Item 1. Business
General
American DG Energy Inc. (“American DG Energy”, the “company”, “ADGE”, “we”, “our” or “us”) distributes 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 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 (“DG” or often referred 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 successfully implemented by others in large industrial installations over 10 Megawatts (“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 level will drive our near term growth and penetration into our target market. The company maintains a web site at www.americandg.com, but our website is not a part of this annual report.
The company was incorporated as a Delaware corporation on July 24, 2001 to install. As of December 31, 2007, we had installed energy systems, representing approximately 3,645 kW (kilowatts), 29.2 MMBtu’s (million British thermal units) of heat and hot water and 600 tons of cooling. Kilowatt (kW) is a measure of electricity generated, MMBtu is a measure of heat generated and a ton is a measure of cooling generated. On December 14, 2007, the company was presented with a report by the EPA which states that the high efficiency of the company’s CHP projects produced an estimated 7,400 metric tons of carbon equivalents less than typical separate heat and power, resulting in emissions reductions equivalent to planting 2,006 acres of forest or removing the emissions of 1,337 automobiles.
We believe that our primary near-term opportunity for DG energy and equipment sales is where commercial electricity rates exceed $0.12 per kWh, which is predominantly in the Northeast and California. These areas represent approximately 15 percent of the U.S. commercial power market, with electricity revenues in excess of $20 billion per year (see Figure 1. on page 6). 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 in 2000 detailed the prospective CHP market in the commercial and institutional sectors(1) and in the industrial sectors(2). These data sets were used to estimate the CHP market potential in the 100kW to 1 MW size range. These target market segments 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 $19.0 billion.
(1) 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) The Market and Technical Potential for Combined Heat and Power in the Industrial Sector; Prepared for the Energy Information Administration; Prepared by ONSITE SYCOM Energy Corporation; January 2000
We believe that the largest number of potential DG users in the United Stated 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. 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 United States 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 percent efficient(3) 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.
(3) Energy Information Administration, Voluntary Reporting of Greenhouse Gases, 2004, Section 2, Reducing Emissions from Electric Power, Efficiency Projects: Definitions and Terminology, page 20
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 the cogeneration of electricity and thermal energy services (a practice also known as 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 (“PURPA”), 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 US utilities for two decades. Several factors caused utilities’ capital spending to fall drastically, including well publicized cost overruns at nuclear plants, an end to guaranteed financial returns on costly new facilities, and growing uncertainty over which power plant technologies to pursue. Recently, investors have become increasingly reluctant to support the risks of the long-term construction projects required for new conventional generating and distribution facilities.
Because of these factors, electricity reserve margins declined, and the reliability of service began 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 distributed generation. These fundamental shifts in economics and requirements are key to the emerging opportunity for distributed generation equipment and services.
The Role of Distributed Generation
Distributed generation, 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.
Distributed generation, or 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, 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.
The growing importance of DG as a key component of our future energy supply is underscored by the establishment of a Distributed Energy Program within the U.S. Department of Energy. The DOE has stated its position on this issue as follows:
“...there are two problems at the root of the current power crunch. There is not always enough power generation available to meet peak demand, and existing transmission lines cannot carry all of the electricity needed by consumers.... Distributed Energy resources are the power of choice for providing customers with reliable energy supplies.... These Distributed Energy products and services use natural gas and renewable energy and will be easily interconnected into the nation’s infrastructure for the generation of electricity. Furthermore, our Program works to encourage the expanded use of Distributed Energy technologies in applications with the right combination and occurrence of electrical and thermal demand...”
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 distributed generation 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 percent) versus less than 33 percent for the existing power grid.
· Rapid adaptation to changing demand requirements; e.g., weeks, not years to add new generating capacity where and when it is needed.
· Ability to by-pass transmission line and substation bottlenecks in congested service areas.
· Avoidance of site and right-of-way issues affecting large-scale power generation and distribution projects.
· Clean operation, in the case of natural gas fired reciprocating engines using microprocessor combustion controls and low-cost exhaust catalyst technology developed for automobiles, producing exhaust emissions well below the world’s strictest regional environmental standards (e.g., Southern California).
· Rapid economic paybacks for equipment investments, often three to five years when compared to existing utility costs and technologies.
· Relative insensitivity to fuel prices due to high overall efficiencies achieved with cogeneration of electricity and thermal energy services, including the use of waste heat to operate absorption type air conditioning systems (displacing electric-powered cooling capacity at times of peak summer demand).
· Reduced vulnerability of multiple de-centralized small-scale generating units compared to the risk of major outages from natural disasters or terrorist attacks against large central-station power plants and long distance transmission lines.
· Ability to remotely monitor, control and dispatch energy services on a real-time basis using advanced switchgear, software, microprocessor and Internet modalities. Through our onsite 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 distributed generation 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. Distributed generation 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 U.S. Environmental Protection Agency (“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 Distributed Generation 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 kWh, which is predominantly in the Northeast and California. These areas represent approximately 15 percent of the U.S. commercial power market, with electricity revenues in excess of $20 billion per year (see Figure 1. on page 6). 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 Combined Heat and Power market analysis reports sponsored by the Energy Information Administration in 2000 detailed the prospective CHP market in the commercial and institutional sectors(4) and in the industrial sectors(5). These data sets were used to estimate the CHP market potential in the 100 kW to 1 MW size range. These target market segments 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 $19.0 billion.
(4) 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) 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
As shown in the graph below, there are substantial variations in the electric rates paid by commercial and institutional customers throughout the U.S. In high-cost regions, monthly payments for energy services supplied by on-site DG projects yield rapid paybacks (e.g. often 3-5 years) on an investment in our systems. An additional 15% of commercial sector electricity, representing annual revenues of $14 billion, is sold at rates between $0.085 and $0.12 per kWh as shown on the graph below. Although paybacks on DG projects would be less rapid in such regions, future rate increases are expected to improve DG economics.
Figure 1.
The DG Market Opportunity
U.S. Commercial/Institutional Electric Rate Profile
Source: U.S. Energy Information Administration Data [2002]
Business Model
We are a distributed generation 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 percent efficiency (versus less than 33 percent 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 capture the engine heat. As of December 31, 2007, we had 47 energy systems operational.
To date, each of our installations runs in conjunction with the electric utility grid and requires standard interconnection approval from the local utility. Our customers use both our energy system and the electric utility grid for their electricity requirements. We typically supply the first 20% to 60% of the building’s electricity requirements while the remaining electricity is supplied by the electric utility grid. Our customers are contractually bound to use the energy we supply.
To date, the price that we have charged our customers is set in our customer contracts at a discount to the price of the building’s local electric utility. For the 20% to 60% portion of the customer’s electricity that we supply, the customer realizes immediate savings on its electric bill. In addition to electricity, we sell our customers the heat and hot water at the same price they were previously paying or at a discount equivalent to their discount from us on electricity. Our air conditioning systems are also priced at a discount so that the customer realizes overall cost savings from the installation.
