UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


WASHINGTON, D.C. 20549




FORM 10-K





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





For the fiscal year ended December 31, 2010


or





 ̈
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 AvenueWaltham, 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 registeredCommon 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, 2010, the aggregate market value of the voting shares of the registrant held by non-affiliates was approximately $70,088,030 based on a closing price per share of $3.11 on the NYSE Amex. For purposes of this calculation, an aggregate of 22,209,685 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, 2011 the registrant’s shares of common stock outstanding were: 45,598,029.





DOCUMENTS INCORPORATED BY REFERENCE


Certain information required by in Items 10, 11, 12, 13 and 14 of Part III of this Annual Report on Form 10-K is incorporated by reference to our definitive Proxy Statement for our 2011 Annual Meeting of Shareholders scheduled to be held on May 26, 2011.


WARNING CONCERNING FORWARD-LOOKING STATEMENTS


THIS ANNUAL REPORT ON FORM 10-K CONTAINS FORWARD-LOOKING STATEMENTS WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS. THESE FORWARD-LOOKING STATEMENTS ARE BASED ON OUR PRESENT INTENT, BELIEFS OR EXPECTATIONS, AND ARE NOT GUARANTEED TO OCCUR AND MAY NOT OCCUR. ACTUAL RESULTS MAY DIFFER MATERIALLY FROM THOSE CONTAINED IN OR IMPLIED BY OUR FORWARD-LOOKING STATEMENTS AS A RESULT OF VARIOUS FACTORS.
 
 WE GENERALLY IDENTIFY FORWARD-LOOKING STATEMENTS BY TERMINOLOGY SUCH AS “MAY,” “WILL,” “SHOULD,” “EXPECTS,” “PLANS,” “ANTICIPATES,” “COULD,” “INTENDS,” “TARGET,” “PROJECTS,” “CONTEMPLATES,” “BELIEVES,” “ESTIMATES,” “PREDICTS,” “POTENTIAL” OR “CONTINUE” OR THE NEGATIVE OF THESE TERMS OR OTHER SIMILAR WORDS. THESE STATEMENTS ARE ONLY PREDICTIONS. THE OUTCOME OF THE EVENTS DESCRIBED IN THESE FORWARD-LOOKING STATEMENTS IS SUBJECT TO KNOWN AND UNKNOWN RISKS, UNCERTAINTIES AND OTHER FACTORS THAT MAY CAUSE OUR, OUR CUSTOMERS’ OR OUR INDUSTRY’S ACTUAL RESULTS, LEVELS OF ACTIVITY, PERFORMANCE OR ACHIEVEMENTS EXPRESSED OR IMPLIED BY THESE FORWARD-LOOKING STATEMENTS, TO DIFFER.
 
 THIS REPORT ALSO CONTAINS MARKET DATA RELATED TO OUR BUSINESS AND INDUSTRY. THESE MARKET DATA INCLUDE PROJECTIONS THAT ARE BASED ON A NUMBER OF ASSUMPTIONS. IF THESE ASSUMPTIONS TURN OUT TO BE INCORRECT, ACTUAL RESULTS MAY DIFFER FROM THE PROJECTIONS BASED ON THESE ASSUMPTIONS. AS A RESULT, OUR MARKETS MAY NOT GROW AT THE RATES PROJECTED BY THESE DATA, OR AT ALL. THE FAILURE OF THESE MARKETS TO GROW AT THESE PROJECTED RATES MAY HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS, RESULTS OF OPERATIONS, FINANCIAL CONDITION AND THE MARKET PRICE OF OUR COMMON STOCK.
 
 SEE “ITEM 1A. RISK FACTORS,” “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS” AND “BUSINESS,” AS WELL AS OTHER SECTIONS IN THIS REPORT, THAT DISCUSS SOME OF THE FACTORS THAT COULD CONTRIBUTE TO THESE DIFFERENCES. THE FORWARD-LOOKING STATEMENTS MADE IN THIS ANNUAL REPORT ON FORM 10-K RELATE ONLY TO EVENTS AS OF THE DATE OF WHICH THE STATEMENTS ARE MADE. EXCEPT AS REQUIRED BY LAW, WE UNDERTAKE NO OBLIGATION TO UPDATE OR RELEASE ANY FORWARD- LOOKING STATEMENTS AS A RESULT OF NEW INFORMATION, FUTURE EVENTS OR OTHERWISE.













AMERICAN DG ENERGY INC.


ANNUAL REPORT ON FORM 10-K


FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010





TABLE OF CONTENTS





PART IItem 1.
Business.
2Item 1A.
Risk Factors.
9Item 1B.
Unresolved Staff Comments.
13Item 2.
Properties.
13Item 3.
Legal Proceedings.
13Item 4.
[Removed and Reserved].
13PART IIItem 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
14Item 6.
Selected Financial Data.
15Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
15Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
23Item 8.
Financial Statements and Supplementary Data.
23Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
23Item 9A.
Controls and Procedures.
24Item 9B.
Other Information.
25PART IIIItem 10.
Directors, Executive Officers and Corporate Governance.
26Item 11.
Executive Compensation.
26Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
26Item 13.
Certain Relationships and Related Transactions, and Director Independence.
26Item 14.
Principal Accountant Fees and Services.
26PART IVItem 15.
Exhibits and Financial Statement Schedules.
27





1




PART I




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, 2010, we had installed energy systems, representing approximately 5,250 kilowatts, or kW, 44.0 million British thermal units, or MMBtu’s, of heat and hot water and 2,820 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 28,200 metric tons of carbon equivalents, less than typical separate heat and power systems, resulting in emissions reductions equivalent to planting 5,780 acres of forest or removing the emissions of 4,640 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 calculation 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.


2




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.




In July 2010, the company established EuroSite Power Inc., or EuroSite Power, a subsidiary formed to introduce the company’s On-Site Utility solution into the European market. As of December 31, 2010 the company owns an 86.1% interest in EuroSite Power and has consolidated EuroSite Power into its financial statements in accordance with Generally Accepted Accounting Principles, or GAAP.





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.







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.


3




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.




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.




4




·
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 calculation 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, 2010, we had 76 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.







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.




5




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.




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


o
Electricity


o
Thermal (Hot Water, Heat and Cooling)





·
Energy Producing Products


o
Cogeneration Packages


o
Chillers


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


o
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.




6




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


$
4,908,000American DG Energy Gross Margin

$
84,000


$
1,456,000Customer 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.




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.




7




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.




8




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 $5,793.




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.




In October 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.





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. The U.S. government has been developing and refining various funding opportunities related to its economic recovery or stimulus initiatives. 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.





Employees





As of December 31, 2010, we employed 14 active full-time employees. We believe that our relationship with our employees is satisfactory. None of our employees are represented by a collective bargaining agreement.





Item 1A. Risk Factors.




Our business faces many risks. The risks described below may not be the only risks we face. Additional risks that we do not yet know of, or that we currently think are immaterial, may also impair our business operations or financial results. If any of the events or circumstances described in the following risks occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline. Investors and prospective investors should consider the following risks and the information contained under the heading ‘‘Warning Concerning Forward-Looking Statements’’ before deciding whether to invest in our securities.




We have incurred losses, and these losses may continue.




We have incurred losses in each of our fiscal years since inception. Losses continued to be incurred in 2010. There is no assurance that profitability will be achieved in the near term, if at all.




9




Because unfavorable utility regulations make the installation of our systems more difficult or less economical, any slowdown in the utility deregulation process would be an impediment to the growth of our business.




In the past, many electric utility companies have raised opposition to DG, a critical element of our On-Site Utility business. Such resistance has generally taken the form of unrealistic standards for interconnection, and the use of targeted rate structures as disincentives to combined generation of on-site power and heating or cooling services. A DG company’s ability to obtain reliable and affordable back-up power through interconnection with the grid is essential to our business model. Utility policies and regulations in most states are often not prepared to accommodate widespread on-site generation. These barriers erected by electric utility companies and unfavorable regulations, where applicable, make more difficult or uneconomic our ability to connect to the electric grid at customer sites and are an impediment to the growth of our business. Development of our business could be adversely affected by any slowdown or reversal in the utility deregulation process or by difficulties in negotiating backup power supply agreements with electric providers in the areas where we intend to do business.




Our onsite utility concept is largely unproven and may not be accepted by a sufficient number of customers.




The sale of cogeneration and cooling equipment has been successfully carried out for more than a decade. However, our On-Site Utility concept (i.e., the sale of on-site energy services, rather than equipment) is still in an early stage of implementation. Unresolved issues include the pricing of energy services and the structuring of contracts to provide cost savings to customers and optimum financial returns to us. There is no assurance that we will be successful in developing a profitable On-Site Utility business model, and failure to do so would have a material adverse effect on our business and financial performance.




The economic viability of our projects depends on the price spread between fuel and electricity, and the variability of the prices of these components creates a risk that our projects will be uneconomic.




