per customer on a monthly basis is based on the sum of the amount of energy produced by our energy systems and the published price of energy (electricity, natural gas or oil) from our customers’ local energy utility that month less the discounts we provide our customers. Our revenues commence as new energy systems become operational.

Cost of Sales

Cost of sales, including depreciation, in 2009 were $4,677,323 compared to $5,733,175 for the same period in 2008, a decrease of $1,055,852 or 18.4%. Included in the cost of sales was depreciation expense of $788,885 in 2009, compared to $596,915 for the same period in 2008. Our cost of sales for our core On-Site Utility business consists primarily of fuel required to operate our energy systems that decreased by 9% as a percentage of revenue in 2009, compared to the same period in 2008. Our cost of sales also includes the cost of maintenance of our systems which increased by 5% as a percentage of revenue in 2009, compared to the same period in 2008. During 2009, our gross margins were 18.9% compared to 12.9% for the same period in 2008, primarily due to lower cost of natural gas which is the majority of our cost of goods. Our On-Site Utility energy margins excluding depreciation were 31.4% in 2009 compared to 27.7% for the same period in 2008.

Operating Expenses

Our general and administrative expenses consist of executive staff, accounting and legal expenses, office space, general insurance and other administrative expenses. Our general and administrative expenses in 2009 were $1,546,743 compared to $1,504,968 for the same period in 2008, an increase of $41,775 or 2.8%. Those expenses include non-cash compensation expense related to the issuance of restricted stock and option awards to our employees and an expense of $76,875 for original listing fees to the NYSE Amex.

Our selling expenses consist of sales staff, commissions, marketing, travel and other selling related expenses including provisions for bad debt write-offs. We sell energy using both direct sales and commissioned agents. Our marketing efforts consisted of trade shows, print literature, media relations and event driven direct mail. Our selling expenses in 2009 were $850,975 compared to $533,874 for the same period in 2008, an increase of $317,101 or 59.4%. The increase in our selling expenses was primarily due to the addition of a new salesperson, the additional commission paid to our outside sales agents and an increase in bad debt expense related to three of our On-Site Utility sites.

Our engineering expenses consisted of technical staff and other engineering related expenses. The role of engineering is to evaluate potential customer sites based on technical and economic feasibility, manage the installed base of energy systems and oversee each new installation project. Our engineering expenses in 2009 were $642,858 compared to $401,361 for the same period in 2008, an increase of $241,497 or 60.2%. The increase in our engineering expenses was primarily due to the addition of an engineer and travel expenses to our energy sites.

Loss from Operations

The loss from operations in 2009 was $1,954,072 compared to $1,593,941for the same period in 2008. The increase in the operating loss was affected by higher operating expenses. Our non-cash compensation expense related to the issuance of restricted stock and option awards to our employees was $286,844 in 2009, compared to $364,231 for the same period in 2008.

Other Income (Expense), Net

Our other income (expense), net, in 2009 was $366,359 compared to $334,717 for the same period in 2008. Other income (expense), net, includes interest income, interest expense and other items. Interest and other income was $71,185 in 2009 compared to $139,690 for the same period in 2008. The decrease was primarily due to lower yields on our invested funds. Interest expense was $437,544 in 2009 compared to $474,407 for the same period in 2008, due to less interest paid on our convertible debenture issued in 2006 because of conversions.

Provision for Income Taxes

Our provision for state income taxes in 2009 was $7,450 compared to $34,087 for the same period in 2008. No benefit for Federal taxes to the company’s losses has been provided in either period.

Noncontrolling Interest

The noncontrolling interest share in the profits in ADGNY was $202,684 in 2009 compared to $305,336 for the same period in 2008. The decrease in non-controlling interest is due to the overall decrease in joint venture volume and profits and due to changes in the ownership structure of underlying sites. In 2009, the company made a distribution of $333,704 to the noncontrolling interest partner based on his interest percent ownership in each site.

Liquidity and Capital Resources

Consolidated working capital at December 31, 2009 was $4,132,378, compared to $3,477,991 at December 31, 2008. Included in working capital were cash, cash equivalents and short-term investments of $3,828,143 at December 31, 2009, compared to $2,445,112 at December 31, 2008. The increase in working capital was a result of additional funds raised during the year, offset by cash needed to fund operations.

Cash used by operating activities was $648,816 in 2009 compared to $1,227,183 for the same period in 2008. The company's short and long-term receivables balance, including unbilled revenue, decreased to $665,319, in 2009 compared to $1,046,319 at December 31, 2008, providing $381,000 of cash. The decrease was due to reduced revenue during the year. Amount due to the company from related parties, increased to $370,400 in 2009 compared to $297,417 at December 31, 2008, using $72,983 of cash. The increase was due to an increase in debt by our noncontrolling interest partner as a result of purchased certain units and supporting equipment from the company. Our inventory increased to $379,303 in 2009 compared to 355,852 at December 31, 2008, using $23,451 of cash. Our prepaid and other current assets decreased to $104,119 in 2009 compared to $163,121 at December 31, 2008, providing $59,002 of cash.

Accounts payable increased to $740,474 in 2009, compared to $270,852 at December 31, 2008, providing $469,622 of cash. The increase in accounts payable was a result of having five sites under construction representing 725 kW on December 31, 2009, compared to two sites at December 31, 2008 representing 150 kW. The accounts payable amount of $740,474 includes $455,167 related to construction-in-process that was higher in 2009 due to increase in construction projects. Our accrued expenses and other current liabilities including accrued interest expense increased to $453,536 in 2009 compared to $384,340 at December 31, 2008, providing $69,196 of cash, offset by an accrual of $106,400 for future interest payments. Our due to related party decreased to $17,531 in 2009, compared to $166,560 at December 31, 2008, using $149,029 of cash.

During 2009, the primary investing activities of the company’s operations were expenditures for the purchase of property, plant and equipment for the company's energy system installations. The company used $4,171,867 for purchases and installation of energy systems and received $232,483 in rebates and incentives. The company’s short-term investments provided $82,693 of cash as our funds invested in certificates of deposits matured and converted into cash. The company's financing activities provided $5,971,231 of cash in 2009 from the sale of common stock, exercise of common stock warrants and stock options, offset by distributions to our noncontrolling interest partner and payments on capital lease obligations.

At December 31, 2009, the company’s commitments included a lease for a plotter with a remaining balance of $22,348 and a rental commitment. The source of funds to fulfill those commitments will be provided from either the company’s existing line of credit agreement or through debt or equity financings.

The company’s On-Site Utility energy program allows customers to reduce both their energy costs and site carbon production by deploying CHP technology on its customers’ premises at no cost. Therefore the company is capital intensive. The company believes that its existing resources, including cash and cash equivalents and future cash flow from operations, are sufficient to meet the working capital requirements of its existing business for the foreseeable future, including the next 12 months. We believe that our cash and cash equivalents and our ability to control certain costs, including those related to general and administrative expenses, will enable us to meet our anticipated cash expenditures through the end of 2010. Beyond January 1, 2011, as we continue to grow our business by adding more energy systems, our cash requirements will increase. We may need to raise additional capital through a debt financing or an equity offering to meet our operating and capital needs for future growth.

Our ability to continue to access capital could be impacted by various factors including general market conditions and the continuing slowdown in the economy, interest rates, the perception of our potential future earnings and cash distributions, any unwillingness on the part of lenders to make loans to us and any deterioration in the financial position of lenders that might make them unable to meet their obligations to us. If these conditions continue and we cannot raise funds through a public or private debt financing, or an equity offering, our ability to grow our business may be negatively affected. In such case, the company may need to suspend any new installation of energy systems and significantly reduce its operating costs until market conditions improve.