Since we own and operate the energy systems and since our customers have no investment in the units, our customers benefit from no captal 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 DG 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 (i.e., boilers, etc.)
o Alternative Energy Equipment (i.e., 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 DG equipment, we will install, maintain, finance, own and operate complete on-site DG 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 distributed generation without the need for retaining specialized in-house staff with skills unrelated to their core business. Customers benefit from our On-Site Utility in a number of ways:
· Guaranteed lower price for energy
· Only pay for the energy they use
· No capital costs for equipment, engineering and installation
· No equipment operating costs for fuel and maintenance
· Immediate cash flow improvement
· Significant green impact by the reduction of carbon produced
· No staffing, operations and equipment responsibility
Our customers pay us for energy produced on site at a rate that is a certain percentage below the rate at which the utility companies provide them electrical and natural gas services. We measure the actual amount of electrical and thermal energy produced, and charge our customers accordingly. We agree to install, operate, maintain and repair our energy systems at our sole cost and expense. We also agree to obtain any necessary permits or regulatory approvals at our sole expense. Our agreements are generally for a term of 15 years, renewable for two additional five years terms upon the mutual agreement of the parties.
In regions where high electricity rates prevail, such as the Northeast, monthly payments for DG 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 percent of the total heating value of fuel supplied to our DG 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:
The example reflects an American DG Energy investment of $345,000 with a payback in 4 years or a 25% internal rate of return (IRR). The example also reflects a 2% of expected annual increase in energy costs that should occur over the 15-year period.
Since inception in 2001 and through December 31, 2007, the company has entered into 42 agreements, for the supply of on-site energy services, primarily with healthcare, housing facilities, apartments and athletic facilities in the Northeast.
Energy Producing Products
We typically offer cogeneration units sized to produce 75 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 percent (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.
In August 2005, we began offering our customers a “turn-key” option whereby we provide equipment, systems engineering, installation, interconnect approvals, on-site labor and startup services needed to bring the complete DG 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 through out 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 in healthcare, hospitality, large residential, athletic facilities and certain industrial sites. This includes national accounts and other customer groups having a common set of energy requirements at multiple locations.
Our energy offering is translated into direct financial gain for our clients, and is best appreciated by senior management. These clients recognize the gain in cash flow, the increase in net income and the preservation of capital we offer. As such, our energy sales are focused on reaching these decision makers. Additionally, we have benefited with increased sales and maintenance support through our joint venture, called American DG NY LLC, with AES-NJ Cogen Co., 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 DG 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.
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, LIPA in Long Island, New York, Public Service Gas and Electric in New Jersey, and NSTAR in Massachusetts.
Engine manufacturers sell DG units that range in size from a few kilowatts to many megawatts 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 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 (“ESCO’s”) that offer related services. These companies include Siemens, Honeywell and Johnson Controls. In general, these companies seek large, diverse projects for electric demand reduction for campuses that include building lighting and controls, and electricity (in rare occasions) or cooling. Because of their overhead structures, these companies often solicit large projects and stay away from individual properties. Since we focus on smaller projects for energy supply, we are well suited to work in tandem with these companies when the opportunity arises.
There are also a few local emerging cogeneration developers and contractors that are attempting to offer services similar to ours. To be successful, they will need to have the proper experience in equipment and technology, installation contracting, equipment maintenance and operation, site economic evaluation, project financing, and energy sales plus the capability to cover a broad region.
Material Contracts
In January 2007, we extended our 2006 Facilities, Support Services and Business Agreement with Tecogen to provide us with certain office and business support services for a period of one year, renewable annually by mutual agreement. Under the 2007 business agreement we revised the rent allocation whereby Tecogen provides the company with office space and utilities at a flat rate of $2,294 per month. We also share personnel support services with Tecogen. We are allocated our share of the cost of the personnel support services based upon the amount of time spent by such support personnel while working on our behalf. To the extent Tecogen is able to do so under its current plans and policies, Tecogen includes us and our employees in several of its insurance and benefit programs. The costs of these programs are charged to us on an actual cost basis.
Under this agreement, we receive pricing based on a volume discount if we purchase cogeneration and chiller products from Tecogen. For certain sites, we hire Tecogen to service our Tecogen chiller and cogeneration products.
We have sales representation rights to Tecogen’s products and services. In New England, we have exclusive sales representation rights to their cogeneration products. We have granted Tecogen sales representation rights to our on-site utility energy service in California.
Government Regulation
We are not subject to extensive government regulation. We are required to file for local construction permits (electrical, mechanical and the like) and utility interconnects, and we must make various local and state filings related to environmental emissions. Our expenditures for regulatory compliance are not material.
Effective March 7, 2007, there were new air quality and permitting requirements in New Jersey that required adding emission control equipment on our already existing 18 cogeneration systems operating in New Jersey and any new energy systems we install in that state. In order to interpret and comply with the new emission requirements, we retained an independent environmental engineering consultant to review our existing installations, as well as all new construction. Of the existing 18 systems previously identified, a total of 9 systems in two locations were affected by the new regulations. The first location at a hospital has been outfitted with commercially available dry catalyst technology, all permits have been obtained and the project has returned to full capacity and is generating revenue. The second location at a large housing complex was in the final permitting phase at year-end 2007 and we expect a successful return of those units during the second quarter of 2008. The estimated lost revenue from those two locations was approximately $499,000 during 2007.
Employees
As of December 31, 2007, we employed eight active full-time employees and three part-time employees. We believe that our relationship with our employees is satisfactory. None of our employees are represented by a collective bargaining agreement.
Item 1A.
Item 1A. Risk Factors
The following risk factors should be considered carefully in addition to the other information contained in this report. This report contains forward-looking statements. Forward-looking statements relate to future events or our future financial performance. 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. “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business,” as well as other sections in this report, discuss some of the factors that could contribute to these differences.
The forward-looking statements made in this report relate only to events as of the date on which the statements are made. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events.
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.
We have incurred losses, and these losses may continue.
We have incurred losses in each of our fiscal years since inception. Losses continued to incure in 2007. There is no assurance that profitability will be achieved in the near term, if at all.
Because unfavorable utility regulations make the installation of our systems more difficult or economic, 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 distributed generation, 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-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 onsite 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.
Effective March 7, 2007, there were new air quality and permitting requirements in New Jersey that required adding emission control equipment on our already existing 18 cogeneration systems operating in New Jersey and any new energy systems we install in that state. In order to interpret and comply with the new emission requirements, we retained an independent environmental engineering consultant to review our existing installations, as well as all new construction. Of the existing 18 systems previously identified, a total of 9 systems in two locations were affected by the new regulations. The first location at a hospital has been outfitted with commercially available dry catalyst technology, all permits have been obtained and the project has returned to full capacity and is generating revenue. The second location at a large housing complex was in the final permitting phase at year-end 2007.
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 distributed generation 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 distributed generation. 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.
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 four 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 intend to 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 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.
Our common stock is quoted on the OTC Bulletin Board which may have an unfavorable impact on our stock price and liquidity.
Our common stock is quoted on the OTC Bulletin Board. The OTC Bulletin Board is a significantly more limited market than the New York Stock Exchange or NASDAQ system. The quotation of our shares on the OTC Bulletin Board may result in a less liquid market available for existing and potential stockholders to trade shares of our common stock, could depress the trading price of our common stock and could have a long-term adverse impact on our ability to raise capital in the future. Trading in stock quoted on the OTC Bulletin Board is often thin and characterized by wide fluctuations in trading prices, due to many factors that may have little to do with our operations or business prospects. Moreover, the OTC Bulletin Board is not a stock exchange, and trading of securities on the OTC Bulletin Board is often more sporadic than the trading of securities listed on a quotation system or a stock exchange.
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.
We have never paid dividends on our capital stock, and we do not anticipate paying any cash dividends in the foreseeable future.
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.
Because we do not intend to pay cash dividends, our stockholders will receive no current income from holding our stock.
We have never paid or declared any cash dividends. 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.
Trading of our common stock is restricted by the SEC’S “penny stock” regulations which may limit a stockholder’s ability to buy and sell our stock.