The economic viability of DG projects is dependent upon the price spread between fuel and electricity prices. Volatility in one component of the spread, the cost of natural gas and other fuels (e.g., propane or distillate oil) can be managed to a greater or lesser extent by means of futures contracts. However, the regional rates charged for both base load and peak electricity services may decline periodically due to excess capacity arising from over-building of utility power plants or recessions in economic activity. Any sustained weakness in electricity prices could significantly limit the market for our cogeneration, cooling equipment and On-Site Utility energy services.




We may fail to make sales to certain prospective customers because of resistance from facilities management personnel to the outsourcing of their service function.




Any outsourcing of non-core activities by institutional or commercial entities will generally lead to reductions in permanent on-site staff employment. As a result, our proposals to implement On-Site Utility contracts are likely to encounter strong initial resistance from the facilities managers whose jobs will be threatened by energy outsourcing. The growth of our business will depend upon our ability to overcome such barriers among prospective customers.




Future government regulations, such as increased emissions standards, safety standards and taxes, may adversely impact the economics of our business.




The operation of DG equipment at our customers’ sites may be subject to future changes in federal, state and local laws and regulations (e.g., emissions, safety, taxes, etc.). Any such new or substantially altered rules and standards may adversely affect our revenues, profits and general financial condition.




If we cannot expand our network of skilled technical support personnel, we will be unable to grow our business.




Each additional customer site for our services requires the initial installation and subsequent maintenance and service of equipment to be provided by a team of technicians skilled in a broad range of technologies, including combustion, instrumentation, heat transfer, information processing, microprocessor controls, fluid systems and other elements of DG. If we are unable to recruit, train, motivate, sub-contract, and retain such personnel in each of the regional markets where our business operates we will be unable to grow our business in those markets.




The company operates in highly competitive markets and may be unable to successfully compete against competitors having significantly greater resources and experience.




Our business may be limited by competition from energy services companies arising from the breakup of conventional regulated electric utilities. Such competitors, both in the equipment and energy services sectors, are likely to have far greater financial and other resources than us, and could possess specialized market knowledge with existing channels of access to prospective customer locations. We may be unable to successfully compete against those competitors.




10




Future technology changes may render obsolete various elements of equipment comprising our On-Site Utility installations.




We must select equipment for our DG projects so as to achieve attractive operating efficiencies, while avoiding excessive downtimes from the failure of unproven technologies. If we are unable to achieve a proper balance between the cost, efficiency and reliability of equipment selected for our projects, our growth and profitability will be adversely impacted.




We have limited historical operating results upon which to base projections of future financial performance, making it difficult for prospective investors to assess the value of our stock.




Our experience is primarily on-site energy services, and we have only a few years of actual operating experience. These limitations make developing financial projections more difficult. We will expand our business infrastructure based on these projections. If these projections prove to be inaccurate, we will sustain additional losses and will jeopardize the success of our business.




We will need to raise additional capital for our business, which will dilute existing shareholders.




Additional financings will be required to implement our overall business plan. We will need additional capital. Equity financings will dilute the percentage ownership of our existing shareholders. Our ability to raise an adequate amount of capital and the terms of any capital that we are able to raise will be dependent upon our progress in implementing demonstration projects and related marketing service development activities. If we do not make adequate progress, we may be unable to raise adequate funds, which will limit our ability to expand our business. If the terms of any equity financings are unfavorable, the dilutive impact on our shareholders might be severe.




We may make acquisitions that could harm our financial performance.




In order to expedite development of our corporate infrastructure, particularly with regard to equipment installation and service functions, we anticipate the future acquisition of complementary businesses. Risks associated with such acquisitions include the disruption of our existing operations, loss of key personnel in the acquired companies, dilution through the issuance of additional securities, assumptions of existing liabilities and commitment to further operating expenses. If any or all of these problems actually occur, acquisitions could negatively impact our financial performance and future stock value.




We are controlled by a small group of majority shareholders, and our minority shareholders will be unable to effect changes in our governance structure or implement actions that require shareholder approval, such as a sale of the company.




George Hatsopoulos and John Hatsopoulos, who are brothers, beneficially own a majority of our outstanding shares of common stock. These stockholders have the ability to control various corporate decisions, including our direction and policies, the election of directors, the content of our charter and bylaws and the outcome of any other matter requiring shareholder approval, including a merger, consolidation and sale of substantially all of our assets or other change of control transaction. The concurrence of our minority shareholders will not be required for any of these decisions.




We may be exposed to substantial liability claims if we fail to fulfill our obligations to our customers.




We enter into contracts with large commercial and not-for-profit customers under which we will assume responsibility for meeting a portion of the customers’ building energy demand and equipment installation. We may be exposed to substantial liability claims if we fail to fulfill our obligations to customers. There can be no assurance that we will not be vulnerable to claims by customers and by third parties that are beyond any contractual protections that we are able to negotiate. We may be unable to obtain liability and other insurance on terms and at prices that are commercially acceptable to us. As a result, liability claims could cause us significant financial harm.




Investment in our common stock is subject to price fluctuations which have been significant for development stage companies like us.




Historically, valuations of many companies in the development stage have been highly volatile. The securities of many of these companies have experienced significant price and trading volume fluctuations, unrelated to the operating performance or the prospects of such companies. If the conditions in the equity markets further deteriorate, we may be unable to finance our additional funding needs in the private or the public markets. There can be no assurance that any future offering will be consummated or, if consummated, will be at a share price equal or superior to the price paid by our investors even if we meet our technological and marketing goals.




11




Future sales of common stock by our existing stockholders may cause our stock price to fall.





The market price of our common stock could decline as a result of sales by our existing stockholders of shares of common stock in the market or the perception that these sales could occur. These sales might also make it more difficult for us to sell equity securities at a time and price that we deem appropriate and thus inhibit our ability to raise additional capital when it is needed.





Because we do not intend to pay cash dividends, our stockholders will receive no current income from holding our stock.





We have paid no cash dividends on our capital stock to date and we currently intend to retain our future earnings, if any, to fund the development and growth of our business. In addition, the terms of any future debt or credit facility may preclude us from paying these dividends. As a result, capital appreciation, if any, of our common stock will be your sole source of gain for the foreseeable future. We currently expect to retain earnings for use in the operation and expansion of our business, and therefore do not anticipate paying any cash dividends for the foreseeable future.





Our ability to access capital for the repayment of debts and for future growth is limited as the financial markets are currently in a period of disruption and recession and the company does not expect these conditions to improve in the near future.





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.





Our business is affected by general economic conditions and related uncertainties affecting markets in which we operate. The current economic conditions could adversely impact our business in 2011 and beyond.





The current economic conditions could adversely impact our business in 2011 and beyond, resulting in reduced demand for our products, increased rate of order cancellations or delays, increased risk of excess and obsolete inventories, increased pressure on the prices for our products and services; and greater difficulty in collecting accounts receivable.





Trading of our common stock is restricted by the Securities and Exchange Commission’s, or the SEC’s, “penny stock” regulations which may limit a stockholder’s ability to buy and sell our stock.





The SEC has adopted regulations which generally define “penny stock” to be any equity security that has a market price less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and accredited investors. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and other quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statement showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure and suitability requirements may have the effect of reducing the level of trading activity in the secondary market for a stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of our capital stock. Trading of our capital stock is restricted by the SEC’s “penny stock” regulations which may limit a stockholder’s ability to buy and sell our stock.




12




There has been a material weakness in our financial controls and procedures, which could harm our operating results or cause us to fail to meet our reporting obligations.





As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer have performed an evaluation of controls and procedures and concluded that our controls were not effective to provide reasonable assurance that information required to be disclosed by our company in reports that we file under the Securities Exchange Act of 1934, as amended, or the Exchange Act, is recorded, processed, summarized and reported as when required. Management conducted an evaluation of our internal control over financial reporting and based on this evaluation, management concluded that the company’s internal control over financial reporting was not effective as of the end of the period covered by this report. The company currently does not have personnel with a sufficient level of accounting knowledge, experience and training in the selection, application and implementation of generally acceptable accounting principles as it relates to complex transactions and financial reporting requirements. The company also has a small number of employees dealing with general controls over information technology security and user access. This constitutes a material weakness in financial reporting. Any failure to implement effective internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Inadequate internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock, and may require us to incur additional costs to improve our internal control system.





Item 1B. Unresolved Staff Comments.





None.




Item 2.  Properties.




Our headquarters are located in Waltham, Massachusetts and consist of 3,339 square feet of office and storage space that are leased from Tecogen. The lease expires on March 31, 2014. We believe that our facilities are appropriate and adequate for our current needs.




Item 3.  Legal Proceedings.




We are not currently a party to any material litigation, and we are not aware of any pending or threatened litigation against us that could have a material adverse affect on our business, operating results or financial condition.




Item 4.  [Removed and Reserved].




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PART II




Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.




Market




Our common stock is traded on the NYSE Amex under the symbol ADGE. Prior to October 19, 2009, our stock was traded on the OTC Bulletin Board. The following table sets forth the high and low sale prices of the company’s common stock for 2010 and 2009, as reported by the applicable exchange or reporting system.