Item 9A(T). Controls and Procedures.

Management’s Evaluation of Disclosure Controls and Procedures:

Our disclosure controls and procedures are designed to provide reasonable assurance that the control system’s objectives will be met. Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, or the Evaluation Date, have concluded that as of the Evaluation Date, our disclosure controls and procedures were not effective due to material weakness in financial reporting relating to lack of personnel with a sufficient level of accounting knowledge and a small number of employees dealing with general controls over information technology.

For these purposes, the term disclosure controls and procedures of an issuer means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Item 10. Directors, Executive Officers and Corporate Governance.

Executive Officers and Directors

Anthony S. Loumidis has been our Chief Financial Officer since 2004 and our Treasurer since 2001. Mr. Loumidis devotes approximately half of his business time to the affairs of the company. He has been the Chief Financial Officer of GlenRose Instruments Inc., since 2006; GlenRose Instruments provides analytical services to the federal government and its prime contractors. He has also been the Vice President and Treasurer of Tecogen Inc., an affiliate of the company, since 2001; Tecogen is a manufacturer of natural gas, engine-driven commercial and industrial cooling and cogeneration systems. He also has been a Partner and President of Alexandros Partners LLC since 2000; Alexandros Partners is a financial advisory firm providing consulting services to early stage entrepreneurial ventures, and he is Treasurer of Ilios Inc., an affiliate of the company, a high-efficiency heating products company. Mr. Loumidis was previously with Thermo Electron Corporation, which is now Thermo Fisher Scientific (NYSE: TMO), where he held various positions including National Sales Manager for Thermo Capital Financial Services, Manager of Investor Relations and Manager of Business Development of Tecomet, a subsidiary of Thermo Electron. Mr. Loumidis is a FINRA registered representative, holds a bachelor’s degree in business administration from the American College of Greece in Athens and a master’s degree in business administration from Northeastern University.

Director Nomination Process

The Nominating and Governance Committee will consider recommendations for candidates to the Board from stockholders holding no less than 2% of the outstanding shares of the company’s voting securities continuously for at least 12 months prior to the date of the submission of the recommendation for nomination. A stockholder that desires to recommend a candidate for election to the Board shall direct the recommendation in writing to American DG Energy Inc., attention: Corporate Secretary, 45 First Avenue, Waltham, Massachusetts, 02451, and must include the candidate’s name, home and business contact information, detailed biographical data and qualifications, information regarding any relationships between the candidate and the company within the last three years and evidence of the nominating person’s ownership of company stock, a statement from the recommending stockholder in support of the candidate, references, particularly within the context of the criteria for Board membership, including issues of character, diversity, skills, judgment, age, independence, industry experience, expertise, corporate experience, length of service, other commitments and the like, and a written indication by the candidate of her/his willingness to serve, if elected.

The Nominating Committee seeks to nominate director candidates who bring diverse experiences and perspectives to our Board. In evaluating candidates, the Nominating Committee’s practice is to consider, among other things, diversity with respect to business experiences, the candidate’s range of experiences with public companies, diversity of gender, race and national origin, education and differences in viewpoints and skills. The Nominating Committee has not formalized this practice into a written policy. Evaluations of potential candidates generally involve a review of the candidate’s background and credentials by the Nominating Committee, interviews with members of the Board/Nominating Committee, the Board/Nominating Committee as a whole, or one or more other Board/Nominating Committee members, and discussions of the Nominating Committee and the Board.

The Nominating and Governance Committees have assessed our practices with respect to diversity to be effective, in that our practices encourage consideration of a wide range of factors that are relevant to a candidate’s value to our Board, while providing our Nominating Committee with flexibility in the director search and nomination process.

The Nominating and Governance Committee has not formally adopted any specific, minimum qualifications that must be met by each candidate for the Board, nor are there specific qualities or skills that are necessary for one or more of the members of the Board to possess. The Nominating and Governance Committee believes that candidates and nominees must reflect a Board that is comprised of directors who (i) are predominantly independent, (ii) are of high integrity, (iii) have or have had experience in positions with a high degree of responsibility, (iv) are or were leaders in the companies or institutions with which they are or were affiliated, (v) have qualifications that will increase overall Board effectiveness and (vi) meet other requirements as may be required by applicable rules, such as financial literacy or financial expertise with respect to Audit Committee members. In order to identify and evaluate nominees for director, the Nominating and Governance Committee regularly reviews the current composition and size of the Board, reviews qualifications of nominees, evaluates the performance of the Board as a whole, evaluates the performance and qualifications of individual members of the Board eligible for re-election at the annual meeting of stockholders, considers such factors as: character; diversity; skills; judgment; age; independence; industry experience; expertise; corporate experience; length of service; other commitments and the like; and the general needs of the Board, including applicable independence requirements. The Nominating and Governance Committee considers each individual candidate in the context of the current perceived needs of the Board as a whole. The Nominating and Governance Committee uses the same process for evaluating all nominees, regardless of the original source of the nomination. All of the members of the Board participate in the consideration of director nominations.

Board Leadership Structure

We separate the roles of Chief Executive Officer and Chairman of the Board in recognition of the differences between the two roles. The CEO is responsible for setting the strategic direction for the company and the day to day leadership and performance of the company, while the Chairman of the Board provides guidance to the CEO and sets the agenda for Board meetings and presides over meetings of the full Board.

Our Chairman, Dr. George N. Hatsopoulos is the founder and chairman emeritus of Thermo Electron Corporation, which is now Thermo Fisher Scientific (NYSE: TMO), he has served on the board of the Federal Reserve Bank of Boston, including a term as chairman. He was a member of the Securities and Exchange Commission Advisory Committee on Capital Formation and Regulatory Process, the Advisory Committee of the U.S. Export-Import Bank, and the boards of various corporations and institutions. In 1996, Dr. Hatsopoulos won the John Fritz Medal, which is the highest American award in the engineering profession and presented each year for scientific or industrial achievement in any field of pure or applied science. In 1997 he was awarded the 3rd Annual Heinz Award in Technology, the Economy and Employment. Dr. Hatsopoulos provides “high-level” guidance to our Chief Executive Officer, John N. Hatsopoulos, his brother, in the field of engineering, science, thermodynamics and thermionic energy conversion, which is the basis of our combined heat and power system. Our Chief Executive Officer, John Hatsopoulos, has a background in operations and finance and is responsible for setting the strategic direction for the company and the overall leadership and performance of the company. The Chairman’s role includes high level supervision over the strategic direction of the company, which is the primary responsibility of the Chief Executive Officer. In our case, we have two highly experienced and distinguished individuals performing distinct high level supervisory and executive functions for the company.

Item 11. Executive Compensation.

The following table sets forth the compensation of our named executive officers, which consist of our chief executive officer and by other executive officers during the fiscal year ended December 31, 2009.

SUMMARY COMPENSATION TABLE

						Stock		Option		All other
Name and principal position	Year	Salary ($)		Bonus ($)		awards ($)		awards ($)		compensation ($)			Total ($)

John N. Hatsopoulos (1)	2009		-		-		-		-		-			-
Chief Executive Officer	2008		-		-		-		-		-			-

Barry J. Sanders	2009		205,430		-		-		-		372	(2)		205,802
President and Chief Operating Officer	2008		175,430		-		-		-		372	(2)		175,802

Anthony S. Loumidis (3)	2009		175,680		-		-		-		372	(2)		176,052
Chief Financial Officer and Treasurer	2008		160,680		-		-		-		372	(2)		161,052

(1)

John N. Hatsopoulos did not receive a salary, bonus or any other compensation in 2008 or 2009, and will not receive a salary, bonus or any other compensation in 2010.