The Securities and Exchange Commission (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 Securities and Exchange Commission 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.
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 are effective to give reasonable assurance that the information required to be disclosed by our company in reports that we file under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported as when required. However, there is a lack of segregation of duties at the company due to the small number of employees dealing with general administrative and financial matters. Furthermore, the company did not have personnel with an appropriate level of accounting knowledge, experience and training in the selection, application and implementation of GAAP as it relates to complex transactions and financial reporting requirements. 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.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Our headquarters are located in Waltham, Massachusetts and consist of 1,199 square feet of office and storage space that are leased from Tecogen. The lease expires on March 31, 2009. We believe that our facilities are appropriate and adequate for our current needs.
Item 3.
Item 3. Legal Proceedings
We are not currently a party to any other 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.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
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 Over-the-Counter Bulletin Board, under the symbol “ADGE”. Our stock started trading on November 8, 2007. During the period ended December 31, 2007, the high price was $1.25 and the low price was $0.83 as reported by the Over-the-Counter Bulletin Board (“OTC”). OTC market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions and may not necessarily represent actual transactions.
Holders
As of December 31, 2007, the number of holders of record of the common stock was 107.
Dividends
We have never declared or paid any cash dividends on shares of our capital 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
Set forth below is information regarding common stock issued, warrants issued and stock options granted by the company during fiscal year 2007. Also included is the consideration, if any, we received and information relating to the section of the Securities Act of 1933, as amended (the “Securities Act”), or rule of the SEC, under which exemption from registration was claimed.
Common Stock and Warrants
On March 8, 2007, the company raised $3,004,505 in a private placement of 4,292,150 shares of common stock exclusively to accredited investors, representing 16.5% of the total shares then outstanding, at a price of $0.70 per share. Included in those shares are 750,000 shares to Maxwell C.B. Ward, 30,000 shares to Giordano Venzi, 15,000 shares to Fermin Alou, 20,000 shares to Edmond Viedma, 500,000 shares to Christian Levett, 357,150 shares to Berger van Berchem & Co Ltd., 10,000 shares to Athanasios Kyranis, 2,150,000 shares to Nettlestone Enterprises Limited, 100,000 shares to Paris and Aliki Nikolaidis (through the exercise of warrants) and 360,000 shares to Martin C.B. Mellish. Prior to this transaction the company had 26,017,250 shares of common stock outstanding. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Section 4(2) and/or Regulation D thereunder.
On April 30, 2007, the company raised $1,120,000 in a private placement of 1,600,000 shares of common stock exclusively to accredited investors, representing 5.2% of the total shares then outstanding, at a price of $0.70 per share. Included in those shares are 1,500,000 shares to Brevan Howard Asset Management, 50,000 shares to Ernest Aloi through the exercise of warrants, 25,000 to Nancy Schachter A/C 7379-1230 through the exercise of warrants and 25,000 to Adam Schachter A/C 7378-8270 through the exercise of warrants. Prior to this transaction the company had 31,046,400 shares of common stock outstanding. All of such investors were accredited investors, and such transactions were exempt from registration under the Securities Act under Section 4(2) and/or Regulation D thereunder.
On June 30, 2007, the company issued to Joseph P. Kennedy 100,000 shares of common stock through an option exercise at $0.07 per share, representing 0.3% of the total shares then outstanding. Prior to this transaction the company had 32,646,400 shares of common stock outstanding.
On October 2, 2007, Michael H. Carstens, a holder of the company’s 8% Convertible Debenture elected to convert $50,000 of the outstanding principal amount of the debenture into 59,524 shares of common stock. Prior to this transaction the company had 32,746,400 shares of common stock outstanding.
Restricted Stock Grants
On February 20, 2007, the company made restricted stock grants to employees, directors and consultants by permitting them to purchase an aggregate of 737,000 shares of common stock, representing 2.4% of the total shares then outstanding at a price of $0.001 per share. Prior to this transaction the company had 30,309,400 shares of common stock outstanding.
Such transactions were exempt from registration under the Securities Act under Section 4(2), Regulation D and/or Rule 701 thereunder.
Stock Options
In 2007 the company granted nonqualified options to purchase 1,156,000 shares of the common stock to 7 employees at $0.90 per share. Of those shares 1,130,000 have a vesting schedule of 10 years and 26,000 shares have a vesting schedule of 4 years. The grant of such options was exempt from registration under Rule 701 under the Securities Act.
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.
Rule 144
Under Rule 144 under the Securities Act, as recently amended, in general, a person who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned shares of our Common Stock for more than six months but less than one year would be entitled to sell an unlimited number of shares. Sales under Rule 144 during this time period are still subject to the requirement that current public information is available about us for at least 90 days prior to the sale. After such person beneficially owns shares of our Common Stock for a period of one year or more, the person is entitled to sell an unlimited number of shares without complying with the public information requirement or any of the other provisions of Rule 144. As of February 15, 2008, all of our shares of Common Stock held by non-affiliates were eligible for resale under amended Rule 144.
Item 6.
Item 6. Selected Financial Data
Not applicable.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operation
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 report. Some of the information contained in this discussion and analysis or set forth elsewhere in this report, including information with respect to our plans and strategy for our business, includes forward-looking statements that involve risks and uncertainties. You should review the “Risk Factors” section beginning on page 10 of this report 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.
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 customer’s 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 customer’s local energy utility that month. Our revenues commence as new energy systems become operational. As of December 31, 2007, we had 47 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. 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. In certain instances, revenue from unresolved claims is recorded when, in the opinion of management, realization of such revenue is probable and can be reliably estimated, only to the extent of actual costs incurred. Otherwise, revenue from claims is recorded in the year in which such claims are resolved. Costs and estimated earnings in excess of related billings represents the excess of contract costs and profit recognized to date on the percentage-of-completion accounting method over billings to date on certain contracts. Billings in excess of related costs and estimated earnings represents the excess of billings to date over the amount of contract costs and profits recognized to date on the percentage-of-completion accounting method for certain contracts. 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 $7.4 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, 2007 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, 2007 and our ability to control certain costs, including those related to general and administrative expenses will enable us to meet our anticipated cash expenditures through January 1, 2009. Beyond January 1, 2009, 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 2007, we raised approximately $4.1 million through a private placement of our common stock and the exercise of various warrants and stock options. If we are unable to raise additional capital in 2009 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 currently have no 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. The preparation of financial statements in conformity with generally accepted accounting principles 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.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with statements and notes thereto appearing elsewhere herein.
Recent Accounting Pronouncements
In September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 establishes a common definition of fair value to be used whenever GAAP requires (or permits) assets or liabilities to be measured at fair value, and does not expand the use of fair value in any new circumstances. It also requires expanded disclosure about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. In addition, in February 2007, the FASB issued FAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115” (“FAS 159”). FAS 159 expands the use of fair value accounting but does not affect existing standards that require assets or liabilities to be carried at fair value. Under FAS 159, a company may elect to use fair value to measure most financial assets and liabilities and any changes in fair value are recognized in earnings. The fair value election is irrevocable and generally made on an instrument-by-instrument basis, even if a company has similar instruments that it elects not to measure based on fair value. Both FAS 157 and FAS 159 will be effective for the company on January 1, 2008. On February 12, 2008, the FASB issued proposed FASB Staff Position No. FAS No. 157-2, “Effective Date of FASB Statement No. 157” which defers the effective date for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually) to fiscal years beginning after November 15, 2008. The company does not expect the adoption of FAS 157 and FAS 159 will have a material impact on its consolidated financial statements in 2008.