2010


2009High


Low


High


LowFirst Quarter

$
3.18


$
2.65


$
2.20


$
1.50Second Quarter


4.01



2.86



3.25



2.45Third Quarter


3.46



2.47



3.08



2.70Fourth Quarter


3.37



2.70



3.55



2.52





The closing price of our common stock as reported on the NYSE Amex on December 31, 2010 and 2009 was $2.77 and $2.95, respectively.





Holders





As of February 22, 2011, there were approximately 788 beneficial holders of our common stock.





Dividends





We have never declared or paid any cash dividends on shares of our common stock. We currently intend to retain earnings, if any, to fund the development and growth of our business and do not anticipate paying cash dividends in the foreseeable future. Our payment of any future dividends will be at the discretion of our board of directors after taking into account various factors, including our financial condition, operating results, cash needs and growth plans.





Recent Sales of Unregistered Securities




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. The investors were accredited investors, and such transaction was exempt from registration under the Securities Act under Section 4(2).





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. The investors were accredited investors, and such transaction was exempt from registration under the Securities Act under Section 4(2).





In July 2010 the company invested $45,000 in exchange for 45 million shares and got controlling interest in EuroSite Power, a newly established corporation. Also in July 2010, Nettlestone Enterprises Limited, invested $5,000 in exchange for 5 million shares in EuroSite Power. During the period from July to December 31, 2010, EuroSite Power raised an additional $2,261,000 in a private placement by selling 2,261,000 shares of EuroSite Power common stock to accredited investors at a price of $1.00 per share. The investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Section 4(2).





On July 12, 2010, the company raised $1,000,000 in a private placement of 400,000 shares of common stock at a price of $2.50 per share. The company also granted the investor a special purchase right, or warrant, regarding the company’s EuroSite Power subsidiary. The warrant grants the investor the non-assignable right but not the obligation, for a period of two years from July 12, 2010, to purchase 400,000 shares of the common equity of EuroSite Power at a per share purchase price of $1.00. The investor was an accredited investor, and such transaction was exempt from registration under the Securities Act under Section 4(2).





14





On January 15, 2011, the company signed an investor relations consulting agreement with AIM Capital Corporation d/b/a Barry Kaplan Associates, or AIM Capital, for a period of twelve months. In connection with that agreement the company granted AIM Capital a warrant to purchase 30,000 shares of the company’s common stock at an exercise price per share of $2.69, with a four year vesting period and an expiration date of January 15, 2016. The company received no other consideration from the issuance of the warrants.





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.





Stock Options





In 2010, the company granted nonqualified options to purchase 290,000 shares of the common stock to seven employees and two directors at prices ranging between $2.76 and $3.45 per share. Those options have a vesting schedule of four years and expire in five years. The fair value of all options issued in 2010 was $359,408, with a weighted average grant date fair value of $1.24 per option. The grant of such options was exempt from registration under Rule 701 under the Securities Act.





Item 6. Selected Financial Data.




Not applicable.




Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.




You should read the following discussion and analysis of our financial condition and results of operations together with our financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report on Form 10-K, including information with respect to our plans and strategy for our business, includes forward-looking statements that involve risks and uncertainties. You should review “Item 1A. Risk Factors” beginning on page 9 of this Annual Report on Form 10-K for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.




During the last two fiscal years there has been a slowdown in the economy, a decline in the availability of financing from the capital markets, and a widening of credit spreads which has, or may in the future, adversely affect us to varying degrees. Such conditions may impact our ability to meet obligations to our suppliers and other third parties. These market conditions could also adversely affect the amount of revenue we report, require us to increase our allowances for losses, result in impairment charges and valuation allowances that decrease our equity, increase our loss and reduce our cash flows from operations. In addition, these conditions or events could impair our credit rating and our ability to raise additional capital.





Overview





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, 2010, we had 76 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.





15





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. In this case, we account for 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 and maintenance services, including shared savings are recorded when provided and verified.





We have experienced total net losses since inception of approximately $14.1 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, 2010 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, 2010 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 March 31, 2012. Beyond March 31, 2012, 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 2010, we raised $4,965,775 through various private placements and registered direct offerings of common stock, the issuance of warrants and exercise of stock options. If we are unable to raise additional capital in 2012 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.




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.




Recent Accounting Pronouncements





In June 2009, the Financial Accounting Standards Board, or 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 became effective for the company beginning in January 2010. The adoption of this guidance did not have a material effect on the company’s 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 became effective for us January 1, 2011 and is not expected to have a material effect on the company’s consolidated financial position or results of operations.





In January 2010, FASB issued an amendment to the accounting for fair value measurements and disclosures. This amendment details additional disclosures on fair value measurements, requires a gross presentation of activities within a Level 3 rollforward, and adds a new requirement to the disclosure of transfers in and out of Level 1 and Level 2 measurements. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. This amendment was effective as of January 1, 2010, with an exception for the gross presentation of Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The adoption of the effective provisions of this amendment did not have a material impact on the company’s consolidated financial position or results of operations. The adoption of the remaining provisions is not expected to have a material impact on the company’s consolidated financial position or results of operations.





In March 2010, FASB reached a consensus to issue an amendment to the accounting for revenue arrangements under which a vendor satisfies its performance obligations to a customer over a period of time, when the deliverable or unit of accounting is not within the scope of other authoritative literature, and when the arrangement consideration is contingent upon the achievement of a milestone. The amendment defines a milestone and clarifies whether an entity may recognize consideration earned from the achievement of a milestone in the period in which the milestone is achieved. This amendment is effective for fiscal years beginning on or after June 15, 2010, with early adoption permitted. The amendment may be applied retrospectively to all arrangements or prospectively for milestones achieved after the effective date. The adoption of this guidance is not expected to have a material impact on the company’s consolidated financial position or results of operations.




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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, 2010. See “Note 8 - 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 8 - 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.





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. Under the current amendment to the Agreement, Tecogen provides the company with office space and utilities at a monthly rate of $5,793.




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.




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On February 15, 2007, the company loaned Peter Westerhoff, the noncontrolling 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 noncontrolling 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 the noncontrolling interest partner a line of credit of $500,000. At December 31, 2009, $370,400 was outstanding and due to the company by the non-controlling interest partner in American DG New York, LLC under the outstanding agreements. All notes were classified in the Due from related party account in the December 31, 2009 balance sheet and were secured by the partner’s noncontrolling 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. In March 2010, the company reached an agreement with the noncontrolling interest partner to reduce his debt by a non-cash amount of $124,111 in return for a decrease in the noncontrolling interest partner’s economic position by 5%. The result of these transactions appears as “Ownership changes to noncontrolling interests” in the accompanying consolidated statement of stockholder’s equity for the year ended December 31, 2010. In September 2010, the company loaned an additional $135,000 to the noncontrolling partner by signing an eighteen month note agreement earning interest at 12% per annum. At December 31, 2010, $52,432 was outstanding and due to the company under the combination of the above and is recorded under “Due from related party” in the accompanying balance sheet.





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.





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, 2010, the company had drawn $2,400,000 of the revolving line of credit recorded as “Due to related party” in the accompanying balance sheet.




On January 4, 2010, the company entered into an agreement with Nettlestone Enterprises Limited (formerly known as Codale Ltd.), whereby Nettlestone Enterprises Limited provided 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, when the company forms a new subsidiary, Nettlestone Enterprises Limited will be entitled to an equity interest in such subsidiary equal to 10% of the equity thereof. In July 2010, the company established EuroSite Power to introduce the company’s On-Site Utility solution into the European market and Nettlestone Enterprises Limited invested $5,000 in exchange for 5 million shares in EuroSite Power.





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 December 31, 2010 and 2009, respectively, and the company has determined that its long-lived assets for those periods are recoverable.





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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 cumulative amount of rebates applied to the cost of construction was $451,603 and $214,653 as of December 31, 2010 and 2009, respectively.





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 company’s historic volatility over a period deemed reflective of future volatility over the expected life of the option grant. The average expected life is estimated using the simplified method for “plain vanilla” options. 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 2010.





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The company is able to participate in the demand response market and receive payments due to the availability of its 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. The company also receives grants and incentives from state organizations and natural gas companies for its installed energy systems.  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 reduction of electricity usage or the increase in electricity production during periods of peak usage throughout a utility territory. The revenue recognized from demand response activity was $106,928 and $17,830 for the years ended December 31, 2010 and 2009, respectively.





Other revenue represents various types of ancillary activities for which the company engages from time to time such as 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, 2010, there was no deferred income tax asset on our books. We recorded a valuation allowance of $4,955,090 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.





The tax years 2005 through 2008 remain open to examination by major taxing jurisdictions to which the company is 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. The company is currently not under examination by the Internal Revenue Service or any other jurisdiction for any tax years. The company did not recognize any interest and penalties associated with unrecognized tax benefits in the accompanying financial statements. The company would record any such interest and penalties as a component of interest expense. The company does not expect any material changes to the unrecognized benefits within 12 months of the reporting date.