(2)

Includes group life insurance of $372.

(3)

Anthony S. Loumidis devotes approximately half of his business time to the affairs of GlenRose Instruments Inc., and 50% of his salary is reimbursed by GlenRose Instruments Inc..

Employment Contracts and Termination of Employment and Change-in-Control Arrangements

None of our executive officers has an employment contract or change-in-control arrangement, other than stock and option awards that contain certain change-in-control provisions such as accelerated vesting due to acquisition. In the event an acquisition that is not a private transaction occurs while the optionee maintains a business relationship with the company and the option has not fully vested, the option will become exercisable for 100% of the then number of shares as to which it has not vested and such vesting to occur immediately prior to the closing of the acquisition.

The stock and option awards that would vest for each named executive if a change-in control were to occur are disclosed under our Outstanding Equity Awards at Fiscal Year-End Table. Specifically, as of April 30, 2010, Barry J. Sanders had 504,000 stock options and 117,500 shares of restricted stock that had not vested and Anthony S. Loumidis had 175,000 stock options and 27,500 shares of restricted stock that had not vested.

Our stock and option awards contain certain change-in-control provisions. Descriptions of those provisions are set forth below:

Stock Awards Change in Control Definition

Change in Control shall mean (a) the acquisition in a transaction or series of transactions by any person (such term to include anyone deemed a person under Section 13(d)(3) of the Exchange Act), other than the company or any of its subsidiaries, or any employee benefit plan or related trust of the company or any of its subsidiaries, of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of fifty percent (50%) or more of the combined voting power of the then outstanding voting securities of the company entitled to vote generally in the election of directors; provided a Change in Control shall not occur solely as the result of an Initial Public Offering or (b) the sale or other disposition of all or substantially all of the assets of the company in one transaction or series of related transactions.

Option Awards Change in Control Definition

Accelerated vesting due to acquisition. In the event an acquisition that is not a private transaction occurs while the optionee maintains a business relationship with the company and this option has not fully vested, this option shall become exercisable for 100% of the then number of Shares as to which it has not vested, such vesting to occur immediately prior to the closing of the Acquisition.

Definitions. The following definitions shall apply: Acquisition means (i) the sale of the company by merger in which the shareholders of the company in their capacity as such no longer own a majority of the outstanding equity securities of the company (or its successor); or (ii) any sale of all or substantially all of the assets or capital stock of the company (other than in a spin-off or similar transaction) or (iii) any other acquisition of the business of the company, as determined by the Board. Business relationship means service to the company or its successor in the capacity of an employee, officer, director or consultant. Private transaction” means any acquisition where the consideration received or retained by the holders of the then outstanding capital stock of the company does not consist of (i) cash or cash equivalent consideration, (ii) securities which are registered under the Securities the Securities Act of 1933, as amended, or any successor statute and/or (iii) securities for which the company or any other issuer thereof has agreed, including pursuant to a demand, to file a registration statement within ninety (90) days of completion of the transaction for resale to the public pursuant to the Securities Act of 1933, as amended.

Item 15. Exhibits and Financial Statement Schedules.

(a)	Index To Financial Statements and Financial Statements Schedules:

Report of Independent Registered Public Accounting Firm Caturano and Company, INC. as of March 31, 2010

Consolidated Balance Sheets as of December 31, 2009 and December 31, 2008

Consolidated Statements of Operations for the years ended December 31, 2009 and December 31, 2008

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2009 and December 31, 2008

Consolidated Statements of Cash Flows for the years ended December 31, 2009 and December 31, 2008

Notes to Consolidated Financial Statements

All other schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions, or are inapplicable, and therefore have been omitted.

(b)

Exhibits

Exhibit
Number		Description

99.1		Audit Committee Charter, as amended October 13, 2009 (incorporated by reference to exhibit 10.1 to registrant’s Form S-3, as amended, originally filed with the SEC on December 23, 2009).

99.2		Compensation Committee Charter (incorporated by reference to exhibit 10.2 to registrant’s Form 10-SB, as amended, originally filed with the SEC on November 2, 2006).

99.3		Nominating and Governance Committee Charter dated August 31, 2009 (incorporated by reference to Exhibit 10.3 to registrant’s Form S-3, as amended, originally filed with the SEC on December 23, 2009).

99.4		Slide show presentation (incorporated by reference to Exhibit 99.1 to registrant’s Current Report on Form 8-K, originally filed with the SEC on December 9, 2009).

23.2#		Consent of Caturano and Company, INC.

31.1#		Rule 13a-14(a) Certification of Chief Executive Officer.

31.2#		Rule 13a-14(a) Certification of Chief Financial Officer.

32.1*		Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.

#	Filed herewith.
*	Furnished herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	AMERICAN DG ENERGY INC.
	(Registrant)

	By:	/s/ JOHN N. HATSOPOULOS
	Chief Executive Officer
	(Principal Executive Officer)

	By:	/s/ ANTHONY S. LOUMIDIS
	Chief Financial Officer
	(Principal Financial 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 capacity and on the dates indicated.

Signature	Title	Date

/s/ George N. Hatsopoulos	Chairman of the Board	September 17, 2010
George N. Hatsopoulos

/s/ John N. Hatsopoulos	Chief Executive Officer (Principal Executive Officer)	September 17, 2010
John N. Hatsopoulos	& Director

/s/ Anthony S. Loumidis	Chief Financial Officer (Principal Financial	September 17, 2010
Anthony S. Loumidis	and Accounting Officer)

/s/ Earl R. Lewis	Director	September 17, 2010
Earl R. Lewis

/s/ Charles T. Maxwell	Director	September 17, 2010
Charles T. Maxwell

/s/ Deanna M. Petersen	Director	September 17, 2010
Deanna M. Petersen

/s/ Francis A. Mlynarczyk	Director	September 17, 2010
Francis A. Mlynarczyk

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

American DG Energy Inc. and subsidiaries:

We have audited the accompanying consolidated balance sheets of American DG Energy Inc. and subsidiaries (collectively, the “Company”) as of December 31, 2009 and December 31, 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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 financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 the Company at December 31, 2009, and December 31, 2008, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2009, the Company retrospectively adopted the presentation and disclosure requirements of the Financial Accounting Standards Board Statement No. 160 “Non-Controlling Interests in Consolidated Financial Statements, an amendment of ARB No.51” which is codified in Accounting Standards Codification 810.

/s/ CATURANO AND COMPANY, INC.