In December 2007, the FASB issued FAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of Accounting Research Bulletin No. 51” (“FAS 160”). FAS 160 clarifies the classification in a company’s consolidated balance sheet and the accounting for and disclosure of transactions between the company and holders of noncontrolling interests. FAS 160 is effective for the company January 1, 2009. Early adoption is not permitted. The company does not expect the adoption of FAS 160 to have a material impact on its consolidated financial statements.
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. Minority interest in net assets and earnings or losses of consolidated entities are reflected in the caption “Minority interest” in the accompanying consolidated financial statements. Minority 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.
FASB Interpretation No. 46 (Revised), “Consolidation of Variable Interest Entities” (“FIN 46-R”) provides the principles to consider in determining when variable interest entities must be consolidated in the financial statements of the primary beneficiary. In general, a variable interest entity is an entity used for business purposes that either (a) does not have equity investors with voting rights or (b) has equity investors that are not required to provide sufficient financial resources for the entity to support its activities without additional subordinated financial support. FIN 46-R requires a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities or is entitled to receive a majority of the entity’s residual returns or both. A company that consolidates a variable interest entity is called the primary beneficiary of that entity. The company evaluates the applicability of FIN 46-R 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 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 related party footnotes 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, 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, 2009.
Property and Equipment and Depreciation and Amortization
Property and equipment are stated at cost. Depreciation and amortization are computed using the straight-line and accelerated methods 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 in accordance with SFAS No. 144 (SFAS 144), Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 requires the recognition of impairment of long-lived assets in the event the net book value of such assets exceeds the estimated future undiscounted cash flows attributable to such assets. If impairment is indicated, the asset is written down to its estimated fair value based on a discounted cash flow analysis. The company reviews long-lived assets for impairment annually 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. At December 31, 2007 the company determined that its long-lived assets are recoverable.
Stock-Based Compensation
Effective January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share Based Payment, or SFAS 123(R), which is a revision of SFAS No. 123 (“SFAS 123”) Accounting for Stock Based Compensation. SFAS 123(R) supersedes Accounting Principles Board (“APB”) No. 25, Accounting for Stock Issued to Employees (“APB 25”), and SFAS No. 95 Statement of Cash Flows. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.
SFAS 123(R) requires nonpublic companies that used the minimum value method in SFAS 123 for either recognition or pro forma disclosures to apply SFAS 123(R) using the prospective-transition method. As such, since we were not a public company as of the adoption date, we will continue to apply APB 25 in future periods to equity awards outstanding at the date of SFAS 123(R)’s adoption that were measured using the minimum value method.
The determination of the fair value of share-based payment awards is affected by the company’s stock price. Since inception and until November 7, 2007, since the company was not publicly traded, the company considered the sales price of common stock in private placements to unrelated third parties as a measure of the fair value of its common stock. The company started trading on November 8, 2007 therefore after such date it will use the market price of its common stock to determine fair value of share-based payment awards.
SFAS 123(R) also requires companies to utilize an estimated forfeiture rate when calculating the expense for the period, whereas, SFAS 123 permitted companies to record forfeitures based on actual forfeitures, which was our historical policy under SFAS 123. As a result, we applied an estimated forfeiture rate of 15% during 2007 in determining the expense recorded in the accompanying consolidated statement of income. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Stock-based compensation expense recognized in our financial statements in 2007 and thereafter is based on awards that are ultimately expected to vest. We evaluate the assumptions used to value our awards on a quarterly basis and if factors change and we employ different assumptions, stock-based compensation expense may differ significantly from what we have recorded in the past. If there are any modifications or cancellations of the underlying unvested securities, we may be required to accelerate, increase or cancel any remaining unearned stock-based compensation expense.
On November 10, 2005, the FASB issued FASB Staff Position SFAS 123R-3 “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.” The company has elected to adopt the alternative transition method provided the FASB Staff Position for calculating the tax effects (if any) of stock-based compensation expense pursuant to SFAS 123R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool related to the tax effects of employee stock-based compensation, and to determine the subsequent impact to the additional paid-in capital pool and the consolidated statements of operations and cash flows of the tax effects of employee stock-based compensation awards that are outstanding upon adoption of SFAS 123R.
Revenue Recognition
Revenue from energy contracts is recognized when electricity, heat, and chilled water is produced by the cogeneration systems onsite. 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. We recognize revenue that relates to multiple element contracts in accordance with EITF 00-21, Accounting for Revenue Arrangements with Multiple Deliverables. Revenue to which this guidance applies includes a contract that consists of the sale of equipment, installation, energy, and maintenance. When a sales arrangement contains multiple elements, revenue is allocated to each element based upon its relative fair value. Fair value is determined based on the price of a deliverable sold on a standalone basis.
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. In certain instances, revenue from unresolved claims is recorded when, in the opinion of management, realization of such revenue is probable and
can be reliably estimated, only to the extent of actual costs incurred. Otherwise, revenue from claims is recorded in the year in which such claims are resolved. Costs and estimated earnings in excess of related billings represents the excess of contract costs and profit recognized to date on the percentage-of-completion accounting method over billings to date on certain contracts. Billings in excess of related costs and estimated earnings represents the excess of billings to date over the amount of contract costs and profits recognized to date on the percentage-of-completion accounting method for certain contracts. 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.
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 our deferred gain and lease rights, 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. To the extent we establish a valuation allowance or increase this allowance in a period, we must include an expense within the tax provision in the consolidated statement of operations.
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, 2007, there was no deferred income tax asset on our books. We recorded a valuation allowance of $2,302,000 against the entire gross deferred income tax asset; due to uncertainties related to our ability to utilize our net operating loss carry forwards before they expire. The valuation allowance is based on our estimates of taxable income by jurisdiction in which we operate and the period over which our deferred tax assets will be recoverable. In the event that actual results differ from these estimates or we adjust these estimates in future periods we may need to establish an additional valuation allowance which could materially impact our financial position and results of operations.
Results of Operations for the Years Ended December 31, 2007 and December 31, 2006
Fiscal 2007 Compared with Fiscal 2006
Revenues
Revenues in 2007 were $5,847,020, an increase of $2,672,694 (84%) from 2006. Revenues increased primarily as a result of full year operation of our energy systems installed in 2006, new energy systems installed in 2007, a contract buyout and our turnkey installation plus business.
As of December 31, 2007, we had installed energy systems, representing approximately 3,645 kW, 29.2 MMBtu’s of heat and hot water and 600 tons of cooling. Our revenues commence as new energy systems become operational. During the first quarter of 2007, we started on a $1.6 million energy system turnkey installation plus project and in 2007 we earned $1,335,000 in revenue based on percentage of completion basis. Unlike our traditional energy sales model, in a turnkey installation plus project our revenue is earned in two methods: we perform the installation and earn revenue on a percentage of completion basis and we sell on-going operation services over an extended period of time that includes a portion of the energy savings delivered by the energy systems.
Effective March 7, 2007, there were new air quality and permitting requirements in New Jersey that required adding emission control equipment on our already existing 18 cogeneration systems operating in New Jersey and any new energy systems we install in that state. In order to interpret and comply with the new emission requirements, we retained an independent environmental engineering consultant to review our existing installations, as well as all new construction. Of the existing 18 systems previously identified, a total of 9 systems in two locations were affected by the new regulations. The first location at a hospital has been outfitted with commercially available dry catalyst technology, all permits have been obtained and the project has returned to full capacity and is generating revenue. The second location at a large housing complex was in the final permitting phase at year-end 2007 and we expect a successful return of those units during the second quarter of 2008. The estimated lost revenue from those two locations was approximately $499,000 during 2007.