Results of Operations for the Years Ended December 31, 2010 and December 31, 2009





Fiscal 2010 Compared with Fiscal 2009





Revenues





Revenues in 2010 were $5,634,765 compared to $5,763,827 for the same period in 2009, a decrease of $129,062 or 2.2%. The decrease in revenue was due to a decrease in our turn-key installation projects and other revenue that in 2010 decreased to $591,021 compared to $1,130,839, for the same period in 2009 due to fewer construction projects. Our core On-Site Utility energy revenues in 2010 increased to $5,043,744 compared to $4,632,988 for the same period in 2009, an increase of $410,756 or 8.9%, due to additional energy systems added to the fleet notwithstanding the fact that energy revenues were affected 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 of energy 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.





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During 2010, we were operating 76 energy systems at 42 locations in the Northeast, representing 5,250 kW of installed electricity plus thermal energy, compared to 62 energy systems at 36 locations, representing 4,210 kW of installed electricity plus thermal energy for the same period in 2009. 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 2010 were $4,493,327 compared to $4,677,323 for the same period in 2009, a decrease of $183,996 or 3.9%. Included in the cost of sales was depreciation expense of $867,923 in 2010, compared to $788,885 for the same period in 2009.





Our cost of sales for our core On-Site Utility business consists primarily of fuel required to operate our energy systems that decreased by 3.8% as a percentage of revenue in 2010, compared to the same period in 2009. Our cost of sales also includes the cost of maintenance of our systems which decreased by 1.8% as a percentage of revenue in 2010, compared to the same period in 2009. During 2010, our gross margins were 20.3% compared to 18.9% for the same period in 2009, 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 37.0% in 2010 compared to 31.4% for the same period in 2009.





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 2010 were $1,487,040 compared to $1,546,743 for the same period in 2009, a decrease of $59,703 or 3.9%. Those expenses include non-cash compensation expense related to the issuance of restricted stock and option awards to our employees.





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 2010 were $602,597 compared to $850,975 for the same period in 2009, a decrease of $248,378 or 29.2%. The decrease in our selling expenses was primarily due to the decrease 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 2010 were $733,504 compared to $642,858 for the same period in 2009, an increase of $90,646 or 14.1%. The increase in our engineering expenses was primarily due to additional consulting engineering costs to operate and expand our fleet of energy systems.





Loss from Operations





The loss from operations in 2010 was $1,681,703 compared to $1,954,072 for the same period in 2009. The decrease in the operating loss was primarily due to the decrease in bad debt expense related to three of our On-Site Utility sites. Our non-cash compensation expense related to the issuance of restricted stock and option awards to our employees was $228,736 in 2010, compared to $286,844 for the same period in 2009.





Other Income (Expense), Net





Our other income (expense), net, in 2010 was $14,065 compared to $366,359 for the same period in 2009. Other income (expense), net, includes interest income, interest expense and other items. Interest and other income was $51,385 in 2010 compared to $71,185 for the same period in 2009. The decrease was primarily due to lower yields on our invested funds. Interest expense was $125,131 in 2010 compared to $437,544 for the same period in 2009, due to less interest paid on our convertible debenture issued in 2006 because of conversions.




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Provision for Income Taxes





Our provision for state income taxes in 2010 was $14,730 compared to $7,450 for the same period in 2009. 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 $197,505 in 2010 compared to $202,684 for the same period in 2009. 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 2010, the company made a distribution of $302,598 to the noncontrolling interest partner based on his interest percent ownership in each site.





Liquidity and Capital Resources





Consolidated working capital at December 31, 2010 was $1,974,594, compared to $4,132,378, at December 31, 2009. Included in working capital were cash, cash equivalents and short-term investments of $3,921,054 at December 31, 2010, compared to $3,828,143 at December 31, 2009. The decrease in working capital was a result of additional funds raised during the year, offset by cash needed to fund operations and the use of a revolving line of credit.





Cash used by operating activities was $862,280 in 2010 compared to $648,816 for the same period in 2009. The company's short and long-term receivables balance, including unbilled revenue, increased to $796,315, in 2010 compared to $665,319 at December 31, 2009, using $188,572 of cash. The increase was due to increased revenue and timing of collections during the year. Amount due to the company from related parties, decreased to $52,432 in 2010 compared to $370,400 at December 31, 2009, providing $193,857 of cash. The decrease was due to the decrease in debt by our noncontrolling interest partner as a result of paying down his note. Our inventory increased to $487,724 in 2010 compared to $379,303 at December 31, 2009, using $108,421 of cash. Our prepaid and other current assets decreased to $86,089 in 2010 compared to $104,119 at December 31, 2009, providing $9,504 of cash.





Accounts payable decreased to $482,917 in 2010, compared to $740,474 at December 31, 2009, using $257,557 of cash. The decrease in accounts payable was due to the timing of payments for projects built early in 2010. Our accrued expenses and other current liabilities including accrued interest expense decreased to $370,774 in 2010 compared to $453,536 at December 31, 2009, using $24,274 of cash, since the accrual for future interest payments was no longer needed. Our due to related party increased to $2,560,720 in 2010, compared to $17,531 at December 31, 2009, providing $2,543,189 of cash. As of December 31, 2010, the company had drawn $2,400,000 of the revolving line of credit provided to the company by John N. Hatsopoulos, the company’s Chief Executive Officer.





During 2010, 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 $5,771,223 for purchases and installation of energy systems and received $451,603 in rebates and incentives. The company’s short-term investments provided $678,921 of cash as our funds invested in certificates of deposits matured and converted into cash. The company's financing activities provided $6,726,414 of cash in 2010 from the sale of common stock, issuance and exercise of common stock warrants and stock options, sale of subsidiary common stock and proceeds from related party line of credit, offset by distributions to our noncontrolling interest partner, convertible debenture transaction costs and payments on capital lease obligations.





At December 31, 2010, the company’s commitments included a lease for a plotter with a remaining balance of $15,427 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.





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, 2010, the company had drawn $2,400,000 of the revolving line of credit recorded as “Due to related party” in the accompanying balance sheet.





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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 2011. Beyond March 31, 2012, 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.





Seasonality




The majority of our heating systems sales are in the winter and the majority of our chilling systems sales are in the summer.




Inflation





We 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. Our customers benefit from a reduction in their current energy bills without the capital costs and risks associated with owning and operating a CHP or chiller system. Inflation will cause an increase in the rates charged by conventional utility suppliers, and since we bill our customers based on the electric utility rates, our pricing will increase in tandem and positively affect our revenue. However, inflation might cause both our investment and cost of goods sold to increase, therefore lowering our return on investment and depressing our gross margins.




Off Balance Sheet Arrangements




The company has no material off balance sheet arrangements.





Item 7A. Quantitative and Qualitative Disclosures About Market Risk.





Not applicable.





Item 8. Financial Statements and Supplementary Data.





The information required by this item is included in Item 15 of this Annual Report on Form 10-K.





Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.





None.




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Item 9A. 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 weaknesses 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. At the present time, our management has decided that, considering the employees involved and the control procedures in place, there are risks associated with the above, but the potential benefits of adding additional employees to mitigate these weaknesses do not justify the expenses associated with such increases. Management will continue to evaluate the above weaknesses, and as the company grows and resources become available, the company plans to take the necessary steps in the future to remediate the weaknesses.





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.





Changes in Internal Control over Financial Reporting:





In connection with the evaluation referred to in the foregoing paragraph, we have made changes in our internal controls over financial reporting during the period ended December 31, 2010. We hired a consultant to review existing controls and review recent updates and changes to the company’s documentation to ensure that any process or control changes are properly identified and documented, including updating the company’s existing risk matrix. The engagement included the creation of testing plans based upon the current state of processes and key controls and the identification of areas for process improvements and documentation updates. The company has already implemented many of the recommended processes.





Report of Management on Internal Control over Financial Reporting:





The management of the company is responsible for establishing and maintaining adequate internal control over financial reporting in accordance with the Exchange Act. Management conducted an evaluation of our internal control over financial reporting based on the framework and criteria established in Internal Control—Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion of this evaluation. Based on this evaluation, management concluded that the company’s internal control over financial reporting was not effective as of December 31, 2010.





The company had 14 active full-time employees as of December 31, 2010. The company currently does not have personnel with a sufficient level of accounting knowledge, experience and training in the selection, application and implementation of generally acceptable accounting principles as it relates to complex transactions and financial reporting requirements. The company also has a small number of employees dealing with general controls over information technology security and user access. This constitutes a material weakness in financial reporting. At this time, management has decided that considering the employees involved and the control procedures in place, there are risks associated with the above, but the potential benefits of adding additional employees to mitigate these weaknesses, does not justify the expenses associated with such increases. Management will continue to evaluate the above weaknesses.





The company reported in previous periods the lack of segregation of duties as a material weakness in financial reporting. The company hired a consultant to review its existing controls and propose changes to the company’s procedures to proper segregation of duties. Based on the consultant’s recommendation, the company has put procedures in place and has trained additional personnel to mitigate the risk. Management believes the previous weakness in financial reporting due to the lack of segregation of duties has been remediated.