Boston, Massachusetts
September 17, 2010

F-1

AMERICAN DG ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009			2008

ASSETS
Current assets:
Cash and cash equivalents	$	3,149,222		$	1,683,498
Short-term investments		678,921			761,614
Accounts receivable, net		518,379			835,922
Unbilled revenue		146,940			204,750
Due from related party		370,400			297,417
Inventory		379,303			355,852
Prepaid and other current assets		104,119			163,121
Total current assets		5,347,284			4,302,174

Property, plant and equipment, net		9,502,346			6,627,540

Accounts receivable, long- term		-			5,647
TOTAL ASSETS		14,849,630			10,935,361

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable		740,474			270,852
Accrued expenses and other current liabilities		453,536			384,340
Due to related party		17,531			166,560
Capital lease obligations		3,365			2,431
Total current liabilities		1,214,906			824,183

Long-term liabilities:
Convertible debentures		5,320,000			5,875,000
Capital lease obligations, long-term		10,095			14,394
Total liabilities		6,545,001			6,713,577

Stockholders’ equity:
American DG Energy Inc. shareholders' equity:
Common stock, $0.001 par value; 100,000,000 shares authorized; 37,676,817 and 34,034,496 issued and outstanding at December 31, 2009 and December 31, 2008, respectively		37,677			34,034
Additional paid- in- capital		19,725,793			12,614,332
Common stock subscription		-			(35,040	)
Accumulated deficit		(12,239,110	)		(9,708,545	)
Total American DG Energy Inc. stockholders' equity		7,524,360			2,904,781
Noncontrolling interest		780,269			1,317,003
Total stockholders' equity		8,304,629			4,221,784

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	14,849,630		$	10,935,361

See accompanying notes to consolidated financial statements

F-2

AMERICAN DG ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	December 31,
	2009			2008

Revenues
Energy revenues	$	4,632,988		$	5,144,505
Turnkey & other revenues		1,130,839			1,434,932
		5,763,827			6,579,437
Cost of sales
Fuel, maintenance and installation		3,888,438			5,136,260
Depreciation expense		788,885			596,915
		4,677,323			5,733,175
Gross profit		1,086,504			846,262

Operating expenses
General and administrative		1,546,743			1,504,968
Selling		850,975			533,874
Engineering		642,858			401,361
		3,040,576			2,440,203
Loss from operations		(1,954,072	)		(1,593,941	)

Other income (expense)
Interest and other income		71,185			139,690
Interest expense		(437,544	)		(474,407	)
		(366,359	)		(334,717	)

Loss, before income taxes		(2,320,431	)		(1,928,658	)
Provision for state income taxes		(7,450	)		(34,087	)
Consolidated net loss		(2,327,881	)		(1,962,745	)
					-
Less: Income attributable to the noncontrolling interest		(202,684	)		(305,336	)
Net loss attributable to American DG Energy Inc.		(2,530,565	)		(2,268,081	)

Net loss per share - basic and diluted	$	(0.07	)	$	(0.07	)

Weighted average shares outstanding - basic and diluted		35,554,303			32,872,006

See accompanying notes to consolidated financial statements

F-3

AMERICAN DG ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

				American DG Energy Inc. Shareholders
							Common
							Stock			Common			Additional
				Accumulated			$0.001			Stock			Paid-In		Noncontrolling
	Total			Deficit			Par Value			Subscription			Capital		Interest

Balance at December 31, 2007	$	5,045,417		$	(7,440,464	)	$	32,806		$	-		$	11,394,289	$	1,058,786
Distributions to noncontrolling interest		(47,119	)		-			-			-			-		(47,119	)
Conversion of convertible debenture to common stock		150,000			-			178			-			149,822		-
Issuance of restricted stock		-			-			40			(40	)		-		-
Stock based compensation expense		364,231			-			-			-			364,231		-
Exercise of warrants		672,000			-			1,010			(35,000	)		705,990		-
Net loss		(1,962,745	)		(2,268,081	)		-			-			-		305,336
Balance at December 31, 2008		4,221,784			(9,708,545	)		34,034			(35,040	)		12,614,332		1,317,003

Distributions to noncontrolling interest		(333,704	)		-			-			-			-		(333,704	)
Ownership changes to noncontrolling interest, Note 7		(405,714	)		-			-			-			-		(405,714	)
Conversion of convertible debenture to common stock		555,000			-			661			-			554,339		-
Issuance of restricted stock		40			-			-			40			-		-
Cancellation of restricted stock		(40	)		-			(40	)		-			-		-
Sale of common stock, net of costs		5,878,079			-			2,991			-			5,875,088		-
Issuance of common stock warrants		372,815			-			-			-			372,815		-
Stock based compensation expense		286,844			-			-			-			286,844		-
Exercise of stock options		22,406			-			31			-			22,375		-
Exercise of warrants		35,000			-			-			35,000			-		-
Net (loss) income		(2,327,881	)		(2,530,565	)		-			-			-		202,684
Balance at December 31, 2009	$	8,304,629		$	(12,239,110	)	$	37,677		$	-		$	19,725,793	$	780,269

See accompanying notes to consolidated financial statements

F-4

AMERICAN DG ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(2,530,565	)	$	(2,268,081	)
Income attributable to noncontrolling interest		202,684			305,336
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization		806,776			604,525
Provision for losses on accounts receivable		299,994			51,759
Amortization of deferred financing costs		8,526			8,526
Stock-based compensation		286,844			364,231

Changes in operating assets and liabilities
(Increase) decrease in:
Accounts receivable		168,294			(330,849	)
Due from related party		(308,183	)		272,957
Inventory		(23,451	)		(269,714	)
Prepaid assets		50,476			(93,794	)
Increase (decrease) in:
Accounts payable		469,622			(83,239	)
Accrued expenses and other current liabilities		69,196			44,600
Due to related party		(149,029	)		166,560
Net cash used in operating activities		(648,816	)		(1,227,183	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of property and equipment		(4,171,867	)		(2,165,899	)
Sale (purchases) of short-term investments		82,693			(761,614	)
Rebates and incentives		232,483			155,831
Net cash used in investing activities		(3,856,691	)		(2,771,682	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of warrants		372,815			-
Proceeds from exercise of warrants		35,000			672,000
Proceeds from sale of common stock, net of costs		5,878,079			-
Proceeds from issuance of stock options		22,406			-
Principal payments on capital lease obligations		(3,365	)		-
Distributions to noncontrolling interest		(333,704	)		(47,119	)
Net cash provided by financing activities		5,971,231			624,881

Net increase (decrease) in cash and cash equivalents		1,465,724			(3,373,984	)
Cash and cash equivalents, beginning of the year		1,683,498			5,057,482
Cash and cash equivalents, ending of the year	$	3,149,222		$	1,683,498

Supplemental disclosures of cash flows information:
Cash paid during the year for:
Interest	$	448,645		$	477,422
Income taxes	$	35,460		$	86,130

Non-cash investing and financing activities:
Conversion of convertible debenture to common stock	$	555,000		$	150,000
Acquisition of equipment under capital lease	$	-		$	16,825

See accompanying notes to consolidated financial statements

F-5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — The company:

American DG Energy Inc. (“American DG Energy”, the “company”, “us” or “we”) distributes and operates on-site cogeneration systems that produce both electricity and heat. Our business is to own the equipment that we install at customers’ facilities and to sell the energy produced by these systems to the customers on a long-term contractual basis. We call this business the American DG Energy “On-Site Utility”.

The company was incorporated as a Delaware corporation on July 24, 2001 to install, own, operate and maintain complete distributed generation systems and other complementary systems at customer sites and sell electricity, hot water, heat and cooling energy under long-term contracts at prices guaranteed to the customer to be below conventional utility rates. As of December 31, 2009, we had installed energy systems, representing approximately 4,210 kilowatts, or kW, 33.5 million British thermal units, or MMBtu’s, of heat and hot water and 2,200 tons of cooling. Kilowatt is a measure of electricity generated, MMBtu is a measure of heat generated and a ton is a measure of cooling generated.