Cost of Sales
Cost of sales, including depreciation, in 2007 was $4,583,568, an increase of $1,843,033 (67%) from 2006. Included in the cost of sales was depreciation expense of $363,233 in 2007, compared with $316,515 in 2006; the increase is due to additional sites coming on line, costs related to a contract buyout and costs incurred on the turnkey project referred to above. Our cost of sales consist of the natural gas fuel required to operate our energy systems, construction, contract buyout costs, the cost of maintenance, and minimal communications costs. The cost of natural gas is the largest component of our cost of sales and changes in natural gas prices can affect our margins. During 2007, our gross margins increased to 22% compared to 14% in 2006, as a result of our efforts to increase the efficiency of our operations and our growing chiller business.
Operating Expenses
Our general and administrative expenses consist of executive staff, accounting and legal expenses, office space, audit services, general insurance and other administrative expenses. In 2007, our general and administrative expenses were $1,423,775 compared to $1,646,134 in 2006. The decrease in the general and administrative expenses of $222,359 was primarily due to a lower non-cash compensation expense of $330,335 in 2007, compared with $664,134, which was offset by an increase in general insurance and additional SEC filing fees in 2007.
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 effort consisted of trade shows, print literature, media relations and event driven direct mail. During 2007, our selling expenses were $415,545 compared to $331,916 in 2006. The increase in the selling expenses was primarily due to the addition of a part time employee and a new salesperson.
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. During 2007 our engineering expenses were $329,139 compared to $308,921 in 2006. The increase was due to the addition of a new engineer.
Operating Income
Operating income in 2007 was a loss of $905,007 as compared with a loss of $1,853,180 in 2006. The improvement was due to the increased sales, gross profit improvement and a decrease in non-cash compensation expense.
Other Income (Expense), Net
The company reported other expense, net, of $213,050 in 2007 and other expense, net, of $200,327 in 2006. Other income (expense), net, includes interest income, interest expense, and other items. Interest and other income was $271,950 in 2007 compared to $110,953 in 2006. The increase was primarily due to additional funds raised and invested. Interest expense is related to the convertible debenture issued in 2006 and was $485,000 in the 2007 compared to $311,280 in 2006.
Provision for Income Taxes
The company did not have a tax provision or benefit in 2007 and 2006, respectively, since both periods had losses.
Minority Interest
In 2002, the company and AES-NJ Cogen Inc. of New Jersey created a limited liability company named American DG New York LLC (“ADGNY”) to develop projects in the New York and New Jersey area. The company owns 51% of ADGNY. Both partners in ADGNY share in the profits of the business. The percentage share of the profit is based on the partner’s investment in each individual project. The company’s investments in ADGNY projects have ranged from 51% to 80%. The minority interest expense represents our partner’s share of profits in the entity. On our balance sheet, minority interest represents our partner’s investment in the entity, plus its share of after tax profits less any cash distributions. The company reported minority interest of $364,833 in 2007 and $19,283 in 2006. The increase in minority interest share of their earnings is due to the overall increase in joint venture profits.
Liquidity and Capital Resources
Consolidated working capital at December 31, 2007 was $5,555,696, compared with $3,375,980 at December 31, 2006. Included in working capital were cash and cash equivalents of $5,057,482 at December 31, 2007, compared with $3,420,446 at December 31, 2006. The increase in working capital was a result of additional funds raised through a private placement of our common stock and the exercise of various warrants and stock options. Cash used by operating activities was
$1,143,080 in 2007 compared with cash used of $912,786 in 2006.
The company’s short and long-term receivables balance increased to $767,229, in 2007 from $284,398 at December 31, 2006 using $482,831 of cash, due to the accounting treatment of the sale of equipment with a three year payment schedule and an additional receivable from a turnkey project. The company’s due from related parties short and long-term increased to $570,374 in 2007 from $121,896 at December 31, 2006, using $448,478 of cash to the company due to notes issued to our minority interest partner. Our prepaid and other current assets decreased to $77,853 in 2007 providing $6,814 of cash due to the timing of insurance billings.
Accounts payable increased to $354,091 in 2007, compared with $115,125 at December 31, 2006 providing 238,965 of cash due to additional construction in process. Our accrued expenses and other current liabilities including accrued interest expense decreased to $339,740 in 2007 from $420,302 at December 31, 2006 using $80,561 of cash. The decrease was due to deferred revenue recognized together with audit and legal expenses that were accrued in relationship to the company’s public offering. During the period we accrued an additional $120,500 of expense related to future interest payments.
During 2007, 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 a net of $1,121,419 for purchases of energy systems. The company’s financing activities provided $3,901,535 of cash, net of costs, in 2007 primarily from the sale of common stock and warrants.
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. However, as we continue to grow our business by adding more energy systems, our cash requirements will increase. 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 2008. Beyond January 1, 2009 we may need to raise additional capital through a debt financing or an equity offering to meet our operating and capital needs.
Seasonality
The majority of our heating systems sales are in the winter and the majority of our chilling systems sales are in the summer.
Off Balance Sheet Arrangements
The company has no material off balance sheet arrangements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Not applicable.
Item 8.
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.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A(T).
Item 9A(T). Controls and Procedures
Management’s evaluation of disclosure controls and procedures:
Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e); collectively, “Disclosure Controls”) as of the end of the period covered by this annual report (the “Evaluation Date”) have concluded that as of the Evaluation Date, our Disclosure Controls were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC, and that material information relating to our company and any consolidated
subsidiaries is made known to management, including our Chief Executive Officer and Chief Financial Officer, particularly during the period when our periodic reports are being prepared to allow timely decisions regarding required disclosure.
This annual report 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 temporary rules of the SEC that permit the company to provide only management’s report in this annual report.
Changes in internal controls:
In connection with the evaluation referred to in the foregoing paragraph, we have identified no change in our internal control over financial reporting that occurred during the year ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Inherent Limitations on Effectiveness of Controls:
There is a lack of segregation of duties at the company due to the small number of employees dealing with general administrative and financial matters and general controls over information technology security and user access. This constitutes a material weakness in financial reporting. Furthermore, the company did not have personnel with an appropriate level of accounting knowledge, experience and training in the selection, application and implementation of GAAP as it relates to complex transactions and financial reporting requirements. At this time, management has decided that, considering the employees involved and the control procedures in place, the risks associated with such lack of segregation are insignificant, and the potential benefits of adding additional employees to clearly segregate duties do not justify the expenses associated with such increases. Management will continue to evaluate this segregation of duties.
The company had 11 employees as of December 31, 2007. Only one of those individuals is in the finance function, other than the Chief Financial Officer. This individual is responsible for receiving and distributing cash, billing, processing transactions, recording journal entries, reconciling accounts, and preparing the financial statements and related disclosures. He also has check signing authority, for transactions under $2,000. As a result, there is the potential for this individual to knowingly or unknowingly misappropriate assets or misstate our financial statements. To mitigate these risks, the company has put in place procedures where the Chief Executive Officer, the President and the Chief Financial Officer have check signing authority. In addition they review and approve all material contracts, transactions and related journal entries. They are also responsible for reviewing and approving monthly financials and related reconciliations, budget to actual comparisons and the information required to be disclosed by the company in all reports we have and will file under the Exchange Act.