24




Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our Disclosure Controls or our internal control over financial reporting will prevent or detect all error and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Further, because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Projections of any evaluation of controls effectiveness to future periods are subject to risks. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.





This Annual Report on Form 10-K does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this Annual Report on Form 10-K.





Item 9B.  Other Information.





None.




25




PART III




Item 10. Directors, Executive Officers and Corporate Governance.




The information required by Item 10 is incorporated by reference to the our definitive Proxy Statement for our 2011 annual meeting of shareholders, or our Proxy Statement, which will be filed not later than 120 days after the end of our fiscal year.





Item 11. Executive Compensation.




The information required by Item 11 is incorporated by reference to the Proxy Statement, which will be filed not later than 120 days after the end of our fiscal year.





Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.




The information required by Item 12 is incorporated by reference to the Proxy Statement, which will be filed not later than 120 days after the end of our fiscal year.





Item 13.  Certain Relationships and Related Transactions, and Director Independence.





The information required by Item 13 is incorporated by reference to the Proxy Statement, which will be filed not later than 120 days after the end of our fiscal year.





Item 14.  Principal Accountant Fees and Services.




The information required by Item 14 is incorporated by reference to the Proxy Statement, which will be filed not later than 120 days after the end of our fiscal year.




26




PART IV




Item 15.  Exhibits and Financial Statement Schedules.




(a)
Index To Financial Statementsand Financial Statements Schedules:




Report of Independent Registered Public Accounting Firm





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





Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009





Consolidated Statements of Operations for the years ended December 31, 2010 and December 31, 2009





Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2010 and December 31, 2009





Consolidated Statements of Cash Flows for the years ended December 31, 2010 and December 31, 2009





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.




27




(b)
Exhibits




ExhibitNumber

Description3.1

Certificate of Incorporation, as amended and restated December 9, 2009 (incorporated by reference to Exhibit 3.1 to the registrant’s Form S-3, as amended, originally filed with the SEC on December 23, 2009).3.2

By-laws, as amended and restated August 31, 2009 (incorporated by reference to Exhibit 3.2 to the registrant’s Form S-3, as amended, originally filed with the SEC on December 23, 2009).4.1

Form of Warrant (incorporated by reference to Exhibit 4.1 to the registrant’s Form 10-SB, as amended, originally filed with the SEC on November 2, 2006).10.1*

American Distributed Generation Inc. 2001 Stock Incentive Plan (incorporated by reference to Exhibit 10.3 to the registrant’s Form 10-SB, as amended, originally filed with the SEC on November 2, 2006).10.2*

2005 Stock Incentive Plan (incorporated by reference to Exhibit A to our definitive proxy statement for the 2008 Annual Meeting of shareholders originally filed with the SEC on April 29, 2008).10.3

Facilities, Support Services and Business Agreement with Tecogen Inc. (incorporated by reference to Exhibit 10.5 to the registrant’s Form 10-SB, as amended, originally filed with the SEC on November 22, 2006. Confidential treatment has been granted for portions of this document. The confidential portions have been omitted and have been filed separately, on a confidential basis, with the SEC).10.4

Amendment to Facilities, Support Services and Business Agreement with Tecogen Inc. dated April 1, 2008 (incorporated by reference to Exhibit 10.5 to the registrant’s Form 10-Q, filed with the SEC on May 14, 2008, for the quarter ended March 31, 2008).10.5

Amendment No. 2 to Facilities, Support Services and Business Agreement with Tecogen Inc. dated May 15, 2008 (incorporated by reference to Exhibit 10.7 to the registrant’s Form 10-K, originally filed, filed with the SEC on March 20, 2009).10.6

Amendment No. 3 to Facilities, Support Services and Business Agreement with Tecogen Inc. dated January 2, 2009 (incorporated by reference to Exhibit 10.8 to the registrant’s Form 10-K, originally filed, filed with the SEC on March 20, 2009).10.7

Operating Agreement of American DG New York LLC (incorporated by reference to Exhibit 10.6 to the registrant’s Form 10-SB, as amended, originally filed with the SEC on November 22, 2006).10.8

Form of Energy Purchase Agreement (incorporated by reference to Exhibit 10.6 to the registrant’s Form 10-SB, as amended, originally filed with the SEC on November 2, 2006).10.9

Form of Subscription Agreement for private placement of common stock for American Distributed Generation Inc. (incorporated by reference to Exhibit 10.12 to the registrant’s Amendment No. 1 to Form S-3, originally filed with the SEC on January 13, 2010).10.10

Restricted Stock Purchase Agreement with Charles T. Maxwell dated February 20, 2007 (incorporated by reference to Exhibit 10.13 to the registrant’s Form S-3, as amended, originally filed with the SEC on December 23, 2009).10.11

Form of 8% Senior Convertible Debenture Due 2011 (incorporated by reference to Exhibit 10.7 to the registrant’s Form 10-SB, as amended, originally filed with the SEC on November 2, 2006).10.12

Form of Subscription Agreement for private placement of common stock, February 2007 (incorporated by reference to Exhibit 10.15 to the registrant’s Amendment No. 1 to Form S-3, originally filed with the SEC on January 13, 2010).10.13

Form of Warrant to purchase shares of common stock, dated February 24, 2009, entered into between the company and Daniel Barnett (incorporated by reference to Exhibit 4.1 to the registrant’s current Form 8-K, originally filed with the SEC on February 26, 2009).10.14

Form of Subscription Agreement for private placement of common stock, April 2009 (incorporated by reference to Exhibit 10.1 to the registrant’s current Form 8-K, originally filed with the SEC on April 27, 2009).




28




10.15

Form of Subscription Agreement for private placement of common stock, July 2009 (incorporated by reference to Exhibit 10.1 to the registrant’s current Form 8-K, originally filed with the SEC on July 27, 2009).10.16

Form of Subscription Agreement for private placement of common stock, October 2009 (incorporated by reference to Exhibit 10.19 to the registrant’s Amendment No. 1 to Form S-3, originally filed with the SEC on January 13, 2010).10.17

Warrant Agreement with Hayden IR dated October 1, 2009 (incorporated by reference to Exhibit 10.20 to the registrant’s Amendment No. 1 to Form S-3, originally filed with the SEC on January 13, 2010).10.18

Revolving Line of Credit Agreement with John N. Hatsopoulos (incorporated by reference to Exhibit 10.1 to the registrant’s current Form 8-K, originally filed with the SEC on December 17, 2009).10.19

Amendment No. 4 to Facilities, Support Services and Business Agreement with Tecogen Inc. dated January 2, 2010 (incorporated by reference to Exhibit 10.23 to the registrant’s Annual Report on Form 10-K, originally filed with the SEC on March 31, 2010).10.20

Letter to John N. Hatsopoulos dated February 22, 2010, as amended, (incorporated by reference to Exhibit 10.24 to the registrant’s Annual Report on Form 10-K, originally filed with the SEC on March 31, 2010).10.21

Subscription Agreement, dated as of July 12, 2010, by and between the company and Nettlestone Enterprises Limited (incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K dated July 12, 2010).10.22

Warrant Agreement for Common Stock of EuroSite Power Inc., dated as of July 12, 2010, by and between the company and Nettlestone Enterprises Limited (incorporated by reference to Exhibit 10.2 to the company’s Current Report on Form 8-K dated July 12, 2010).10.23

Form of Common Stock Purchase Agreement for EuroSite Power Inc. dated July 2010 (incorporated by reference to Exhibit 10.1 to the company’s Quarterly Report on Form 10-Q dated November 10, 2010).10.24#

Warrant Agreement with AIM Capital Corporation d/b/a Barry Kaplan Associates dated January 15, 2011.14.1

Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 to the registrant’s Form 10-SB, as amended, originally filed with the SEC on November 2, 2006).16.1

Letter on change in certifying accountant (incorporated by reference to Exhibit 16.1 to the company’s Current Report on Form 8-K/A dated September 24, 2010).21.1#

List of subsidiaries.23.1#

Consent of McGladrey & Pullen, LLP.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 (Furnished herewith).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).





29




99.5

Slide show presentation (incorporated by reference to Exhibit 99.1 to registrant’s Current Report on Form 8-K dated June 15, 2010).





#
Filed herewith.


*
Management contract or compensatory plan or arrangement.





30




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. HATSOPOULOSChief Executive Officer(Principal Executive Officer)By:
/s/ ANTHONY S. LOUMIDISChief 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

March 31, 2011George N. Hatsopoulos/s/ John N. Hatsopoulos

Chief Executive Officer (Principal Executive Officer)

March 31, 2011John N. Hatsopoulos

& Director/s/ Anthony S. Loumidis

Chief Financial Officer (Principal Financial

March 31, 2011Anthony S. Loumidis

and Accounting Officer)/s/ Earl R. Lewis

Director

March 31, 2011Earl R. Lewis/s/ Charles T. Maxwell

Director

March 31, 2011Charles T. Maxwell/s/ Deanna M. Petersen

Director

March 31, 2011Deanna M. Petersen/s/ Francis A. Mlynarczyk

Director

March 31, 2011Francis A. Mlynarczyk




31





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 sheet of American DG Energy Inc. and subsidiaries (collectively, the “Company”) as of December 31, 2010 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year 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 audit.