We derive sales from selling energy in the form of electricity, heat, hot water and cooling to our customers under long-term energy sales agreements (with a typical term of 10 to 15 years). The energy systems are owned by us and are installed in our customers’ buildings. Each month we obtain readings from our energy meters to determine the amount of energy produced for each customer. We multiply these readings by the appropriate published price of energy (electricity, natural gas or oil) from our customers’ local energy utility, to derive the value of our monthly energy sale, less the applicable negotiated discount. Our revenues per customer on a monthly basis vary based on the amount of energy produced by our energy systems and the published price of energy (electricity, natural gas or oil) from our customers’ local energy utility that month. Our revenues commence as new energy systems become operational. As of December 31, 2009, we had 62 energy systems operational. As a by-product of our energy business, in some cases the customer may choose to have us construct the system for them rather than have it owned by American DG Energy.

Note 2 — Summary of significant accounting policies:

Principles of Consolidation and Basis of Presentation:

The accompanying consolidated financial statements include the accounts of the company, its wholly-owned subsidiary American DG Energy and its 51% joint venture, American DG New York, LLC, or ADGNY. The company’s owns 51% of ADGNY, after elimination of all material intercompany accounts, transactions and profits. The interest in underlying energy system projects in the joint venture varies between the company and its joint venture partner. As the controlling partner, all major decisions in ADGNY are made by the company according to the joint venture agreement. Distributions, however, are made based on the economic ownership and profitability of the joint venture and underlying energy projects. The economic ownership is calculated by the amount invested by the company and the noncontrolling partner in each site. Each quarter the company calculates a year-to-date profit/loss for each site that is part of ADGNY and the noncontrolling interest percent ownership in each site is applied to determine the noncontrolling interest share in the profit/loss. The company follows the same calculation regarding available cash and a cash distribution is made to the noncontrolling interest partner, Peter Westerhoff, each quarter. On the company’s balance sheet, noncontrolling interest represents the partner’s investment in the entity, plus its share of after tax profits less any cash distributions. The company owned a controlling 51% legal interest and a 57% economic interest in ADGNY as of December 31, 2009.

The company evaluates the applicability of the Financial Accounting Standards Board, or FASB, guidance on variable interest entities to partnerships and joint ventures at the inception of its participation to ensure its accounting is in accordance with the appropriate standards. The company has contractual interests in Tecogen and determined that Tecogen was a Variable Interest Entity, as defined by the applicable guidance; however, the company was not considered the primary beneficiary and does not have any exposure to loss as a result of its involvement with Tecogen. Therefore, Tecogen was not consolidated in our consolidated financial statements through December 31, 2009. See “Note 7 - Related Parties” for further discussion.

The company’s operations are comprised of one business segment. Our business is selling energy in the form of electricity, heat, hot water and cooling to our customers under long-term sales agreements.

F-6

We have experienced total net losses since inception of approximately $12.2 million. For the foreseeable future, we expect to experience continuing operating losses and negative cash flows from operations as our management executes our current business plan. The cash and cash equivalents available at December 31, 2009 will provide sufficient working capital to meet our anticipated expenditures including installations of new equipment for the next twelve months; however, as we continue to grow our business by adding more energy systems, the cash requirements will increase. We believe that our cash and cash equivalents available at December 31, 2009 and our ability to control certain costs, including those related to general and administrative expenses, will enable us to meet our anticipated cash expenditures through January 1, 2011. Beyond January 1, 2011, we may need to raise additional capital through a debt financing or equity offering to meet our operating and capital needs. There can be no assurance, however, that we will be successful in our fundraising efforts or that additional funds will be available on acceptable terms, if at all.

In 2009, we raised $6,310,525 through various private placements of common stock, the issuance of warrants and exercise of stock options. If we are unable to raise additional capital in 2011 we may need to terminate certain of our employees and adjust our current business plan. Financial considerations may cause us to modify planned deployment of new energy systems and we may decide to suspend installations until we are able to secure additional working capital. We will evaluate possible acquisitions of, or investments in, businesses, technologies and products that are complementary to our business; however, we are not currently engaged in such discussions.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition

F-7

Other revenue represents various types of ancillary activities for which the company engages from time to time such as demand response incentives, the sale of equipment, and feasibility studies.

Cash and Cash Equivalents

The company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. The company has cash balances in certain financial institutions in amounts which occasionally exceed current federal deposit insurance limits. The financial stability of these institutions is continually reviewed by senior management. The company believes it is not exposed to any significant credit risk on cash and cash equivalents.

Short-Term Investments

Short-term investments consist of certificates of deposit with maturities of greater than three months but less than one year. Certificates of deposits are recorded at fair value.

Concentration of Credit Risk

Financial instruments, which potentially subject the company to concentrations of credit risk, consist of highly liquid cash equivalents and trade receivables. The company’s cash equivalents are placed with certain financial institutions and issuers. As of December 31, 2009, the company had a balance of $3,578,143 in cash and cash equivalents and short-term investments that exceeded the Federal Deposit Insurance Corporation limit of $250,000.

Accounts Receivable

The company maintains receivable balances primarily with customers located throughout New York and New Jersey. The company reviews its customers’ credit history before extending credit and generally does not require collateral. An allowance for doubtful accounts is established based upon factors surrounding the credit risk of specific customers, historical trends and other information. Generally, such losses have been within management’s expectations. Bad debt is written off when identified.

Accounts receivable are presented net of an allowance for doubtful collections of $51,821 and $51,759 at December 31, 2009 and December 31, 2008 respectively. Included in accounts receivable are amounts from four major customers accounting for approximately 22% and 45% of total accounts receivable for the years ended December 31, 2009 and December 31, 2008, respectively. There were sales to three customers accounting for approximately 26% and 27% of total sales for the years ended December 31, 2009 and December 31, 2008, respectively.

Inventory

Inventories are stated at the lower of cost or market, valued on a first-in, first-out basis. Inventory is reviewed periodically for slow-moving and obsolete items. As of December 31, 2009 and December 31, 2008, there were no reserves or write-downs recorded against inventory.

Accounts Payable

Included in accounts payable are amounts due to five major vendors accounting for approximately 66% and 51% of total accounts payable for the years ended December 31, 2009 and December 31, 2008, respectively. Purchases from four vendors accounted for approximately 67% and 50% of total purchases for the years ended December 31, 2009, and December 31, 2008, respectively.

Supply Concentrations

All of the company’s cogeneration unit purchases for the years ended December 31, 2009 and 2008 were from one vendor (see “Note 7 - Related Parties”). We believe there are sufficient alternative vendors available to ensure a constant supply of cogeneration units on comparable terms. However, in the event of a change in suppliers, there could be a delay in obtaining units which could result in a temporary slowdown of installing additional income producing sites. In addition, the majority of the company’s units are installed and maintained by the noncontrolling interest holder or maintained by Tecogen. The company believes there are sufficient alternative vendors available to ensure a constant supply of maintenance and installation services on comparable terms. However, in the event of a change of vendor, there could be a delay in installation or maintenance services.