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.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
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 2008 annual meeting of shareholders (“Proxy Statement”), which will be filed not later than 120 days after the end of our fiscal year.
Item 11.
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.
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.
Item 13. Certain Relationships and Related Transactions
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.
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.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) Index To Financial Statements and Financial Statements Schedules:
Report of Independent Registered Public Accounting Firm Vitale Caturano & Company Ltd as of March 14, 2008
Consolidated Balance Sheets as of December 31, 2007 and December 31, 2006
Consolidated Statements of Operations for the years ended December 31, 2007 and December 31,
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2007 and December 31, 2006
Consolidated Statements of Cash Flows for the years ended December 31, 2007 and December 31,
Notes to Consolidated Financial Statements
All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions, or are inapplicable, and therefore have been omitted.
(b)
Exhibits:
Exhibit No.
Description
3.1*
Certificate of Incorporation
3.2*
By-laws
4.1*
Form of Warrant
10.1*
Audit Committee Charter
10.2*
Compensation Committee Charter
10.3*
American Distributed Generated Inc. 2001 Stock Incentive Plan
10.4#
2005 Stock Incentive Plan
10.5*+
Facilities, Support Services and Business Agreement with Tecogen Inc.
10.6*
Operating Agreement of American DG New York LLC
10.7*
Form of Energy Purchase Agreement
10.8*
Form of 8% Senior Convertible Debenture Due 2011
14.1*
Code of Business Conduct and Ethics
16.1*
Letter on change in certifying accountant
21.1*
List of subsidiaries
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
* Incorporated by reference from the registrant’s Form 10-SB, as amended, originally filed with the Securities and Exchange Commission on October 3, 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 Securities and Exchange Commission.
# Filed herewith
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 18, 2008.
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the issuer and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ GEORGE N. HATSOPOULOS
Chairman of the Board
March 18, 2008
George N. Hatsopoulos
/s/ JOHN N. HATSOPOULOS
Chief Executive Officer
March 18, 2008
John N. Hatsopoulos
/s/ ANTHONY S. LOUMIDIS
Chief Financial Officer (Principal Financial
March 18, 2008
Anthony S. Loumidis
and Accounting Officer)
/s/ BARRY J. SANDERS
President and Chief Operating Officer
March 18, 2008
Barry J. Sanders
/s/ EARL R. LEWIS
Director
March 18, 2008
Earl R. Lewis
/s/ CHARLES T. MAXWELL
Director
March 18, 2008
Charles T. Maxwell
/s/ ALAN D. WEINSTEIN
Director
March 18, 2008
Alan D. Weinstein
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, 2007 and December 31, 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2007 and December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above, present fairly, in all material respects, the financial position of American DG Energy Inc. and subsidiaries at December 31, 2007, and December 31, 2006, and the results of their operations and their cash flows for the years ended December 31, 2007, and December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standard No. 123(R), “Share-Based Payment”, effective January 1, 2006.
/s/ VITALE, CATURANO & CO., LTD.
Boston, Massachusetts
March 14, 2008
AMERICAN DG ENERGY AND SUBSISIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements
AMERICAN DG ENERGY AND SUBSISIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements
AMERICAN DG ENERGY AND SUBSISIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
See accompanying notes to consolidated financial statements
AMERICAN DG ENERGY AND SUBSISIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - The Company and Basis of Presentation:
American DG Energy Inc. (“American DG Energy”, the “company”, “ADGE” 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 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. American DG Energy has been operating as a subsidiary of American Distributed Generation Inc. since 2003, along with Tecogen Inc. (“Tecogen”). In December 2005, the Board of Directors of American Distributed Generation Inc. decided to distribute to its shareholders all of the outstanding shares of Tecogen in the form of a stock dividend. American DG Energy merged with American Distributed Generation Inc. and the company then changed its name to American DG Energy Inc. As of December 31, 2007, we had installed energy systems, representing approximately 3,645 kW (kilowatt), 29.2 MMBtu’s (million British thermal units) of heat and hot water and 600 tons of cooling. Kilowatt (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 customer’s 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 customer’s local energy utility that month. Our revenues commence as new energy systems become operational. As of December 31, 2007, we had 47 energy systems operational.
We have experienced total net losses since inception of approximately $7.4 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, 2007 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, 2007 and our ability to control certain costs, including those related to general and administrative expenses will enable us to meet our anticipated cash expenditures through January 1, 2009. Beyond January 1, 2009 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 2007 we raised approximately $4.1 million through a private placement of our common stock and the exercise of various warrants and stock options. If we are unable to raise additional capital in 2009 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 currently have no 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. The preparation of financial statements in conformity with generally accepted accounting principles 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.
Note 2 - Summary of significant accounting policies:
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of American DG Energy, its wholly owned subsidiary American DG Energy, Inc. and its 51% joint venture, American DG New York, LLC (NY, LLC), and Hermany Energy, LLC (Hermany), of which NY, LLC is a 50% member (referred to hereafter as “Investee entities”), after elimination of all material intercompany accounts, transactions and profits. Investee entities in which American DG Energy, Inc. owns directly or indirectly 50% or more of the membership interests have been consolidated as a result of the company’s control over the investee entities. All significant intercompany accounts and transactions are eliminated. Minority interests in the net assets and earnings or losses of consolidated Investee entities are reflected in the caption “Minority interest” in the accompanying consolidated financial statements. Minority interest adjusts the consolidated results of operations to reflect only American DG Energy’s share of the earnings or losses of the consolidated Investee entities. Upon dilution of ownership below 50%, the accounting method is adjusted to the equity or cost method of accounting, as appropriate, for subsequent periods. In January 2006, the company entered into an agreement with Hermany Farms to liquidate the entity. The assets and liabilities were distributed in accordance with the terms of the limited liability company agreement. The process to liquidate Hermany was completed on December 29, 2006.
The company evaluates the applicability of Financial Accounting Standards Board (“FASB”) Interpretation No. 46 (Revised) “Consolidation of Variable Interest Entities” (FIN 46(R)) 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 (VIE), as defined by FIN 46R; 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, 2007. See Note 8 for further discussion.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles 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 onsite. 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. We recognize revenue that relates to multiple element contracts in accordance with EITF 00-21, Accounting for Revenue Arrangements with Multiple Deliverables. Revenue to which this guidance applies includes a contract that consists of the sale of equipment, installation, energy, and maintenance. When a sales arrangement contains multiple elements, revenue is allocated to each element based upon its relative fair value. Fair value is determined based on the price of a deliverable sold on a standalone basis.
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. In certain instances, revenue from unresolved claims is recorded when, in the opinion of management, realization of such revenue is probable and can be reliably estimated, only to the extent of actual costs incurred. Otherwise, revenue from claims is recorded in the year in which such claims are resolved. Costs and estimated earnings in excess of related billings represents the excess of contract costs and profit recognized to date on the percentage-of-completion accounting method over billings to date on certain contracts. Billings in excess of related costs and estimated earnings represents the excess of billings to date over the amount of contract costs and profits recognized to date on the percentage-of-completion accounting method for certain contracts. 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.
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.
Accounts receivable
The company maintains receivable balances primarily with customers located throughout New York and New Jersey. The company reviews its customer’s 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.
Accounts receivable are presented net of an allowance for doubtful collections of $35,589 and $57,000 at December 31, 2007 and 2006 respectively. Included in accounts receivable are amounts from four major customers accounting for approximately 59% and 56% of total accounts receivable for the years ended December 31, 2007 and December 31, 2006, respectively. There were sales to three customers accounting for approximately 41% and 46% of total sales for the years ended December 31, 2007 and December 31, 2006, respectively.