We conducted our audit 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 audit provides a reasonable basis for our opinion.




In our opinion, the consolidated financial statements referred to above, present fairly, in all material respects, the financial position of the Company at December 31, 2010 and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.




/s/ MCGLADREY & PULLEN, LLPBoston, MassachusettsMarch 31, 2011





F-1





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 the related consolidated statements of operations, stockholders’ equity, and cash flows for the year 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 audit.




We conducted our audit 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 audit provides a reasonable basis for our opinion.




In our opinion, the consolidated financial statements referred to above, present fairly, in all material respects, the financial position of the Company at December 31, 2009, and the results of their operations and their cash flows for the year 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, MassachusettsMarch 31, 2010





F-2





AMERICAN DG ENERGY INC. AND SUBSIDIARIES


CONSOLIDATED BALANCE SHEETS





2010


2009ASSETSCurrent assets:Cash and cash equivalents

$
3,921,054


$
3,149,222Restricted cash


65,790



-Short-term investments


-



678,921Accounts receivable, net


661,435



518,379Unbilled revenue


117,846



146,940Due from related party


52,432



370,400Inventory


487,724



379,303Prepaid and other current assets


86,089



104,119Total current assets


5,392,370



5,347,284Property, plant and equipment, net


14,362,444



9,502,346Accounts receivable, long-term


17,034



-TOTAL ASSETS


19,771,848



14,849,630LIABILITIES AND STOCKHOLDERS’ EQUITYCurrent liabilities:Accounts payable


482,917



740,474Accrued expenses and other current liabilities


370,774



453,536Due to related party


2,560,720



17,531Capital lease obligations


3,365



3,365Total current liabilities


3,417,776



1,214,906Long-term liabilities:Convertible debentures


-



5,320,000Warrant liability


676,603



-Capital lease obligations, long-term


6,730



10,095Total liabilities


4,101,109



6,545,001Stockholders’ equity:American DG Energy Inc. shareholders’ equity:Common stock, $0.001 par value; 100,000,000 shares authorized; 45,598,029 and 37,676,817 issued and outstanding at December 31, 2010 and December 31, 2009, respectively


45,598



37,677Additional paid-in capital


28,905,660



19,725,793Accumulated deficit


(14,147,113
)


(12,239,110
)Total American DG Energy Inc. stockholders’ equity


14,804,145



7,524,360Noncontrolling interest


866,594



780,269Total stockholders’ equity


15,670,739



8,304,629TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

$
19,771,848


$
14,849,630




See accompanying notes to consolidated financial statements




F-3





AMERICAN DG ENERGY INC. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF OPERATIONS




2010


2009RevenuesEnergy revenues

$
5,043,744


$
4,632,988Turnkey & other revenues


591,021



1,130,8395,634,765



5,763,827Cost of salesFuel, maintenance and installation


3,625,404



3,888,438Depreciation expense


867,923



788,8854,493,327



4,677,323Gross profit


1,141,438



1,086,504Operating expensesGeneral and administrative


1,487,040



1,546,743Selling


602,597



850,975Engineering


733,504



642,8582,823,141



3,040,576Loss from operations


(1,681,703
)


(1,954,072
)Other income (expense)Interest and other income


51,385



71,185Interest expense


(125,131
)


(437,544
)Change in fair value of warrant liability


59,681



-(14,065
)


(366,359
)Loss before income taxes


(1,695,768
)


(2,320,431
)Provision for state income taxes


(14,730
)


(7,450
)Consolidated net loss


(1,710,498
)


(2,327,881
)Less: Income attributable to the noncontrolling interest


(197,505
)


(202,684
)Net loss attributable to American DG Energy Inc.


(1,908,003
)


(2,530,565
)Net loss per share - basic and diluted

$
(0.04
)

$
(0.07
)Weighted average shares outstanding -basic and diluted


43,525,374



35,554,303




See accompanying notes to consolidated financial statements




F-4





AMERICAN DG ENERGY INC. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY




American DG Energy Inc. ShareholdersCommonStock


Common


AdditionalAccumulated


$0.001


Stock


Paid-In


NoncontrollingTotal


Deficit


Par Value


Subscription


Capital


InterestBalance at December 31, 2008

$
4,221,784


$
(9,708,545
)


34,034


$
(35,040
)

$
12,614,332


$
1,317,003Distributions to noncontrolling interest


(333,704
)


-



-



-



-



(333,704
)Ownership changes to noncontrolling interest, Note 8


(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
)


-



-



-



202,684Balance at December 31, 2009


8,304,629



(12,239,110
)


37,677



-



19,725,793



780,269Distributions to noncontrolling interest


(302,598
)


-



-



-



-



(302,598
)Ownership changes to noncontrolling interest


(124,111
)


-



-



-



-



(124,111
)Conversion of convertible debenture tocommon stock, net of costs


5,356,932



-



6,403



-



5,350,529



-Sale of common stock, net of costs


1,286,855



-



852



-



1,286,003



-Sale of subsidiary common stock, net of costs


2,226,019



-



-



-



1,910,490



315,529Stock based compensation expense


228,736



-



-



-



228,736



-Exercise of stock options


54,775



-



166



-



54,609



-Exercise of warrants


350,000



-



500



-



349,500



-Net (loss) income


(1,710,498
)


(1,908,003
)


-



-



-



197,505Balance at December 31, 2010

$
15,670,739


$
(14,147,113
)


45,598


$
-


$
28,905,660


$
866,594




See accompanying notes to consolidated financial statements




F-5





AMERICAN DG ENERGY INC. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS




2010


2009CASH FLOWS FROM OPERATING ACTIVITIES:Net loss

$
(1,908,003
)

$
(2,530,565
)Income attributable to noncontrolling interest


197,505



202,684Adjustments to reconcile net loss to net cash used in operating activities:Depreciation and amortization


911,125



806,776Provision for losses on accounts receivable


57,576



299,994Amortization of deferred financing costs


8,526



8,526Change in fair value of warrant liability


(59,681
)


-Stock-based compensation


228,736



286,844Changes in operating assets and liabilities(Increase) decrease in:Restricted cash


(65,790
)


-Accounts receivable and unbilled revenue


(188,572
)


168,294Due from related party


193,857



(308,183
)Inventory


(108,421
)


(23,451
)Prepaid and other current assets


9,504



50,476Increase (decrease) in:Accounts payable


(257,557
)


469,622Accrued expenses and other current liabilities


(24,274
)


69,196Due to related party


143,189



(149,029
)Net cash used in operating activities


(862,280
)


(648,816
)CASH FLOWS FROM INVESTING ACTIVITIES:Purchases of property and equipment


(5,771,223
)


(3,939,384
)Sale of short-term investments


678,921



82,693Net cash used in investing activities


(5,092,302
)


(3,856,691
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from issuance of warrants


736,284



372,815Proceeds from exercise of warrants


350,000



35,000Proceeds from sale of common stock, net of costs


1,286,855



5,878,079Proceeds from sale of subsidiary common stock, net of costs


2,226,019



-Proceeds from exercise of stock options


54,775



22,406Proceeds from related party line of credit


2,400,000



-Convertible debenture transaction costs


(21,556
)


-Principal payments on capital lease obligations


(3,365
)


(3,365
)Distributions to noncontrolling interest


(302,598
)


(333,704
)Net cash provided by financing activities


6,726,414



5,971,231Net increase in cash and cash equivalents


771,832



1,465,724Cash and cash equivalents, beginning of the year


3,149,222



1,683,498Cash and cash equivalents, end of the year

$
3,921,054


$
3,149,222Supplemental disclosures of cash flows information:Cash paid during the year for:Interest

$
114,116


$
448,645Income taxes

$
31,329


$
35,460Non-cash investing and financing activities:Conversion of convertible debentures to common stock

$
5,320,000


$
555,000Forgiveness of related party debt in exchange for reductionin noncontrolling interest

$
124,111


$
-





See accompanying notes to consolidated financial statements




F-6




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 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, 2010, we had installed energy systems, representing approximately 5,250 kilowatts, or kW, 44.0 million British thermal units, or MMBtu’s, of heat and hot water and 2,820 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.





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, 2010, we had 76 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, its 51% joint venture, American DG New York, LLC, or ADGNY, and its 86.1% owned subsidiary EuroSite Power Inc., or EuroSite Power. 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 64% economic interest in ADGNY as of December 31, 2010.





In July 2010 the company invested $45,000 in exchange for 45 million shares of EuroSite Power, a newly established corporation. The investment gave the company a controlling financial interest in EuroSite Power, whose business focus is to introduce the On-Site Utility solution into the European market. Also in July 2010, Nettlestone Enterprises Limited, invested $5,000 in exchange for 5 million shares in EuroSite Power. During the year ended December 31, 2010 EuroSite Power raised approximately $2,261,000 in a private placement by selling 2,261,000 shares of EuroSite Power common stock to accredited investors at $1.00 per share. As of December 31, 2010 the company owns an 86.1% interest in EuroSite Power and has consolidated EuroSite Power into its financial statements in accordance with Generally Accepted Accounting Principles, or GAAP.