F-8

Property and Equipment and Depreciation and Amortization

Stock Based Compensation

Stock based compensation cost is measured at the grant date based on the estimated fair value of the award and is recognized as an expense in the consolidated statement of operations over the requisite service period. The fair value of stock options granted is estimated using the Black-Scholes option pricing valuation model. The company recognizes compensation on a straight-line basis for each separately vesting portion of the option award. Use of a valuation model requires management to make certain assumptions with respect to selected model inputs. Expected volatility is calculated based on the average volatility of 20 companies in the same industry as the company. The average expected life is estimated using the simplified method for “plain vanilla” options. The expected life in years is based on the “simplified” method. The simplified method determines the expected life in years based on the vesting period and contractual terms as set forth when the award is made. The company uses the simplified method for awards of stock-based compensation since it does not have the necessary historical exercise and forfeiture data to determine an expected life for stock options. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term which approximates the expected life assumed at the date of grant. When options are exercised the company normally issues new shares.

See “Note 5 – Stockholders’ Equity” for a summary of the restricted stock and stock option activity under our stock-based employee compensation plan for the years ended December 31, 2009 and December 31, 2008.

F-9

Loss per Common Share

We compute basic loss per share by dividing net income (loss) for the period by the weighted average number of shares of common stock outstanding during the period. We compute our diluted earnings per common share using the treasury stock method. For purposes of calculating diluted earnings per share, we consider our shares issuable in connection with convertible debentures, stock options and warrants to be dilutive common stock equivalents when the exercise price is less than the average market price of our common stock for the period. As of the year ended December 31, 2009, we excluded 9,643,460 anti-dilutive shares resulting from conversion of debentures and exercise of stock options, warrants and unvested restricted stock, and as of the year ended December 31, 2008, we excluded 10,543,049 anti-dilutive shares resulting from conversion of debentures and exercise of stock options, warrants and unvested restricted stock. All shares issuable for both years were anti-dilutive because of the reported net loss.

Other Comprehensive Net Loss

The comprehensive net loss for the years ended December 31, 2009 and 2008 does not differ from the reported loss.

Income Taxes

The tax years 2005 through 2008 remain open to examination by major taxing jurisdictions to which we are subject, which are primarily in the United States, as carry forward attributes generated in years past may still be adjusted upon examination by the Internal Revenue Service or state tax authorities if they are or will be used in a future period. We are currently not under examination by the Internal Revenue Service or any other jurisdiction for any tax years. We did not recognize any interest and penalties associated with unrecognized tax benefits in the accompanying financial statements. We would record any such interest and penalties as a component of interest expense. We do not expect any material changes to the unrecognized benefits within 12 months of the reporting date.

Fair Value of Financial Instruments

The company’s financial instruments are cash and cash equivalents, short-term investments, accounts receivable, accounts payable, convertible debentures and notes due from related parties. The recorded values of cash and cash equivalents, accounts receivable, accounts payable and notes due from related parties approximate their fair values based on their short-term nature. Short-term investments are recorded at fair value. The carrying value of the convertible debentures on the balance sheet at December 31, 2009 approximates fair value as the terms approximate those currently available for similar instruments. See Note 8 for discussion of fair value measurements.

Recent Accounting Pronouncements

In December 2007, the FASB issued guidance on changes in the accounting and reporting of business acquisitions. The guidance requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in purchased entities, measured at their fair values at the date of acquisition based upon the definition of fair value. This guidance was effective for the company beginning January 1, 2009. The guidance had no impact on the company’s consolidated financial statements and any future effect will depend on the extent that the company makes business acquisitions in the future.

As noted in Note 2, in December 2007, the FASB issued new rules on noncontrolling interests in consolidated financial statements. The noncontrolling interest guidance changed the accounting for minority interests, which are reclassified as noncontrolling interests and classified as a component of equity. This guidance was effective for the company beginning January 1, 2009, and resulted in a change in presentation of minority interests in the consolidated financial statements consistent with the new rules.

F-10

In September, 2006, the FASB issued guidance which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. In February, 2008, the FASB delayed the effective date of the fair value guidance for all non-financial assets and non-financial liabilities, except those that are measured on a recurring basis. Effective January 1, 2009, the company adopted fair value guidance with respect to non-financial assets and liabilities measured on a non-recurring basis. The adoption of this guidance did not have an impact on the Company’s financial position or results of operations.

In March 2008, the FASB issued a pronouncement pertaining to disclosures about derivative instruments and hedging activities. This guidance requires disclosures of how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The rule was effective for the company beginning January 1, 2009. The guidance did not have a material impact on its results of operations and financial condition.

In April 2009, the FASB issued guidance on providing interim disclosures about fair value of financial instruments. This new guidance requires the fair value disclosures that were previously disclosed only annually to be disclosed now on an interim basis. This guidance was effective for the company in the second quarter of 2009, and has resulted in additional disclosures in our interim financial statements, and therefore did not impact our financial position, results of operations or cash flows.

In May 2009, the FASB issued a pronouncement on subsequent event accounting. The guidance identifies the following: the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. The pronouncement was effective for the company’s second quarter 2009, and did not have an impact on our financial position, results of operations, or cash flows.

In June 2009, the FASB issued guidance on the FASB Accounting Standards Codification and the hierarchy of generally accepted accounting principles. The FASB Accounting Standards Codification, or the Codification, is the single source of authoritative nongovernmental generally accepted accounting principles in the U.S. The Codification was effective for interim and annual periods ending after September 15, 2009. The adoption of the Codification had no impact on the company’s financial position, results of operations or cash flows.

In June, 2009 the FASB updated existing guidance to improve financial reporting by enterprises involved with variable interest entities. The new guidance requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest(s) give it a controlling financial interest in a variable interest entity. This guidance is effective for the company beginning in January 2010. The company does not believe adoption of this guidance will have a material effect on its consolidated financial statements.

In September 2009, the Emerging Issues Task Force issued new rules pertaining to the accounting for revenue arrangements with multiple deliverables. The new rules provide an alternative method for establishing fair value of a deliverable when vendor specific objective evidence cannot be determined. The guidance provides for the determination of the best estimate of selling price to separate deliverables and allows the allocation of arrangement consideration using this relative selling price model. The guidance supersedes the prior multiple element revenue arrangement accounting rules that are currently used by the company. This guidance is effective for us January 1, 2011 and is not expected to have a material effect on our consolidated financial position or results of operations.

Reclassifications

F-11

Note 3 — Property, plant and equipment:

Property, plant and equipment consist of the following as of December 31, 2009 and December 31, 2008:

	December 31,
	2009			2008

Co-generation units	$	8,559,132		$	7,187,382

Computer equipment and software		42,531			20,199
Furniture and fixtures		28,087			26,846
Vehicles		37,193			37,193
		8,666,943			7,271,620
Less — accumulated depreciation		(2,168,063	)		(1,506,511	)
		6,498,880			5,765,109
Construction in progress		3,003,466			862,431
	$	9,502,346		$	6,627,540

Depreciation expense of property, plant and equipment totaled $806,776 and $604,525 for the years ended December 31, 2009 and December 31, 2008.

Note 4 — Convertible debentures:

In April and June of 2006, the company issued convertible debentures totaling $6,075,000 to existing investors (the “debentures”). The debentures accrue interest at a rate of 8% per annum and are due five years from the issuance date. The debentures are convertible, at the option of the holder, into a number of shares of common stock as determined by dividing the original outstanding amount of the respective debenture by the conversion price in effect at the time. The initial conversion price of the debenture is $0.84 and is subject to adjustment in accordance with the agreement. As of December 31, 2009 the conversion price of the debenture has not been adjusted.

In 2008, two holders of the company’s 8% Convertible Debenture elected to convert $150,000 of the outstanding principal amount of the debentures into 178,572 shares of common stock. In 2009, three holders of the company’s 8% Convertible Debenture elected to convert $555,000 of the outstanding principal amount of the debentures into 660,714 shares of common stock. At December 31, 2009, there were 6,333,335 shares of common stock issuable upon conversion of our outstanding convertible debentures.