Accounts payable
Included in accounts payable are amounts due to five major vendors accounting for approximately 58% and 66% of total accounts payable for the years ended December 31, 2007 and December 31, 2006, respectively. Purchases from four vendors accounted for approximately 47% and 51% of total cost of goods sold for the years ended December 31, 2007, and December 31, 2006, respectively.
Supply Concentrations
Approximately 100% of the company’s cogeneration unit purchases for the year ended December 31, 2007 and 2006 were from one vendor (see Note 8). 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 minority interest holder or maintained by Tecogen. The company believes there are sufficient alternative vendors available to ensure a constant supply of 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. The company uses 10 years for the majority of the assets such as its energy systems and 3-5 years for computer equipment, software, office furniture etc. Repairs and maintenance are expensed as incurred.
Stock Based Compensation
Effective January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share Based Payment, or SFAS 123(R), which is a revision of Statement No. 123 (“SFAS 123”) Accounting for Stock Based Compensation. SFAS 123(R) supersedes Accounting Principles Board (“APB”) No. 25, Accounting for Stock Issued to Employees (“APB 25”), and amends Financial Accounting Standards Board (“FASB”) Statement No. 95 Statement of Cash Flows. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.
SFAS 123(R) requires nonpublic companies that used the minimum value method in SFAS 123 for either recognition or pro forma disclosures to apply SFAS 123(R) using the prospective-transition method. As such, since we were not a public company as of the adoption date, we will continue to apply APB 25 in future periods to equity awards outstanding at the date of SFAS 123(R)’s adoption that were measured using the minimum value method.
During the year ended December 31, 2007 the company recognized employee non-cash compensation expense of $330,335 related to the issuance of restricted stock and stock options. At December 31, 2007 there were 948,875 unvested
shares of restricted stock outstanding. The total compensation cost related to unvested restricted stock awards not yet recognized is $834,538. This amount will be recognized over the next nine years.
The determination of the fair value of share-based payment awards is affected by the company’s stock price. Since inception and until November 7, 2007, since the company was not publicly traded, the company considered the sales price of common stock in private placements to unrelated third parties as a measure of the fair value of its common stock. The company started trading on November 8, 2007 therefore after such date it will use the market price of its common stock to determine fair value of share-based payment awards.
SFAS 123(R) also requires companies to utilize an estimated forfeiture rate when calculating the expense for the period, whereas, SFAS 123 permitted companies to record forfeitures based on actual forfeitures, which was our historical policy under SFAS 123. As a result, we applied an estimated forfeiture rate of 15% and 0% during 2007 and 2006 respectively, in determining the expense recorded in the accompanying consolidated statement of income. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Stock-based compensation expense recognized in our financial statements in 2007 and thereafter is based on awards that are ultimately expected to vest. We evaluate the assumptions used to value our awards on a quarterly basis and if factors change and we employ different assumptions, stock-based compensation expense may differ significantly from what we have recorded in the past. If there are any modifications or cancellations of the underlying unvested securities, we may be required to accelerate, increase or cancel any remaining unearned stock-based compensation expense.
On November 10, 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position SFAS 123R-3 “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.” The company has elected to adopt the alternative transition method provided the FASB Staff Position for calculating the tax effects (if any) of stock-based compensation expense pursuant to SFAS 123R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool related to the tax effects of employee stock-based compensation, and to determine the subsequent impact to the additional paid-in capital pool and the consolidated statements of operations and cash flows of the tax effects of employee stock-based compensation awards that are outstanding upon adoption of SFAS 123R.
See Note 6 for a summary of the restricted stock and stock option activity under our stock-based employee compensation plan for the year ended December 31, 2007 and 2006.
Earnings per Common Share
Basic net income (loss) per common share is calculated using the weighted-average number of common shares outstanding during the period less the weighted-average shares subject to repurchase. Diluted income (loss) per common share gives effect to dilutive common stock subject to repurchase, stock options and warrants (calculated based on the treasury stock method), and convertible debt (calculated using an as-if-converted method). We compute basic earnings per share by dividing net income (loss) for the period by the weighted average number of shares of common stock outstanding during the period. For purposes of calculating diluted earnings per share, we consider our shares issuable in connection with 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. For the year ended December 31, 2007, we excluded 9,503,690 anti-dilutive shares resulting from conversion of debentures and exercise of stock options and warrants, and for the year ended December 31, 2006 we excluded 7,344,145 anti-dilutive shares resulting from conversion of debentures and exercise of stock options.
Other Comprehensive Net Loss
The comprehensive net loss for the years ended December 31, 2007 and 2006 does not differ from the reported loss.
Impairment of Intangible Assets:
The company evaluates the recoverability of its long-lived assets in accordance with Statement of Financial Accounting Standards No. 144 (“SFAS No. 144”), Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 requires the recognition of impairment of long-lived assets in the event the net book value of such assets exceeds the estimated future undiscounted cash flows attributable to such assets. If impairment is indicated, the asset is written down to its estimated fair value based on a discounted cash flow analysis. The company reviews long-lived assets for impairment annually 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. At December 31, 2007 the company determined that its long-lived assets are recoverable.
Income Taxes
We account for income taxes in accordance SFAS No. 109, “Accounting for Income Taxes”. Under SFAS No. 109, deferred tax assets and liabilities are determined based on differences between the financial reporting and tax reporting bases of assets and liabilities and are measured by applying the enacted tax rates and laws to taxable years in which the differences are expected to reverse. We recognize a deferred tax asset for the tax benefit of net operating loss carry forwards when it is more likely than not that the tax benefits will be realized and reduce the deferred tax asset with a valuation reserve when it is more likely than not that some portion of the tax benefits will not be realized.
Fair Value of Financial Instruments
The company’s financial instruments are cash and cash equivalents, accounts receivable, accounts payable, convertible debentures and notes due from related party. The recorded values of cash and cash equivalents, accounts receivable, accounts payable and notes due from related party approximate their fair values based on their short-term nature. The carrying value of the convertible debentures on the balance sheet at December 31, 2007 approximates fair value as the term approximate those currently available for similar instruments.
Recent Accounting Pronouncements
In September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 establishes a common definition of fair value to be used whenever GAAP requires (or permits) assets or liabilities to be measured at fair value, and does not expand the use of fair value in any new circumstances. It also requires expanded disclosure about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. In addition, in February 2007, the FASB issued FAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115” (“FAS 159”). FAS 159 expands the use of fair value accounting but does not affect existing standards that require assets or liabilities to be carried at fair value. Under FAS 159, a company may elect to use fair value to measure most financial assets and liabilities and any changes in fair value are recognized in earnings. The fair value election is irrevocable and generally made on an instrument-by-instrument basis, even if a company has similar instruments that it elects not to measure based on fair value. Both FAS 157 and FAS 159 will be effective for the company on January 1, 2008. On February 12, 2008, the FASB issued proposed FASB Staff Position No. FAS No. 157-2, “Effective Date of FASB Statement No. 157” which defers the effective date for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually) to fiscal years beginning after November 15, 2008. The company does not expect the adoption of FAS 157 and FAS 159 will have a material impact on its consolidated financial statements in 2008.
In December 2007, the FASB issued FAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of Accounting Research Bulletin No. 51” (“FAS 160”). FAS 160 clarifies the classification in a company’s consolidated balance sheet and the accounting for and disclosure of transactions between the company and holders of noncontrolling interests. FAS 160 is effective for the company January 1, 2009. Early adoption is not permitted. The company does not expect the adoption of FAS 160 to have a material impact on its consolidated financial statements.