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, 2010. See “Note 8 - Related parties” for further discussion.




F-7





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.




We have experienced total net losses since inception of approximately $14.1 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, 2010 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, 2010 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 March 31, 2012. Beyond March 31, 2012, 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 2010, we raised $4,965,775 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 2012 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





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. The company had no such arrangements in fiscal years 2010 and 2009.




F-8





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 arrangements in fiscal years 2010 and 2009.





The company is able to participate in the demand response market and receive payments due to the availability of its 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. The company also receives grants and incentives from state organizations and natural gas companies for its installed energy systems. 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 reduction of electricity usage or the increase in electricity production during periods of peak usage throughout a utility territory. The revenue recognized from demand response activity was $106,928 and $17,830 for the years ended December 31, 2010 and 2009, respectively.





Other revenue represents various types of ancillary activities for which the company engages from time to time such as 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, 2010, the company had a balance of $3,736,844 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 $67,000 and $51,821 at December 31, 2010 and December 31, 2009 respectively. Included in accounts receivable are amounts from four major customers accounting for approximately 30% and 22% of total accounts receivable for the years ended December 31, 2010 and December 31, 2009, respectively. There were sales to four customers accounting for approximately 28% and 26% of total sales for the years ended December 31, 2010 and December 31, 2009, 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, 2010 and December 31, 2009, there were no reserves or write-downs recorded against inventory.





F-9





Accounts Payable





Included in accounts payable are amounts due to five major vendors accounting for approximately 67% and 66% of total accounts payable for the years ended December 31, 2010 and December 31, 2009, respectively. Purchases from four vendors accounted for approximately 72% and 67% of total purchases for the years ended December 31, 2010, and December 31, 2009, respectively.




Supply Concentrations




All of the company’s cogeneration unit purchases for the years ended December 31, 2010 and 2009 were from one vendor (see “Note 8 - 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.




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 December 31, 2010 and 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 cumulative amount of rebates applied to the cost of construction was $451,603 and $214,653 as of December 31, 2010 and 2009, respectively.




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 company’s historic volatility over a period deemed reflective of future volatility over the expected life of the option grant. The average expected life is estimated using the simplified method for “plain vanilla” options. 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.




F-10





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, 2010 and December 31, 2009.





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, 2010, we excluded 3,161,625 anti-dilutive shares resulting from exercise of stock options, warrants and unvested restricted stock, and 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. 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, 2010 and 2009 does not differ from the reported loss.





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.





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 9 - Fair value measurements.”





Recent Accounting Pronouncements




In June 2009, 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 became effective for the company beginning in January 2010. The adoption of this guidance did not have a material effect on the company’s 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 became effective for us January 1, 2011 and is not expected to have a material effect on the company’s consolidated financial position or results of operations.




F-11





In January 2010, FASB issued an amendment to the accounting for fair value measurements and disclosures. This amendment details additional disclosures on fair value measurements, requires a gross presentation of activities within a Level 3 rollforward, and adds a new requirement to the disclosure of transfers in and out of Level 1 and Level 2 measurements. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. This amendment was effective as of January 1, 2010, with an exception for the gross presentation of Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The adoption of the effective provisions of this amendment did not have a material impact on the company’s consolidated financial position or results of operations. The adoption of the remaining provisions is not expected to have a material impact on the company’s consolidated financial position or results of operations.





In March 2010, FASB reached a consensus to issue an amendment to the accounting for revenue arrangements under which a vendor satisfies its performance obligations to a customer over a period of time, when the deliverable or unit of accounting is not within the scope of other authoritative literature, and when the arrangement consideration is contingent upon the achievement of a milestone. The amendment defines a milestone and clarifies whether an entity may recognize consideration earned from the achievement of a milestone in the period in which the milestone is achieved. This amendment is effective for fiscal years beginning on or after June 15, 2010, with early adoption permitted. The amendment may be applied retrospectively to all arrangements or prospectively for milestones achieved after the effective date. The adoption of this guidance is not expected to have a material impact on the company’s consolidated financial position or results of operations.





Note 3 — Property, plant and equipment:





Property, plant and equipment consist of the following as of December 31, 2010 and December 31, 2009:




December 31,2010


2009Energy Systems

$
12,682,708


$
8,559,132Computer equipment and software


60,760



42,531Furniture and fixtures


31,399



28,087Vehicles


117,953



37,19312,892,820



8,666,943Less — accumulated depreciation


(3,079,188
)


(2,168,063
)9,813,632



6,498,880Construction in progress


4,548,812



3,003,466$
14,362,444


$
9,502,346





Depreciation expense of property, plant and equipment totaled $911,125 and $806,776 for the years ended December 31, 2010 and December 31, 2009.




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 had not been adjusted.




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.




F-12





Note 5 — Stockholders’ equity:





Common Stock





In July 2010 the company invested $45,000 in exchange for 45 million shares and obtained controlling interest in EuroSite Power, a newly established corporation. Also in July 2010, Nettlestone Enterprises Limited invested $5,000 in exchange for 5 million shares in EuroSite Power. During the period from July to December 31, 2010, EuroSite Power raised an additional $2,261,000 in a private placement by selling 2,261,000 shares of EuroSite Power common stock to accredited investors at a price of $1.00 per share.




On July 12, 2010, the company raised $1,000,000 in a private placement of 400,000 shares of common stock at a price of $2.50 per share. The company also granted the investor a special purchase right, or warrant, regarding the company’s EuroSite Power subsidiary. The warrant grants the investor the non-assignable right but not the obligation, for a period of two years from July 12, 2010, to purchase up to 400,000 shares of the common equity of EuroSite Power at a per share purchase price of $1.00.





On December 9, 2010, the company entered into subscription agreements with selected investors for the purchase of units consisting, in the aggregate, of 500,000 shares of its common stock and warrants to purchase 500,000 shares of its common stock (see “Note 6 – Warrant liability”). The subscription agreements provided for the purchase of the units at a purchase price of $2.50 per unit, and the warrants had an exercise price of $3.25 per share of common stock. Canaccord Genuity Inc., or Canaccord, acted as placement agent, on a reasonable efforts basis, for the offering and received a placement fee equal to 6.0% of the gross proceeds of the offering (excluding any consideration that may be paid in the future upon exercise of the warrants).  The company also reimbursed certain expenses incurred by Canaccord in the offering. The offering was made pursuant to our shelf registration statement on Form S-3, which became effective on October 6, 2010.





The holders of common stock have the right to vote their interest on a per share basis. At December 31, 2010, there were 45,598,029 shares of common stock outstanding.





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.





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.





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. At December 31, 2010, there were 8,000 warrants outstanding and 4,000 warrants that expired unexercised.




F-13





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, providing gross proceeds to the company of $350,000.





Warrant activity for the years ended December 31, 2010 and 2009 was as follows:





WeightedAverageNumber of


Grant DateWarrants


Fair ValueOutstanding, December 31, 2008


500,000


$
0.70Granted


1,975,167



3.10Exercised


-



-Expired


(1,913,167
)


3.10Unvested, December 31, 2009


562,000



0.95Granted


500,000



3.25Exercised


(500,000
)


0.70Expired


(4,000
)


2.98Unvested, December 31, 2010


558,000


$
3.22





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 1,134,500 shares of restricted stock outstanding as of December 31, 2010. 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 761,250 at December 31, 2010.




During the years ended December 31, 2010 and December 31, 2009, the company recognized employee non-cash compensation expense of $228,736 and $286,844, respectively, related to the issuance of stock options and restricted stock. At December 31, 2010 there were 175,250 unvested shares of restricted stock outstanding. At December 31, 2010 the total compensation cost related to unvested restricted stock awards and stock option awards not yet recognized is $525,089. This amount will be recognized over the weighted average period of 4.91 years.





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.





In 2010, the company granted nonqualified options to purchase 290,000 shares of the common stock to seven employees and two directors at prices ranging between $2.76 and $3.45 per share. Each of those options has a vesting schedule of four years and expires in five years. The fair value of all options issued in 2010 was $359,408, with a weighted average grant date fair value of $1.24 per option.