On February 9, 2010, all holders of the convertible debentures elected to convert their principal amount outstanding into shares of common stock at a conversion price of $0.84. See “Note 11 – Subsequent events.”

Note 5 — Stockholders’ equity:

Common Stock

The holders of common stock have the right to vote their interest on a per share basis. At December 31, 2009, there were 37,676,817 shares of common stock outstanding.

F-12

Warrants

From December 1, 2003 to December 31, 2005, the company raised funds through a private placement of shares of common stock to a limited number of accredited investors. In connection with the private placement, the company issued warrants to purchase an aggregate of 3,895,000 shares of common stock at a price of $0.70. The company issued 1,030,000, 775,000 and 2,090,000 warrants in 2003, 2004 and 2005 respectively. Each warrant represents the right to purchase one share of common stock for a period of three or five years from the date the warrant was issued.

During the year ended December 31, 2007, investors exercised 200,000 warrants with expiration dates in 2007, for gross proceeds to the company of $140,000 and during the year 575,000 warrants expired. During the year ended December 31, 2008, investors exercised 1,010,000 warrants with expiration dates in 2008, for gross proceeds to the company of $707,000. Of these warrants, 50,000 were exercised towards the end of the year, therefore, the company established a receivable shown as common stock subscription on the balance sheet and that amount was collected early in 2009.

Stock Based Compensation

The company has adopted the 2005 Stock Incentive Plan, or the Plan, under which the board of directors may grant incentive or non-qualified stock options and stock grants to key employees, directors, advisors and consultants of the company. On April 17, 2008 the board unanimously amended the Plan, subject to shareholder approval, to increase the reserved shares of common stock issuable under the Plan from 4,000,000 to 5,000,000, or the Amended Plan. On May 30, 2008, at the company’s annual meeting, the shareholders voted in favor of an amendment to increase the number of shares of common stock of the company available for issuance under the Plan from 4,000,000 to 5,000,000 shares.

The maximum number of shares of stock allowable for issuance under the Amended Plan is 5,000,000 shares of common stock, including 1,190,500 shares of restricted stock outstanding as of December 31, 2009. Stock options vest based upon the terms within the individual option grants, usually over a two- or ten-year period with an acceleration of the unvested portion of such options upon a liquidity event, as defined in the company’s stock option agreement. The options are not transferable except by will or domestic relations order. The option price per share under the Amended Plan is not less than the fair market value of the shares on the date of the grant. The number of securities remaining available for future issuance under the Amended Plan was 1,051,250 at December 31, 2009.

During the years ended December 31, 2009 and December 31, 2008, the company recognized employee non-cash compensation expense of $286,844 and $364,231, respectively, related to the issuance of stock options and restricted stock. At December 31, 2009 there were 440,125 unvested shares of restricted stock outstanding. At December 31, 2009 the total compensation cost related to unvested restricted stock awards and stock option awards not yet recognized is $423,607. This amount will be recognized over the weighted average period of 5.46 years.

In 2008, the company granted to one of its employees nonqualified options to purchase 100,000 shares of the common stock at $1.95 per share. Those options have a vesting schedule of four years and expire in ten years. The fair value of the options issued in 2008 was $93,977, with a weighted average grant date fair value of $0.94 per option.

In 2009, the company granted to three of its employees nonqualified options to purchase 13,000 shares of the common stock at $1.82 per share. Those options have a vesting schedule of four years and expire in five years. During 2009, the company also granted to one of its employees nonqualified options to purchase 6,000 shares of the common stock at $2.95 per share. Those options have a vesting schedule of four years and expire in five years. The fair value of all options issued in 2009 was $16,161, with a weighted average grant date fair value of $0.85 per option.

The weighted average assumptions used in the Black-Scholes option pricing model are as follows:

	2009			2008
Stock options and restricted stock awards
Expected life	5.94 years			6.95 years
Risk-free interest rate		0.37	%		1.62	%
Expected volatility		48.4	%		48.4	%

F-13

Stock option activity for the years ended December 31, 2009 and 2008 was as follows:

				Exercise	Weighted		Weighted
	Number			Price	Average		Average	Aggregate
	Of			Per	Exercise		Remaining	Intrinsic
Common Stock Options	Options			Share	Price		Life	Value

Outstanding, December 31, 2007		2,241,000		$0.07-$0.90	$	0.63	7.71 years	$	607,600
Granted		100,000		$1.95		1.95
Exercised		-		-		-			-
Canceled		(12,000	)	$0.90		0.90
Expired		-		-		-
Outstanding, December 31, 2008		2,329,000		$0.07-$1.95	$	0.68	6.95 years	$	3,017,920
Exercisable, December 31, 2008		1,244,500			$	0.42		$	1,937,660
Vested or expected to vest, December 31, 2008		2,329,000			$	0.68		$	3,017,920

Outstanding, December 31, 2008		2,329,000		$0.07-$1.95	$	0.68	6.95 years	$	3,017,920
Granted		19,000		$1.82-$2.95		2.18
Exercised		(31,250	)	$0.70-$0.90		0.72
Canceled		-		-		-
Expired		(8,750	)	$0.70-$0.90		0.87
Outstanding, December 31, 2009		2,308,000		$0.07-$2.95	$	0.70	5.94 years	$	5,203,740
Exercisable, December 31, 2009		1,421,000			$	0.50		$	3,488,400
Vested or expected to vest, December 31, 2009		2,308,000			$	0.70		$	5,203,740

The aggregate intrinsic value of options outstanding as of December 31, 2009 is calculated as the difference between the exercise price of the underlying options and the price of the company’s common stock for options that were in-the-money as of that date. Options that were not in-the-money as of that date, and therefore have a negative intrinsic value, have been excluded from this amount.

In 2008, the company made a restricted stock grant to one employee by permitting him to purchase an aggregate of 40,000 shares of common stock, at a price of $0.001 per share. The fair value of the restricted stock issued in 2008 was $77,960 and vests in four years. There were no restricted stock grants to employees in 2009.

Restricted stock activity for the years ended December 31, 2009 and 2008 was as follows:

	Number of			Grant Date
	Restricted Stock			Fair Value

Unvested, December 31, 2007		948,875			0.70
Granted		40,000			1.95
Vested		(268,875	)		0.70
Forfeited		-			-
Unvested, December 31, 2008		720,000		$	0.77

Granted		-			-
Vested		(240,875	)		0.75
Forfeited		(39,000	)		0.70
Unvested, December 31, 2009		440,125		$	0.79

F-14

Note 6 — Employee benefit plan:

The company has a defined contribution retirement plan, or the Retirement Plan, which qualifies under Section 401(k) of the Internal Revenue Code, or the IRC. Under the Retirement Plan, employees meeting certain requirements may elect to contribute a percentage of their salary up to the maximum allowed by the IRC. The company matches a variable amount based on participant contributions up to a maximum of 4.5% of each participant’s salary. The company contributed $39,075 and $31,717 to the Retirement Plan for the years ended December 31, 2009 and 2008, respectively.

Note 7 — Related parties

The company has sales representation rights to Tecogen’s products and services. In New England, the company has exclusive sales representation rights to Tecogen’s cogeneration products. The company has granted Tecogen sales representation rights to its On-Site Utility energy service in California.