Note 3 - Property plant and equipment:
Property and equipment consists of the following as of December 31, 2007 and 2006:
Depreciation of property and equipment totaled $363,233 and $316,515 for the years ended December 31, 2007 and 2006.
Note 4 - Short-term notes payable:
On December 31, 2005 the company had short-term notes payable to stockholders of $1,250,000. The notes were due upon the earlier of either written demand for payment or consummation of any financing by the company. During the year ended December 31, 2006, the company converted $700,000 of the short-term notes to 1,000,000 shares of common stock. In addition, the company converted the remaining $550,000 of short-term notes and $100,000 of accrued interest related to the notes to convertible debentures (see Note 5).
Note 5 - 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 5 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, 2007 the conversion price of the debenture has not been adjusted. As of December 31, 2007, there were 7,172,621 shares of common stock issuable upon conversion of our outstanding convertible debentures. On October 2, 2007, a holder of the company’s 8% Convertible Debenture elected to convert $50,000 of the outstanding principal amount of the debenture into 59,524 shares of common stock.
Note 6 - Stockholders’ equity:
Common Stock
In 2006 the company raised funds through a private placement of common stock and warrants to a limited number of accredited investors. In connection with the private placement the company sold an aggregate of 901,700 shares of common stock at a purchase price of $0.70 per share, resulting in net cash proceeds or $572,166. In 2007 the company raised additional funds through a private placement of common stock to a limited number of accredited investors. In connection with the private placement the company sold an aggregate of 5,692,150 shares of common stock at a purchase price of $0.70 per share, resulting in net cash proceeds of $3,892,218. The holders of common stock have the right to vote their interest on a per share basis. As of December 31, 2007, there were 32,805,924 shares of common stock outstanding.
The company has also issued redeemable common stock. The holders of the shares of the redeemable common stock may elect to require the company to redeem their shares, if certain obligations are not met in accordance with the terms of the redemption agreement. Due to the redemption features, the common stock is classified separately in the accompanying balance sheet of December 31, 2006. At December 31, 2006 the company had outstanding 450,000 shares of common stock subject to redemption at $0.70 per share with various expiration dates. On November 8, 2007, the company common stock started trading on the Over-The-Counter Bulletin Board, therefore the company’s obligations to the redeemable common stockholders were met and the aforementioned securities were no longer considered redeemable. The company reclassified the redeemable common stock into equity.
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. As of December 31, 2007 there were 1,990,000 fully vested exercisable warrants outstanding at $0.70 per share, which expire between 2008 and 2010.
Stock Awards
During the year ended December 31, 2006, the company issued 876,800 shares of common stock to Tecogen employees and consultants (Note 8). The shares of common stock were fully vested and did not contain any restrictive provisions. The company accounts for stock based awards issued to non-employees in accordance with EITF 96-18, Accounting for Equity Instruments that are Issued to Other Than Employees for Acquiring or in Conjunction with Selling, Goods or Services. The common stock was issued at $0.001 per share when the fair value was estimated to be $0.70 per share. The company recorded an expense of $612,883 in 2006, related to such awards.
Stock Based Compensation
In 2003, the company adopted the American Distributed Generation, Inc. stock incentive 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.
The maximum number of shares of stock allowable for issuance under the Plan is 4,000,000 shares of common stock, including 1,189,500 restricted shares as of December 31, 2007. Stock options, are exercisable within a five-year or ten-year period from the date of grant and vest based upon the terms within the individual option grants, usually over a two- or four-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 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 Plan was 189,500 at December 31, 2007.
We account for stock awards issued to employees in accordance with FASB Statement No. 123 (Revised 2004), Share-Based Payment (SFAS 123(R)) and have adopted the prospective application transition method. During the years ended December 31, 2007 and December 31, 2006, the company recognized employee non-cash compensation expense of $330,335 and $664,134, respectively, related to the issuance of stock options and restricted stock. At December 31, 2007 there were 948,875 unvested shares of restricted stock outstanding. At December 31, 2007, the total compensation cost related to unvested restricted stock awards not yet recognized is $834,538. This amount will be recognized over the next five years. In 2007 the company granted nonqualified options to purchase 1,156,000 shares of the common stock to 7 employees at $0.90 per share. Of those stock options 1,130,000 have a vesting schedule of 10 years and 26,000 stock options have a vesting schedule of 4 years. Stock option activity for the year ended December 31, 2007 and 2006 was as follows:
The aggregate intrinsic value of options outstanding as of December 31, 2007 is calculated as the difference between the exercise price of the underlying options and the price of the company’s common stock for options that were in-the-money as of that date. Options that were not in-the-money as of that date, and therefore have a negative intrinsic value, have been excluded from this amount.
In 2006, the company made restricted stock grants to 9 employees by permitting them to purchase an aggregate of 287,500 shares of common stock at a price of $0.001 per share. Out of those shares, 257,500 have a vesting schedule of 25% 180 days after the company’s Initial Public Offering and then 25% on each subsequent anniversary thereafter, and 30,000 shares have a vesting schedule of 100% one year after the Initial Public Offering.
In 2007, the company made restricted stock grants to employees, board members and consultants by permitting them to purchase an aggregate of 737,000 shares of common stock at a price of $0.001 per share. Out of those shares, 681,000 have a vesting schedule of 25% one year after the company’s Initial Public Offering and then 25% on each subsequent anniversary thereafter, and 56,000 shares vest 180 days after the company’s Initial Public Offering together with certain gross profit goals as described in the agreement.
Restricted stock activity for the year ended December 31, 2007 and 2006 was as follows:
Note 7 - Employee benefit plan:
The company has a defined contribution retirement plan (the “Plan”) which qualifies under Section 401(k) of the Internal Revenue Code (“IRC”). Under the 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 $27,138 and $16,273 to the Plan for the years ended December 31, 2007 and 2006, respectively.
Note 8 - Related party:
The company purchases the majority of its cogeneration units from 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, 2009.
In January 2007, the company entered into a Facilities, Support Services and Business 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 (Note 10).
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.
During the year ended December 31, 2006, the company issued 876,800 shares of common stock to Tecogen employees. The shares of common stock were fully vested and did not contain any restrictive provisions. The common stock was issued at a fair value of $0.70 per share (Note 6).
On February 15, 2007, the company loaned the minority interest partner in the NY LLC $20,000 by signing in 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 minority interest 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. All notes are classified in the Due from related party-long term account in the accompanying balance sheet and are secured by the partner’s minority interest. On October 11, 2007 we extended to our minority interest partner a line of credit not to exceed $500,000. At December 31, 2007, $403,810 was outstanding and due to the company.
Note 9 - Income taxes:
A reconciliation of federal statutory income tax provision to the company’s actual provision for the years ended December 31, 2007 and December 31, 2006 respectively are as follows:
The components of net deferred tax assets recognized in the accompanying balance sheets at December 31, 2007 and December 31, 2006 respectively are as follows:
As of December 2007, the company has federal and state loss carryforwards of approximately $5,797,000 and $4,249,000, respectively, which may be used to offset future federal and state taxable income, expiring at various dates through 2027.
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 FIN 48 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, 2007.
Note 10 - Commitments and contingencies:
In January 2007, the company entered into a Facilities, Support Services and Business 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 2007 business agreement we revised the rent allocation whereby Tecogen provides the company with office space and utilities at a flat rate of $2,294 per month. 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.