F-14





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




2010


2009Stock options and restricted stock awardsExpected life

5 years


5 yearsRisk-free interest rate


1.80
%


0.37
%Expected volatility


50.97
%


48.34
%





Stock option activity for the years ended December 31, 2010 and 2009 was as follows:





Exercise


Weighted


WeightedPrice


Average


Average


AggregateNumber of


Per


Exercise


Remaining


IntrinsicCommon Stock Options

Options


Share


Price


Life


ValueOutstanding, December 31, 2008


2,329,000


$
0.07-$1.95


$
0.68


6.95 years


$
3,017,920Granted


19,000


$
1.82-$2.95



2.18Exercised


(31,250
)

$
0.70-$0.90



0.72Canceled


-



-



-Expired


(8,750
)

$
0.70-$0.90



0.87Outstanding, December 31, 2009


2,308,000


$
0.07-$2.95


$
0.70


5.94 years


$
5,203,740Exercisable, December 31, 2009


1,421,000






$
0.50






$
3,488,400Vested and expected to vest, December 31, 2009


2,308,000






$
0.70






$
5,203,740Outstanding, December 31, 2009


2,308,000


$
0.07-$2.95


$
0.70


5.94 years


$
5,203,740Granted


330,000


$
2.76-$3.45



2.96Exercised


(169,625
)

$
0.07-$1.82



0.35Canceled


(40,000
)

$
2.89



2.89Expired


-



-



-Outstanding, December 31, 2010


2,428,375


$
0.07-$3.45


$
0.99


5.11 years


$
4,379,711Exercisable, December 31, 2010


1,395,125






$
0.58






$
3,058,719Vested and expected to vest, December 31, 2010


2,428,375






$
0.99






$
4,379,711





The aggregate intrinsic value of options outstanding as of December 31, 2010 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.




The company did not make any restricted stock grants to employees in 2010 or 2009. Restricted stock activity for the years ended December 31, 2010 and 2009 was as follows:




WeightedNumber of


AverageRestricted


Grant DateStock


Fair ValueUnvested, December 31, 2008


720,000


$
0.77Granted


-



-Vested


(240,875
)


0.75Forfeited


(39,000
)


0.70Unvested, December 31, 2009


440,125



0.79Granted


-



-Vested


(216,875
)


0.76Forfeited


(48,000
)


0.70Unvested, December 31, 2010


175,250


$
0.84





F-15





Note 6 – Warrant liability





In connection with the subscription agreement that the company entered into on December 9, 2010 (see “Note 5 – Stockholders’ equity”), the company issued warrants for the purchase of 500,000 shares of its common stock. The warrants have an exercise price of $3.25 and are exercisable for five years commencing six months after the closing of the offering and expire on December 14, 2015.





The warrants contain both a right to obtain stock upon exercise, or a Call, and a right to settle the warrants for cash upon the occurrence of certain events, or a Put. Generally, the Put provisions allow the warrant holders liquidity protection; the right to receive cash equal to the value of the remaining unexercised portion of the warrants in certain situations where the holders would not have a means of readily selling the shares issuable upon exercise of the warrants (e.g., where there would no longer be a significant public market for the company’s common stock). Specifically, the Put rights would be triggered upon the occurrence of a Fundamental Transaction as defined in the agreement. Pursuant to the agreement, in the case of a Fundamental Transaction the warrant holders would receive a cash settlement in an amount equal to the value of obtained by using the  Black Scholes Option Pricing Model obtained from the “OV” function on Bloomberg L.P. using (i) a price per share of Common Stock equal to the Volume-Weighted Average Price of the Common Stock for the Trading Day immediately preceding the date of consummation of the applicable Fundamental Transaction, (ii) a risk-free interest rate corresponding to the U.S. Treasury rate for a period equal to the remaining term of this Warrant as of the date of consummation of the applicable Fundamental Transaction and (iii) an expected volatility equal to the lesser of (1) the thirty (30) day volatility obtained from the “HVT” function on Bloomberg L.P. determined as of the end of the Trading Day immediately following the public announcement of the applicable Fundamental Transaction or (2) 70%.These warrants are classified as liabilities pursuant to the FASB guidance contained in ASC 480.  Changes in the fair value of the warrant liabilities are recorded in the accompanying statement of operations (see “Note 9 – Fair value measurements”).





Note 7 — 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 $41,323 and $39,075 to the Retirement Plan for the years ended December 31, 2010 and 2009, respectively.





Note 8 — Related parties





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.





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. Under the current amendment to the Agreement, Tecogen provides the company with office space and utilities at a monthly rate of $5,793.




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 noncontrolling 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 noncontrolling 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 the noncontrolling interest partner a line of credit of $500,000. At December 31, 2009, $370,400 was outstanding and due to the company by the non-controlling interest partner in American DG New York, LLC under the outstanding agreements. All notes were classified in the Due from related party account in the December 31, 2009 balance sheet and were secured by the partner’s noncontrolling 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. In March 2010, the company reached an agreement with the noncontrolling interest partner to reduce his debt by a non-cash amount of $124,111 in return for a decrease in the noncontrolling interest partner’s economic position by 5%. The result of these transactions appears as “Ownership changes to noncontrolling interests” in the accompanying consolidated statement of stockholder’s equity for the year ended December 31, 2010. In September 2010, the company loaned an additional $135,000 to the noncontrolling partner by signing an eighteen month note agreement earning interest at 12% per annum. At December 31, 2010, $52,432 was outstanding and due to the company under the combination of the above and is recorded under “Due from related party” in the accompanying balance sheet.




F-16





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.





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, 2010, the company had drawn $2,400,000 of the revolving line of credit recorded as “Due to related party” in the accompanying balance sheet.




On January 4, 2010, the company entered into an agreement with Nettlestone Enterprises Limited (formerly known as Codale Ltd.), whereby Nettlestone Enterprises Limited provided 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, when the company forms a new subsidiary, Nettlestone Enterprises Limited will be entitled to an equity interest in such subsidiary equal to 10% of the equity thereof. In July 2010, the company established EuroSite Power to introduce the company’s On-Site Utility solution into the European market and Nettlestone Enterprises Limited invested $5,000 in exchange for 5 million shares in EuroSite Power.





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.





Note 9 — 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. We currently do not have any Level 2 financial assets or liabilities.




F-17





Level 3— Unobservable inputs reflecting management’s own assumptions about the input used in pricing the asset or liability. As of December 31, 2010, the company has classified the warrants with put and call rights as Level 3 (see “Note 6 – Warrant liability”). The Company estimated that the fair value of the warrants using a Black-Scholes option pricing model under various probability-weighted outcomes which take into consideration the protective, but limited, cash-settlement feature of the warrants. At issuance, the following average assumptions were assigned to the varying outcomes: expected volatility of 57%, risk free interest rate of 2.08, expected life of five years and no dividends. The Company estimated that the fair value of the warrants at December 31, 2010 using this same model with the following assumptions average assumptions assigned to the varying outcomes: expected volatility of 55%, risk free interest rates of 2.01%, expected lives of five years and no dividends. As of December 31, 2010, the financial liabilities held by the company and measured at fair value on a recurring basis (which consist solely of the warrant liability) were $676,603. The following table summarizes the activity for the period:





Warrant LiabilitiesValue at issuance, December 14, 2010

$
736,284Fair value adjustment at December 31, 2010


(59,681
)Balance at December 31, 2010

$
676,603





Note 10 — Income taxes:





A reconciliation of federal statutory income tax provision to the company’s actual provision for the years ended December 31, 2010 and December 31, 2009, respectively, are as follows:




2010


2009Benefit at federal statutory tax rate

$
(649,000
)

$
(860,000
)Unbenefited operating losses


649,000



860,000Provision for state income taxes


14,730



7,450Income tax provision

$
14,730


$
7,450





The components of net deferred tax assets recognized in the accompanying balance sheets at December 31, 2010 and December 31, 2009, respectively, are as follows:





2010


2009Net operating loss carryforwards

$
5,896,090


$
4,676,000Accrued expenses and other


316,000



312,000Depreciation


(1,257,000
)


(764,000
)4,955,090



4,224,000Valuation allowance


(4,955,090
)


(4,224,000
)Net deferred tax asset

$
-


$
-





As of December 2010, the company has federal and state loss carryforwards of approximately $15,800,000 and $12,900,000, respectively, which may be used to offset future federal and state taxable income, expiring at various dates through 2030. Included in these net operating losses is $667,000 of excess stock compensation deductions, related to the amount of tax deductions on restricted stock, in excess of book compensation expense. 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, 2010.




F-18




Note 11 — 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 $5,793.




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, 2010.





Payments2011


5,2212012


5,2212013


5,221Total lease payments


15,663Less: Amount representing interest


(5,568
)Present value of minimum lease payments

$
10,095





At December 31, 2010, the company’s commitments included a lease for a plotter with a remaining balance of $15,427 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.





Note 12 — Subsequent events:





On January 15, 2011, the company signed an investor relations consulting agreement with AIM Capital Corporation d/b/a Barry Kaplan Associates, or AIM Capital, for a period of twelve months. In connection with that agreement the company granted AIM Capital a warrant to purchase 30,000 shares of the company’s common stock at an exercise price per share of $2.69, with a four year vesting period and an expiration date of January 15, 2016. The company received no other consideration from the issuance of the warrants.





On February 22, 2011, John N. Hatsopoulos purchased 25,000 shares of EuroSite Power common stock from an accredited investor at a price of $1.00 per share and George N. Hatsopoulos purchased 25,000 shares of EuroSite Power common stock from the same accredited investor at a price of $1.00 per share.





F-19