On February 15, 2007, the company loaned Peter Westerhoff, the non controlling interest partner in ADGNY, $20,000 by signing a two year loan agreement earning interest at 12% per annum. On April 1, 2007, the company loaned an additional $75,000 to the same non controlling partner by signing a two year note agreement earning interest at 12% per annum, and on May 16, 2007, the company loaned an additional $55,000 to the same partner by signing a two year note agreement under the same terms. On October 11, 2007, the company extended to its non controlling interest partner a line of credit of $500,000. At December 31, 2008, $265,012 was outstanding and due to the company under the combination of the above agreements. All notes were classified in the Due from related party account in the December 31, 2008 balance sheet and were secured by the partner’s non controlling interest. Effective April 1, 2009 the company reached an agreement with the noncontrolling interest partner in ADGNY to purchase its interest in the Riverpoint location. As a result of this transaction, the company owns 100% of that location and the noncontrolling interest partners’ share of that location was applied to his outstanding debt to the company related to the above mentioned loan agreements and line of credit. Additionally, in 2009, ADGNY financed capital improvements at several projects, which per project agreements was the responsibility of the noncontrolling interest partner. This further reduced the noncontrolling interest partner’s noncontrolling interest in ADGNY. The result of these transactions appears as “Ownership changes to noncontrolling interests” in the amount of $405,714 in the accompanying consolidated statement of stockholder’s equity for the year ended December 31, 2009.

F-15

Note 8 — Fair value measurements:

The fair value topic of the FASB Accounting Standards Codification defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The accounting guidance also establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs, where available, and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities. We currently do not have any Level 1 financial assets or liabilities.

Level 2 — Observable inputs other than quoted prices included in Level 1. Level 2 inputs include quoted prices for identical assets or liabilities in non-active markets, quoted prices for similar assets or liabilities in active markets and inputs other than quoted prices that are observable for substantially the full term of the asset or liability.

Level 3 — Unobservable inputs reflecting management’s own assumptions about the input used in pricing the asset or liability. We currently do not have any Level 3 financial assets or liabilities.

At December 31, 2009, the company had $678,921 in short-term investments that are comprised of certificates of deposits which are categorized as Level 2. The company determines the fair value of certificates of deposits using information provided by the issuing bank which includes discounted expected cash flow estimates using current market rates offered for deposits with similar remaining maturities.

Note 9 — Income taxes:

A reconciliation of federal statutory income tax provision to the company’s actual provision for the years ended December 31, 2009 and December 31, 2008, respectively, are as follows:

		2009			2008

Benefit at federal statutory tax rate	��	$	(860,000	)	$	(760,000	)
Unbenefited operating losses			860,000			760,000
Provision for state income taxes			7,450			34,087
Income tax provision		$	7,450		$	34,087

The components of net deferred tax assets recognized in the accompanying balance sheets at December 31, 2009 and December 31, 2008, respectively, are as follows:

	2009			2008

Net operating loss carryforwards	$	4,676,000		$	3,149,000
Accrued expenses and other		312,000			178,000
Depreciation		(764,000	)		(271,000	)
		4,224,000			3,056,000
Valuation allowance		(4,224,000	)		(3,056,000	)
Net deferred tax asset	$	-		$	-

F-16

As of December 2009, the company has federal and state loss carryforwards of approximately $12,400,000 and $8,300,000, respectively, which may be used to offset future federal and state taxable income, expiring at various dates through 2029. Under IRC Section 382, certain substantial changes in the company’s ownership may limit the amount of net operating loss carryforwards that can be utilized in any one year to offset future taxable income. As a result of the company’s various private placements of common stock, it is possible that, net operating loss carryforwards and other tax attributes may have been limited by these rules. The change-in-control provisions of IRC section 382 have not been fully investigated in relation to these transactions.

Management has determined that it is more likely than not that the company will not recognize the benefits of the federal and state deferred tax assets and as a result has recorded a valuation allowance against the entire net deferred tax asset. If the company should generate sustained future taxable income, against which these tax attributes may be recognized, some portion or all of the valuation allowance would be reversed.

The company adopted accounting for uncertain tax positions effective January 1, 2007. The adoption of this statement had no effect on the company’s financial position. The company has no uncertain tax positions as of either the date of the adoption, or as of December 31, 2009.

Note 10 — Commitments and contingencies:

In January 2006, the company entered into the Agreement with Tecogen to provide the company with certain office and business support services for a period of one year, renewable annually by mutual agreement. The company also shares personnel support services with Tecogen. The company is allocated its share of the cost of the personnel support services based upon the amount of time spent by such support personnel while working on the company’s behalf. To the extent Tecogen is able to do so under its current plans and policies, Tecogen includes the company and its employees in several of its insurance and benefit programs. The costs of these programs are charged to the company on an actual cost basis. Under this agreement, the company receives pricing based on a volume discount if it purchases cogeneration and chiller products from Tecogen. For certain sites, the company hires Tecogen to service its Tecogen chiller and cogeneration products. Under the current amendment to the Agreement, Tecogen provides the company with office space and utilities at a monthly rate of $5,526.

In November 2008, the company received from Georgia King Village, an On-Site Utility energy customer, a notice to terminate operations at their location. The company notified the management of Georgia King Village that the termination notice violated the terms of the agreement between the company and Georgia King Village and that termination charges would apply. The company proceeded to remove five energy systems and other supporting equipment from the Georgia King Village site and placed them in inventory. The customer has recently proposed a settlement regarding the aforementioned dispute and as a result the company has postponed the arbitration hearing. The company does not expect the outcome to have a material impact on its results of operations and financial condition.

The company is the lessee of certain equipment under capital lease expiring in 2013. The following is a schedule of future minimum lease payments, together with the present value of the net minimum lease payments under capital leases as of December 31, 2009.

	Payments
2010	$	5,221
2011		5,221
2012		5,221
2013		5,221
Total lease payments		20,884
Less: Amount representing interest		(7,424	)
Present value of minimum lease payments	$	13,460

F-17

Note 11 — Subsequent events:

On January 4, 2010, the company entered into an agreement with Codale Ltd., whereby Codale will provide the company an amount up to two hundred fifty thousand British Pounds sterling (£250,000) to cover expenses incurred in connection with an investigation and research effort for the development of the company’s business in European markets. Expenses relating to this investigation will be incurred over a period of up to one year, and in consideration for the funds provided to the company, if the company forms a new subsidiary within two years from the signing of the agreement, Codale will be entitled to an equity interest in such subsidiary equal to 10% of the equity thereof.

On February 9, 2010, the company issued a Notice of Redemption to all holders of its outstanding 8% Convertible Debentures to announce redemption as of February 26, 2010, of all of its outstanding convertible debentures that had not been converted into common stock. The aggregate principal amount of convertible debentures outstanding on February 26, 2010 was $5,320,000 and accrued interest was $66,204. All holders of the convertible debentures elected to convert their principal amount outstanding into shares of common stock at a conversion price of $0.84. In connection with this transaction, the company issued to the holders of the convertible debentures an aggregate of 6,402,962 shares of common stock and paid $7,716 of accrued interest in cash. The closing price of the company’s common stock on the NYSE Amex on February 8, 2010 was $2.82.

In March 2010, certain investors including George N. Hatsopoulos and John N. Hatsopoulos, exercised 500,000 warrants with an expiration date of April 5, 2010, for gross proceeds to the company of $350,000.

F-18

American DG Energy (ADGE) Inactive 10-K/A2009 FY Annual report (amended)